Patent Publication Number: US-9896899-B2

Title: Downhole tool with rounded mandrel

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application claims the benefit under 35 U.S.C. § 119(e) of U.S. Provisional Patent Application Ser. No. 61/865,064, filed on Aug. 12, 2013, the entirety of which being incorporated herein by reference for all purposes. 
    
    
     STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
     Not applicable. 
     BACKGROUND 
     Field of the Disclosure 
     This disclosure generally relates to tools used in oil and gas wellbores. More specifically, the disclosure relates to downhole tools that may be run into a wellbore and useable for wellbore isolation, and systems and methods pertaining to the same. In particular embodiments, the tool may be a composite plug made of drillable materials. 
     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&#39;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 Facing operations. 
     Fracing is common in the industry and growing in popularity and general acceptance, and includes the use of a plug set in the wellbore below or beyond the respective target zone, followed by pumping or injecting high pressure frac fluid into the zone. The frac operation results in fractures or “cracks” in the formation that allow hydrocarbons to be more readily extracted and produced by an operator, and may be repeated as desired or necessary until all target zones are fractured. 
     A frac plug serves the purpose of isolating the target zone for the frac operation. Such a tool is usually constructed of durable metals, with a sealing element being a compressible material that may also expand radially outward to engage the tubular and seal off a section of the wellbore and thus allow an operator to control the passage or flow of fluids. For example, by forming a pressure seal in the wellbore and/or with the tubular, the frac plug allows pressurized fluids or solids to treat the target zone or isolated portion of the formation. 
       FIG. 1A  illustrates a conventional plugging system  100  that includes use of a downhole tool  102  used for plugging a section of the wellbore  106  drilled into formation  110 . The tool or plug  102  may be lowered into the wellbore  106  by way of workstring  105  (e.g., e-line, wireline, coiled tubing, etc.) and/or with setting tool  112 , as applicable. The tool  102  generally includes a body  103  with a compressible seal member  122  to seal the tool  102  against an inner surface  107  of a surrounding tubular, such as casing  108 . The tool  102  may include the seal member  122  disposed between one or more slips  109 ,  111  that are used to help retain the tool  102  in place. 
     In operation, forces (usually axial relative to the wellbore  106 ) are applied to the slip(s)  109 ,  111  and the body  103 . As the setting sequence progresses, slip  109  moves in relation to the body  103  and slip  111 , the seal member  122  is actuated, and the slips  109 ,  111  are driven against corresponding conical surfaces  104 . This movement axially compresses and/or radially expands the compressible member  122 , and the slips  109 ,  111 , which results in these components being urged outward from the tool  102  to contact the inner wall  107 . In this manner, the tool  102  provides a seal expected to prevent transfer of fluids from one section  113  of the wellbore across or through the tool  102  to another section  115  (or vice versa, etc.), or to the surface. Tool  102  may also include an interior passage (not shown) that allows fluid communication between section  113  and section  115  when desired by the user. Oftentimes multiple sections are isolated by way of one or more additional plugs (e.g.,  102 A). 
     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&#39;s components. For example, when the sealing element is placed under compression, its surfaces do not always seal properly with surrounding components (e.g., cones, etc.). 
     Downhole tools are often activated with a drop ball that is flowed from the surface down to the tool, whereby the pressure of the fluid must be enough to overcome the static pressure and buoyant forces of the wellbore fluid(s) in order for the ball to reach the tool. Frac fluid is also highly pressurized in order to not only transport the fluid into and through the wellbore, but also extend into the formation in order to cause fracture. Accordingly, a downhole tool must be able to withstand these additional higher pressures. 
     In addition, downhole tool technology has evolved from tools historically used in vertical orientation, which has resulted in new problems. For example, when used in a general horizontal orientation downhole tools, as well as the work string, encounter frictional resistance and gravitational force not otherwise present in a vertical orientation. In some instances, the downhole tool and/or the work string will be off-center, and even contact the surrounding tubular (e.g., casing), for thousands of feet. 
     Referring briefly to  FIGS. 1B-1E , pitfalls associated with tool technology originally intended for vertical use, but ultimately used horizontally, may be seen. That is, in the prior art downhole tool  102  was conventionally used in a vertical orientation illustrated by  FIG. 1B . This view is a partial component view of an end  114 A of a mandrel  114  disposed within tool  102  and surrounded by a setting sleeve  154 , as would be understood and apparent to one of skill in the art. It should be appreciated that other tool and system components exist (e.g., workstring  112 , etc.) and are in place, and the  FIGS. 1B-1D  are for simplified illustrative purposes. 
     When the tool  102  is run into the well  106  and through tubular  108 , the tool  102  will encounter various forces, including downward force F1, which may be a net force of pressure, gravity, etc. Tool area A1, resembling a circumferential contact region or near-contact region of the mandrel end  114 A and the setting sleeve  154  incurs little to no portion of the force F1 because the area is largely parallel to the vector. The conventional tool  102  incorporates the simplest component parts that are cheapest and easily fabricated, which includes machined, linear portions. The tool  102  is easily positionable, and ultimately set, so that a largely concentric and equal annulus is formed between the tool  102  and the casing  108  (see, e.g., annulus arrows  199 ). 
     While this type of configuration is sufficient for vertical orientation, very distinct and different problems are encountered when the tool  102  is used in horizontal service.  FIG. 1C  readily illustrates how the tool  102 , workstring  112 , etc. incur various downward forces F1, resulting in the tool  102 , etc. moving along the bottom portion of the casing  108 . When the setting sequence begins, radial outward movement of slips and compressible member (not shown here) will ultimately urge the tool  102  toward a central position, as illustrated in  FIG. 1D . However, when this occurs the tool  102 , by way of, for example, area A1 experiences incredible downward forces F2. This happens because as the tool  102  begins to centralize, the workstring  112  in some manner is also urged to centralize. Thus, the weight of the workstring  112  will be transferred into the tool  102 , including at a point P1 of the mandrel  114 , resulting in a fracture point P1, as shown in  FIG. 1E . 
     The most apparent solution for one of skill would be to increase clearance between the mandrel end and the setting sleeve; however, debris, sand, etc. may fill into this clearance, and then there is ultimately no clearance, resulting in a pseudo tolerance fit, as well as other problems caused by the debris that impairs the function of the tool  102 . 
     Accordingly, there are needs in the art for novel systems and methods for isolating wellbores in a viable and economical fashion. There is a great need in the art for downhole plugging tools that form a reliable and resilient seal against a surrounding tubular. There is also a need for a downhole tool made substantially of a drillable material that is easier and faster to drill. 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. There is a great need in the art for a downhole tool that overcomes problems encountered in a horizontal orientation. 
     SUMMARY 
     Embodiments of the disclosure pertain to a downhole tool useable for isolating sections of a wellbore that may include a mandrel further comprising a first end and a second end. The second end may include a first outer surface area and a second outer surface area. The second outer surface area may be in contact with a setting sleeve prior to setting of the tool. At least part of the first outer surface area may not be in contact with the setting sleeve prior to setting of the tool. In aspects, the first outer surface area may include at least one rounded segment comprising a radius of curvature in longitudinal cross-section. 
     The downhole tool may include a composite member disposed about the mandrel. The downhole tool may include a composite slip. The composite member may be made of a first material and include a top and a bottom. There may be at least one spiral formed or shaped groove between about the bottom to about the top. The mandrel may include composite material. 
     The downhole tool may include a metal slip disposed about the mandrel. The metal slip may include a one-piece circular slip body; and a face comprising a set of mating holes. The tool may have a lower sleeve that may include a set of stabilizer pins configured to engage the set of mating holes. The stabilizer pins of the set may be disposed in a symmetrical manner with respect to each other. 
     The first outer surface area may include at least one rounded segment. The first outer surface area may include at least one non-linear segment. The first outer surface area may include at least one linear segment. The first outer surface area may include combinations thereof. 
     Other embodiments of the disclosure pertain to a downhole tool useable for isolating sections of a wellbore that may include a composite mandrel having a distal end and a proximate end. The distal end may be configured with a set of rounded threads. The proximate end may be configured with at least one tapered surface. In aspects, the proximate end may be configured with an outer surface area with at least one rounded segment comprising a radius of curvature in longitudinal cross-section. There may be a composite member disposed about the mandrel. The composite member may be made of a first material and include a first portion and a second portion. The tool may include a slip disposed about the mandrel. The set of rounded threads may be disposed along an external mandrel surface at the distal end. The composite mandrel may be made of or include filament wound material. 
     The composite mandrel may be coupled with an adapter configured with corresponding threads that mate with shear threads disposed in the proximate end. In aspects, application of a load to the mandrel may be sufficient enough to shear the second set of threads or shear threads. 
     Other embodiments of the disclosure pertain to a downhole tool for isolating zones in a well that may include a composite mandrel that further includes a proximate end further comprising a first set of threads configured for coupling to a lower sleeve. There may be a distal end further having a second set of threads configured for mating with a setting tool. The proximate end may be configured with a surface length greater than a run-in contact length between the proximate end and a setting sleeve. There may be a composite member disposed around the composite mandrel. The composite member may include a deformable portion having one or more grooves disposed therein. 
     The composite mandrel may include a flow path formed therein. The first set of threads may be shear threads. The shear threads may be disposed on an inner surface of the composite mandrel. 
     The tool may further include a one-piece metal slip formed of or from hardened cast iron. The second set of threads may include round threads. The downhole tool may be selected from the group consisting of a frac plug, a bridge plug, a bi-directional bridge plug, and a kill plug. 
     The composite slip may include a circular slip body with at least partial connectivity therearound. The composite slip may include at least one groove disposed therein. The one piece metal slip may include a slip body; an outer surface comprising gripping elements; and an inner surface configured for receiving the composite mandrel. The slip body may include at least one hole formed therein. 
     The composite member may be disposed proximate to a sealing element. The tool may include a composite one-piece slip disposed about the composite mandrel. The composite slip may be adjacent a cone. The sleeve may be disposed around the composite mandrel. The sleeve may be proximate a tapered end of the metal slip. 
     Yet other embodiments of the disclosure pertain to a mandrel for a downhole tool. The mandrel may include a body having a proximate end having shear threads and a first outer diameter, and a distal end having rounded threads and a second outer diameter. The mandrel may be made from composite filament wound material. The first outer diameter may be larger than the second outer diameter. The mandrel may include a transition region formed on the body between the proximate end and the distal end. The mandrel may include an outer surface along the body. There may be a circumferential taper formed on the outer surface near the proximate end. The proximate end may include a ball seat configured to receive a drop ball. 
     The transition region may be configured to distribute forces as a result of compression between the mandrel and the bearing plate. The transition region may be configured to distribute shear forces along an angle to an axis of the mandrel. The outer surface along the body may include one of a rounded surface, a linear surface, or a combination(s) thereof. 
     The proximate end may include a first length extending about from the transition region to a furthest proximate end point. The proximate end may include a second length configured for engagement with a setting sleeve. 
     The method may include the downhole tool configured in any manner as disclosed herein. 
     These and other embodiments, features and advantages will be apparent in the following detailed description and drawings. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWING 
       For a more detailed description of an embodiment of the present disclosure, reference will now be made to the accompanying drawing, wherein: 
         FIG. 1A  is a side view of a process diagram of a conventional plugging system; 
         FIG. 1B  shows a side view of a vertical oriented plugging system; 
         FIG. 1C  shows a side view of a horizontal oriented plugging system; 
         FIG. 1D  shows a side view of a horizontal oriented plugging system during setting; 
         FIG. 1E  shows a side view of a fractured plug during setting; 
         FIGS. 2A-2B  each show an isometric view of a system having a downhole tool, according to embodiments of the disclosure; 
         FIG. 2C  shows a side longitudinal view of a downhole tool according to embodiments of the disclosure; 
         FIG. 2D  shows a longitudinal cross-sectional view of a downhole tool according to embodiments of the disclosure; 
         FIG. 2E  shows an isometric component break-out view of a downhole tool according to embodiments of the disclosure; 
         FIG. 3A  shows an isometric view of a mandrel usable with a downhole tool according to embodiments of the disclosure; 
         FIG. 3B  shows a longitudinal cross-sectional view of a mandrel usable with a downhole tool according to embodiments of the disclosure; 
         FIG. 3C  shows a longitudinal cross-sectional view of an end of a mandrel usable with a downhole tool according to embodiments of the disclosure; 
         FIG. 3D  shows a longitudinal cross-sectional view of an end of a mandrel engaged with a sleeve according to embodiments of the disclosure; 
         FIG. 4A  shows a longitudinal cross-sectional view of a seal element usable with a downhole tool according to embodiments of the disclosure; 
         FIG. 4B  shows an isometric view of a seal element usable with a downhole tool according to embodiments of the disclosure; 
         FIG. 5A  shows an isometric view of one or more slips usable with a downhole tool according to embodiments of the disclosure; 
         FIG. 5B  shows a lateral view of one or more slips usable with a downhole tool according to embodiments of the disclosure; 
         FIG. 5C  shows a longitudinal cross-sectional view of one or more slips usable with a downhole tool according to embodiments of the disclosure; 
         FIG. 5D  shows an isometric view of a metal slip usable with a downhole tool according to embodiments of the disclosure; 
         FIG. 5E  shows a lateral view of a metal slip usable with a downhole tool according to embodiments of the disclosure; 
         FIG. 5F  shows a longitudinal cross-sectional view of a metal slip usable with a downhole tool according to embodiments of the disclosure; 
         FIG. 5G  shows an isometric view of a metal slip without buoyant material holes usable with a downhole tool according to embodiments of the disclosure; 
         FIG. 6A  shows an isometric view of a composite deformable member usable with a downhole tool according to embodiments of the disclosure; 
         FIG. 6B  shows a longitudinal cross-sectional view of a composite deformable member usable with a downhole tool according to embodiments of the disclosure; 
         FIG. 6C  shows a close-up longitudinal cross-sectional view of a composite deformable member usable with a downhole tool according to embodiments of the disclosure; 
         FIG. 6D  shows a side longitudinal view of a composite deformable member usable with a downhole tool according to embodiments of the disclosure; 
         FIG. 6E  shows a longitudinal cross-sectional view of a composite deformable member usable with a downhole tool according to embodiments of the disclosure; 
         FIG. 6F  shows an underside isometric view of a composite deformable member usable with a downhole tool according to embodiments of the disclosure; 
         FIG. 7A  shows an isometric view of a bearing plate usable with a downhole tool according to embodiments of the disclosure; 
         FIG. 7B  shows a longitudinal cross-sectional view of a bearing plate usable with a downhole tool according to embodiments of the disclosure; 
         FIG. 8A  shows an underside isometric view of a cone usable with a downhole tool according to embodiments of the disclosure; 
         FIG. 8B  shows a longitudinal cross-sectional view of a cone usable with a downhole tool according to embodiments of the disclosure; 
         FIGS. 9A and 9B  show an isometric view, and a longitudinal cross-sectional view, respectively, of a lower sleeve usable with a downhole tool according to embodiments of the disclosure; 
         FIG. 9C  shows an isometric view of a lower sleeve configured with stabilizer pin inserts according to embodiments of the disclosure; 
         FIG. 9D  shows a lateral view of the lower sleeve of  FIG. 9C  according to embodiments of the disclosure; 
         FIG. 9E  shows a longitudinal cross-sectional view of the lower sleeve of  FIG. 9C  according to embodiments of the disclosure; 
         FIG. 10A  shows an isometric view of a ball seat usable with a downhole tool according to embodiments of the disclosure; 
         FIG. 10B  shows a longitudinal cross-sectional view of a ball seat usable with a downhole tool according to embodiments of the disclosure; 
         FIG. 11A  shows a side longitudinal view of a downhole tool configured with a plurality of composite members and metal slips according to embodiments of the disclosure; 
         FIG. 11B  shows a longitudinal cross-section view of a downhole tool configured with a plurality of composite members and metal slips according to embodiments of the disclosure; 
         FIGS. 12A and 12B  show longitudinal side views of an encapsulated downhole tool according to embodiments of the disclosure; 
         FIG. 13A  shows an underside isometric view of an insert(s) configured with a hole usable with a slip(s) according to embodiments of the disclosure; 
         FIGS. 13B and 13C  show underside isometric views of an insert(s) usable with a slip(s) according to embodiments of the disclosure; 
         FIG. 13D  shows a topside isometric view of an insert(s) usable with a slip(s) according to embodiments of the disclosure; 
         FIGS. 14A and 14B  show longitudinal cross-section views of various configurations of a downhole tool according to embodiments of the disclosure; 
         FIG. 15A  shows a longitudinal cross-sectional view of a mandrel having a reduced contact surface mandrel end according to embodiments of the disclosure; 
         FIG. 15B  shows a longitudinal cross-sectional view of another example of a mandrel having a reduced contact surface mandrel end according to embodiments of the disclosure; 
         FIG. 15C  shows a longitudinal cross-sectional view of a mandrel having a rounded contact surface mandrel end according to embodiments of the disclosure; 
         FIG. 15D  shows a longitudinal cross-sectional view of another example of a mandrel having a rounded contact surface mandrel end according to embodiments of the disclosure; 
         FIG. 15E  a longitudinal cross-sectional view of a mandrel having a rounded reduced contact surface mandrel end according to embodiments of the disclosure; 
         FIG. 16A  shows an isometric view of a metal slip configured with one or more mating holes according to embodiments of the disclosure; 
         FIG. 16B  shows a lateral view of the metal slip of  FIG. 16A  according to embodiments of the disclosure; 
         FIG. 16C  shows a longitudinal cross-sectional view of the metal slip of  FIG. 16A  according to embodiments of the disclosure; 
         FIG. 16D  shows a rotated longitudinal cross-sectional view of the metal slip of viewed in  FIG. 16C  according to embodiments of the disclosure; 
         FIG. 17A  shows a longitudinal side view of a system having a downhole tool in a pre-set to set position according to embodiments of the disclosure; 
         FIG. 17B  shows a longitudinal side view of a system having a downhole tool moving from a pre-set to set position according to embodiments of the disclosure; and 
         FIG. 17C  shows a longitudinal side view of a system having a downhole in a set position according to embodiments of the disclosure. 
     
    
    
     DETAILED DESCRIPTION 
     In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . ”. Herein disclosed are novel apparatuses, systems, and methods that pertain to downhole tools usable for wellbore operations, details of which are described herein. 
     Referring now to  FIGS. 2A and 2B  together, isometric views of a system  200  having a downhole tool  202  illustrative of embodiments disclosed herein, are shown.  FIG. 2B  depicts a wellbore  206  formed in a subterranean formation  210  with a tubular  208  disposed therein. In an embodiment, the tubular  208  may be casing (e.g., casing, hung casing, casing string, etc.) (which may be cemented). A workstring  212  (which may include a part  217  of a setting tool coupled with adapter  252 ) may be used to position or run the downhole tool  202  into and through the wellbore  206  to a desired location. 
     In accordance with embodiments of the disclosure, the tool  202  may be configured as a plugging tool, which may be set within the tubular  208  in such a manner that the tool  202  forms a fluid-tight seal against the inner surface  207  of the tubular  208 . In an embodiment, the downhole tool  202  may be configured as a bridge plug, whereby flow from one section of the wellbore  213  to another (e.g., above and below the tool  202 ) is controlled. In other embodiments, the downhole tool  202  may be configured as a frac plug, where flow into one section  213  of the wellbore  206  may be blocked and otherwise diverted into the surrounding formation or reservoir  210 . 
     In yet other embodiments, the downhole tool  202  may also be configured as a ball drop tool. In this aspect, a ball may be dropped into the wellbore  206  and flowed into the tool  202  and come to rest in a corresponding ball seat at the end of the mandrel  214 . The seating of the ball may provide a seal within the tool  202  resulting in a plugged condition, whereby a pressure differential across the tool  202  may result. The ball seat may include a radius or curvature. 
     In other embodiments, the downhole tool  202  may be a ball check plug, whereby the tool  202  is configured with a ball already in place when the tool  202  runs into the wellbore. The tool  202  may then act as a check valve, and provide one-way flow capability. Fluid may be directed from the wellbore  206  to the formation with any of these configurations. 
     Once the tool  202  reaches the set position within the tubular, the setting mechanism or workstring  212  may be detached from the tool  202  by various methods, resulting in the tool  202  left in the surrounding tubular and one or more sections of the wellbore isolated. In an embodiment, once the tool  202  is set, tension may be applied to the adapter  252  until the threaded connection between the adapter  252  and the mandrel  214  is broken. For example, the mating threads on the adapter  252  and the mandrel  214  ( 256  and  216 , respectively as shown in  FIG. 2D ) may be designed to shear, and thus may be pulled and sheared accordingly in a manner known in the art. The amount of load applied to the adapter  252  may be in the range of about, for example, 20,000 to 40,000 pounds force. In other applications, the load may be in the range of less than about 10,000 pounds force. 
     Accordingly, the adapter  252  may separate or detach from the mandrel  214 , resulting in the workstring  212  being able to separate from the tool  202 , which may be at a predetermined moment. The loads provided herein are non-limiting and are merely exemplary. The setting force may be determined by specifically designing the interacting surfaces of the tool and the respective tool surface angles. The tool  202  may also be configured with a predetermined failure point (not shown) configured to fail or break. For example, the failure point may break at a predetermined axial force greater than the force required to set the tool but less than the force required to part the body of the tool. 
     Operation of the downhole tool  202  may allow for fast run in of the tool  202  to isolate one or more sections of the wellbore  206 , as well as quick and simple drill-through to destroy or remove the tool  202 . Drill-through of the tool  202  may be facilitated by components and subcomponents of tool  202  made of drillable material that is less damaging to a drill bit than those found in conventional plugs. In an embodiment, the downhole tool  202  and/or its components may be a drillable tool made from drillable composite material(s), such as glass fiber/epoxy, carbon fiber/epoxy, glass fiber/PEEK, carbon fiber/PEEK, etc. Other resins may include phenolic, polyamide, etc. All mating surfaces of the downhole tool  202  may be configured with an angle, such that corresponding components may be placed under compression instead of shear. 
     Referring now to  FIGS. 2C-2E  together, a longitudinal view, a longitudinal cross-sectional view, and an isometric component break-out view, respectively, of downhole tool  202  useable with system ( 200 ,  FIG. 2A ) and illustrative of embodiments disclosed herein, are shown. The downhole tool  202  may include a mandrel  214  that extends through the tool (or tool body)  202 . The mandrel  214  may be a solid body. In other aspects, the mandrel  214  may include a flowpath or bore  250  formed therein (e.g., an axial bore). The bore  250  may extend partially or for a short distance through the mandrel  214 , as shown in  FIG. 2E . Alternatively, the bore  250  may extend through the entire mandrel  214 , with an opening at its proximate end  248  and oppositely at its distal end  246  (near downhole end of the tool  202 ), as illustrated by  FIG. 2D . 
     The presence of the bore  250  or other flowpath through the mandrel  214  may indirectly be dictated by operating conditions. That is, in most instances the tool  202  may be large enough in diameter (e.g., 4¾ inches) that the bore  250  may be correspondingly large enough (e.g., 1¼ inches) so that debris and junk can pass or flow through the bore  250  without plugging concerns. However, with the use of a smaller diameter tool  202 , the size of the bore  250  may need to be correspondingly smaller, which may result in the tool  202  being prone to plugging. Accordingly, the mandrel may be made solid to alleviate the potential of plugging within the tool  202 . 
     With the presence of the bore  250 , the mandrel  214  may have an inner bore surface  247 , which may include one or more threaded surfaces formed thereon. As such, there may be a first set of threads  216  configured for coupling the mandrel  214  with corresponding threads  256  of a setting adapter  252 . 
     The coupling of the threads, which may be shear threads, may facilitate detachable connection of the tool  202  and the setting adapter  252  and/or workstring ( 212 ,  FIG. 2B ) at the threads. It is within the scope of the disclosure that the tool  202  may also have one or more predetermined failure points (not shown) configured to fail or break separately from any threaded connection. The failure point may fail or shear at a predetermined axial force greater than the force required to set the tool  202 . 
     The adapter  252  may include a stud  253  configured with the threads  256  thereon. In an embodiment, the stud  253  has external (male) threads  256  and the mandrel  214  has internal (female) threads; however, type or configuration of threads is not meant to be limited, and could be, for example, a vice versa female-male connection, respectively. 
     The downhole tool  202  may be run into wellbore ( 206 ,  FIG. 2A ) to a desired depth or position by way of the workstring ( 212 ,  FIG. 2A ) that may be configured with the setting device or mechanism. The workstring  212  and setting sleeve  254  may be part of the plugging tool system  200  utilized to run the downhole tool  202  into the wellbore, and activate the tool  202  to move from an unset to set position. The set position may include seal element  222  and/or slips  234 ,  242  engaged with the tubular ( 208 ,  FIG. 2B ). In an embodiment, the setting sleeve  254  (that may be configured as part of the setting mechanism or workstring) may be utilized to force or urge compression of the seal element  222 , as well as swelling of the seal element  222  into sealing engagement with the surrounding tubular. 
     The setting device(s) and components of the downhole tool  202  may be coupled with, and axially and/or longitudinally movable along mandrel  214 . When the setting sequence begins, the mandrel  214  may be pulled into tension while the setting sleeve  254  remains stationary. The lower sleeve  260  may be pulled as well because of its attachment to the mandrel  214  by virtue of the coupling of threads  218  and threads  262 . As shown in the embodiment of  FIGS. 2C and 2D , the lower sleeve  260  and the mandrel  214  may have matched or aligned holes  281 A and  281 B, respectively, whereby one or more anchor pins  211  or the like may be disposed or securely positioned therein. In embodiments, brass set screws may be used. Pins (or screws, etc.)  211  may prevent shearing or spin-off during drilling or run-in. 
     As the lower sleeve  260  is pulled in the direction of Arrow A, the components disposed about mandrel  214  between the lower sleeve  260  and the setting sleeve  254  may begin to compress against one another. This force and resultant movement causes compression and expansion of seal element  222 . The lower sleeve  260  may also have an angled sleeve end  263  in engagement with the slip  234 , and as the lower sleeve  260  is pulled further in the direction of Arrow A, the end  263  compresses against the slip  234 . As a result, slip(s)  234  may move along a tapered or angled surface  228  of a composite member  220 , and eventually radially outward into engagement with the surrounding tubular ( 208 ,  FIG. 2B ). 
     Serrated outer surfaces or teeth  298  of the slip(s)  234  may be configured such that the surfaces  298  prevent the slip  234  (or tool) from moving (e.g., axially or longitudinally) within the surrounding tubular, whereas otherwise the tool  202  may inadvertently release or move from its position. Although slip  234  is illustrated with teeth  298 , it is within the scope of the disclosure that slip  234  may be configured with other gripping features, such as buttons or inserts (e.g.,  FIGS. 13A-13D ). 
     Initially, the seal element  222  may swell into contact with the tubular, followed by further tension in the tool  202  that may result in the seal element  222  and composite member  220  being compressed together, such that surface  289  acts on the interior surface  288 . The ability to “flower”, unwind, and/or expand may allow the composite member  220  to extend completely into engagement with the inner surface of the surrounding tubular. 
     Additional tension or load may be applied to the tool  202  that results in movement of cone  236 , which may be disposed around the mandrel  214  in a manner with at least one surface  237  angled (or sloped, tapered, etc.) inwardly of second slip  242 . The second slip  242  may reside adjacent or proximate to collar or cone  236 . As such, the seal element  222  forces the cone  236  against the slip  242 , moving the slip  242  radially outwardly into contact or gripping engagement with the tubular. Accordingly, the one or more slips  234 ,  242  may be urged radially outward and into engagement with the tubular ( 208 ,  FIG. 2B ). In an embodiment, cone  236  may be slidingly engaged and disposed around the mandrel  214 . As shown, the first slip  234  may be at or near distal end  246 , and the second slip  242  may be disposed around the mandrel  214  at or near the proximate end  248 . It is within the scope of the disclosure that the position of the slips  234  and  242  may be interchanged. Moreover, slip  234  may be interchanged with a slip comparable to slip  242 , and vice versa. 
     Because the sleeve  254  is held rigidly in place, the sleeve  254  may engage against a bearing plate  283  that may result in the transfer load through the rest of the tool  202 . The setting sleeve  254  may have a sleeve end  255  that abuts against the bearing plate end  284 . As tension increases through the tool  202 , an end of the cone  236 , such as second end  240 , compresses against slip  242 , which may be held in place by the bearing plate  283 . As a result of cone  236  having freedom of movement and its conical surface  237 , the cone  236  may move to the underside beneath the slip  242 , forcing the slip  242  outward and into engagement with the surrounding tubular ( 208 ,  FIG. 2B ). 
     The second slip  242  may include one or more, gripping elements, such as buttons or inserts  278 , which may be configured to provide additional grip with the tubular. The inserts  278  may have an edge or corner  279  suitable to provide additional bite into the tubular surface. In an embodiment, the inserts  278  may be mild steel, such as 1018 heat treated steel. The use of mild steel may result in reduced or eliminated casing damage from slip engagement and reduced drill string and equipment damage from abrasion. 
     In an embodiment, slip  242  may be a one-piece slip, whereby the slip  242  has at least partial connectivity across its entire circumference. Meaning, while the slip  242  itself may have one or more grooves  244  configured therein, the slip  242  itself has no initial circumferential separation point. In an embodiment, the grooves  244  may be equidistantly spaced or disposed in the second slip  242 . In other embodiments, the grooves  244  may have an alternatingly arranged configuration. That is, one groove  244 A may be proximate to slip end  241 , the next groove  244 B may be proximate to an opposite slip end  243 , and so forth. 
     The tool  202  may be configured with ball plug check valve assembly that includes a ball seat  286 . The assembly may be removable or integrally formed therein. In an embodiment, the bore  250  of the mandrel  214  may be configured with the ball seat  286  formed or removably disposed therein. In some embodiments, the ball seat  286  may be integrally formed within the bore  250  of the mandrel  214 . In other embodiments, the ball seat  286  may be separately or optionally installed within the mandrel  214 , as may be desired. 
     The ball seat  286  may be configured in a manner so that a ball  285  seats or rests therein, whereby the flowpath through the mandrel  214  may be closed off (e.g., flow through the bore  250  is restricted or controlled by the presence of the ball  285 ). For example, fluid flow from one direction may urge and hold the ball  285  against the seat  286 , whereas fluid flow from the opposite direction may urge the ball  285  off or away from the seat  286 . As such, the ball  285  and the check valve assembly may be used to prevent or otherwise control fluid flow through the tool  202 . The ball  285  may be conventionally made of a composite material, phenolic resin, etc., whereby the ball  285  may be capable of holding maximum pressures experienced during downhole operations (e.g., fracing). By utilization of retainer pin  287 , the ball  285  and ball seat  286  may be configured as a retained ball plug. As such, the ball  285  may be adapted to serve as a check valve by sealing pressure from one direction, but allowing fluids to pass in the opposite direction. 
     The tool  202  may be configured as a drop ball plug, such that a drop ball may be flowed to a drop ball seat  259 . The drop ball may be much larger diameter than the ball of the ball check. In an embodiment, end  248  may be configured with a drop ball seat surface  259  such that the drop ball may come to rest and seat at in the seat proximate end  248 . As applicable, the drop ball (not shown here) may be lowered into the wellbore ( 206 ,  FIG. 2A ) and flowed toward the drop ball seat  259  formed within the tool  202 . The ball seat may be formed with a radius  259 A (i.e., circumferential rounded edge or surface). 
     In other aspects, the tool  202  may be configured as a bridge plug, which once set in the wellbore, may prevent or allow flow in either direction (e.g., upwardly/downwardly, etc.) through tool  202 . Accordingly, it should be apparent to one of skill in the art that the tool  202  of the present disclosure may be configurable as a frac plug, a drop ball plug, bridge plug, etc. simply by utilizing one of a plurality of adapters or other optional components. In any configuration, once the tool  202  is properly set, fluid pressure may be increased in the wellbore, such that further downhole operations, such as fracture in a target zone, may commence. 
     The tool  202  may include an anti-rotation assembly that includes an anti-rotation device or mechanism  282 , which may be a spring, a mechanically spring-energized composite tubular member, and so forth. The device  282  may be configured and usable for the prevention of undesired or inadvertent movement or unwinding of the tool  202  components. As shown, the device  282  may reside in cavity  294  of the sleeve (or housing)  254 . During assembly the device  282  may be held in place with the use of a lock ring  296 . In other aspects, pins may be used to hold the device  282  in place. 
       FIG. 2D  shows the lock ring  296  may be disposed around a part  217  of a setting tool coupled with the workstring  212 . The lock ring  296  may be securely held in place with screws inserted through the sleeve  254 . The lock ring  296  may include a guide hole or groove  295 , whereby an end  282 A of the device  282  may slidingly engage therewith. Protrusions or dogs  295 A may be configured such that during assembly, the mandrel  214  and respective tool components may ratchet and rotate in one direction against the device  282 ; however, the engagement of the protrusions  295 A with device end  282 B may prevent back-up or loosening in the opposite direction. 
     The anti-rotation mechanism may provide additional safety for the tool and operators in the sense it may help prevent inoperability of tool in situations where the tool is inadvertently used in the wrong application. For example, if the tool is used in the wrong temperature application, components of the tool may be prone to melt, whereby the device  282  and lock ring  296  may aid in keeping the rest of the tool together. As such, the device  282  may prevent tool components from loosening and/or unscrewing, as well as prevent tool  202  unscrewing or falling off the workstring  212 . 
     Drill-through of the tool  202  may be facilitated by the fact that the mandrel  214 , the slips  234 ,  242 , the cone(s)  236 , the composite member  220 , etc. may be made of drillable material that is less damaging to a drill bit than those found in conventional plugs. The drill bit will continue to move through the tool  202  until the downhole slip  234  and/or  242  are drilled sufficiently that such slip loses its engagement with the well bore. When that occurs, the remainder of the tools, which generally would include lower sleeve  260  and any portion of mandrel  214  within the lower sleeve  260  falls into the well. If additional tool(s)  202  exist in the well bore beneath the tool  202  that is being drilled through, then the falling away portion will rest atop the tool  202  located further in the well bore and will be drilled through in connection with the drill through operations related to the tool  202  located further in the well bore. Accordingly, the tool  202  may be sufficiently removed, which may result in opening the tubular  208 . 
     Referring now to  FIGS. 17A, 17B, and 17C  together, longitudinal side views of a system having a downhole tool moved from a pre-set to set position, illustrative of embodiments disclosed herein, are shown. System  300  may be comparable or identical in aspects, function, operation, components, etc. as that of System  200 , and redundant discussion is limited for sake of brevity. Accordingly,  FIGS. 17A-17C  illustrate tool  302  may be positioned downhole within a tubular  308 . In an embodiment, the tubular  308  may be casing (e.g., casing, hung casing, casing string, etc.). A workstring  312  may be used to position or run the tool  302  into to a desired location, as generally depicted by  FIG. 17A . As a result of the horizontal orientation and downward forces (e.g., gravity) the tool  302  may have a tool axis  358  offset or eccentric to a tubular axis  308   a , as the tool  302  and workstring  312  may naturally move to the bottommost part of the tubular  308  instead of being centralized. 
     The workstring  312  and setting sleeve  354  may be used collectively for activation of the tool  302  from an unset to set position in a manner like that of embodiments disclosed herein. The setting device(s) and components of the downhole tool  302  may be coupled with, and axially and/or longitudinally movable along mandrel  314 , where the mandrel  314  may extend through the tool (or tool body)  302 . When the setting sequence begins, as generally depicted in  FIG. 17B , the mandrel  314  may be pulled into tension while the setting sleeve  354  remains stationary. The lower sleeve  360  and other tool  302  components may incur a setting force by way of connectivity or coupling, be it directly or indirectly, with the mandrel  314 . 
     For example, as the lower sleeve  360  is pulled and tension occurs in the tool  302 , the components disposed about mandrel  314  between the lower sleeve  360  and the setting sleeve  354  may begin to compress against one another. The sleeve  354  may engage against a bearing plate  383  that may result in the transfer load through the rest of the tool  302 . As a result of cone  336  having freedom of movement, the cone  336  may move to the underside beneath the slip  342 , forcing the slip  342  outward and into engagement with the surrounding tubular  308 . 
     This force and resultant movement causes compression and/or expansion of slip  342 , which subsequently results in at least part of the tool  302  being raised or moved away from the bottommost surface  307  of the tubular  308 . The upward force F3 that occurs during setting and urges the tool  302  upward, and downward force F2 that occurs from gravity on the workstring  312  and results in net force(s) incurred along the tool  302 , including at point P1. The force at point P1 is at least partially due to the contact area A2 as a result of an external mandrel surface  345   a  of a proximate mandrel end  348  that contacts the inner surface  354   a  of the setting sleeve  354 . 
       FIG. 17B  illustrates the tool  302 , workstring  312 , etc. incurring various downward forces F2, resulting in the tool  302 , etc. moving along the bottom portion  307  of the casing  308 , and as the setting sequence progresses, radial outward movement of slips  334 ,  342  and compressible member  322  will ultimately urge the tool  302  toward a central position in the tubing  308 , as illustrated in  FIG. 17C  (where the tubing axis  308   a  and the tool axis  358  are concentric). 
     Generally tool  302  performance improves with centralization, such that, as shown in  FIG. 17C , the tool  302  ultimately sets in a position that provides an effective even annulus (i.e., annulus arrows  399 ) around the tool  302 . As a result of reduced contact area A2, the tool  302  also provides the ability for the setting sleeve  354  to have less hang-up and binding on the mandrel  314 . 
     Manufacturing of the external mandrel surface(s)  345   a  may be in a conventional manner, such as a machining process. The mandrel surface(s)  345   a  on the proximate end  348  may be rounded, or machined with enough incremental “flat” (linear) surfaces at different angles (or slopes) to form an apparent or effective rounded surface. 
     The use of such surfaces helps dramatically improve any aspect of reducing clearances and at friction, while at the same time the configuration of the proximate end  348  and the setting sleeve  354  limits or prevents “flopping around” of the same. The proximate end  348  may have a first length L1, which may extend about from the transition portion  349  to a most proximate end  348   b . The proximate end  348  may have a second length L2, which may be comparable to an approximate length of the mandrel  314  that may contact or engage the setting sleeve  354 , such as while in a run-in configuration. 
     Referring briefly to  FIGS. 15A, 15B, 15C, 15D, and 15E  together, longitudinal cross-sectional views of a mandrel having a reduced contact surface mandrel end; another example of a mandrel having a reduced contact surface mandrel end according to embodiments of the disclosure; a mandrel having a rounded contact surface mandrel end according to embodiments of the disclosure; a mandrel having a rounded contact surface mandrel end according to embodiments of the disclosure; and a mandrel having a rounded reduced contact surface mandrel end according to embodiments of the disclosure; illustrative of embodiments disclosed herein, are shown. 
     In accordance with the disclosure various configurations of the proximate mandrel end  348 , and particularly, an external mandrel surface  345   a , may be useful for improving tool performance and reducing unwanted forces incurred by the mandrel during setting and operation. As already described, as a result of configurations related to area A2, the tool ( 302 ) provides the ability for the setting sleeve  354  to have less hang-up and binding on the mandrel  314 . 
     The proximate end  348  may include an outer taper  348 A, which may be generally linear with an approximate cross-sectional slope s1 made with reference to an appropriate x-y axis as would be apparent to one of skill. The outer taper  348 A may suitable to help prevent the tool from getting stuck or binding. For example, during setting the use of a smaller tool may result in the tool binding on the setting sleeve, whereby the presence of the outer taper  348 A will allow the tool mandrel end  348  to slide off easier from the setting sleeve  354 . In an embodiment, the outer taper  348 A may be formed at an angle of about 5 degrees with respect to an axis ( 358 ). 
     There may be a neck or transition portion  349 , such that the mandrel may have variation with its outer diameter. The surface  345   a  of the transition portion  349  may be generally linear with an approximate cross-sectional slope s3 made with reference to an appropriate x-y axis as would be apparent to one of skill. 
     Between the taper  348 A and the transition  349  may be another generally linear surface  354   b  with an approximate cross-sectional slope s2. In a run-in configuration, the surface  354   b  may be engaged with the sleeve  354  around the circumference of the parts, and as essentially illustrated by area A2. The surfaces of the mandrel end  348  may intersect at points, such as point(s)  397 . The intersecting points  397  may be distinctly pointed, have rounded (or smoothed) surfaces), etc. 
       FIG. 15B  illustrates how mandrel end  348  may have additional (linear) surfaces at different angles (or slopes, e.g., s1-s7) to form an apparent or effective rounded surface.  FIG. 15C  illustrates by way of example how the external mandrel end may have a combination of generally linear surfaces (e.g., of approximate slope s1, s3) and surfaces having a curvature r1. The presence of a curvature r1 may be useful for further minimizing contact between the mandrel end and the setting sleeve. Comparably  FIG. 15E  illustrates the surface of the mandrel end having a substantially curved surface, including radius of curvature r6. 
     The external mandrel surface  345   a  of the proximate end  348  may have an apparent length L1, which may be with reference from a straight line from about the transition region  349  to an absolute furthest endpoint of the proximate end  348 . The external mandrel surface  345   a  of the proximate end  348  may have an apparent length L2, which may be with reference from a straight line from about the distance of the surface  345   a  intended to contact, engage, or otherwise be nearmost to the setting sleeve  354  prior to setting, such as during run-in. In aspects, the length L1 is greater than the length L2. As would be apparent, the mandrel  314  may be configured with the end mandrel surface  345   a  having a greater area A1 than a proximate settling sleeve engagement surface A2. 
     Manufacturing of the external mandrel surface(s)  345   a  may be in a conventional manner, such as a machining process. The mandrel surface(s)  345   a  on the mandrel end  348  may be rounded, linear, combinations, etc. The surface(s) may be readily machined with enough incremental “flat” (linear) surfaces at different angles (or slopes) to form an apparent or effective rounded surface. 
     Referring now to  FIGS. 3A, 3B, 3C and 3D  together, an isometric view and a longitudinal cross-sectional view of a mandrel usable with a downhole tool, a longitudinal cross-sectional view of an end of a mandrel, and a longitudinal cross-sectional view of an end of a mandrel engaged with a sleeve, in accordance with embodiments disclosed herein, are shown. Components of the downhole tool may be arranged and disposed about the mandrel  314 , as described and understood to one of skill in the art. The mandrel  314 , which may be made from filament wound drillable material, may have a distal end  346  and a proximate end  348 . The filament wound material may be made of various angles as desired to increase strength of the mandrel  314  in axial and radial directions. The presence of the mandrel  314  may provide the tool with the ability to hold pressure and linear forces during setting or plugging operations. 
     The mandrel  314  may be sufficient in length, such that the mandrel may extend through a length of tool (or tool body) ( 202 ,  FIG. 2B ). The mandrel  314  may be a solid body. In other aspects, the mandrel  314  may include a flowpath or bore  350  formed therethrough (e.g., an axial bore). There may be a flowpath or bore  350 , for example an axial bore, that extends through the entire mandrel  314 , with openings at both the proximate end  348  and oppositely at its distal end  346 . Accordingly, the mandrel  314  may have an inner bore surface  347 , which may include one or more threaded surfaces formed thereon. 
     The ends  346 ,  348  of the mandrel  314  may include internal or external (or both) threaded portions. As shown in  FIG. 3C , the mandrel  314  may have internal threads  316  within the bore  350  configured to receive a mechanical or wireline setting tool, adapter, etc. (not shown here). For example, there may be a first set of threads  316  configured for coupling the mandrel  314  with corresponding threads of another component (e.g., adapter  252 ,  FIG. 2B ). In an embodiment, the first set of threads  316  are shear threads. In an embodiment, application of a load to the mandrel  314  may be sufficient enough to shear the first set of threads  316 . Although not necessary, the use of shear threads may eliminate the need for a separate shear ring or pin, and may provide for shearing the mandrel  314  from the workstring. 
     The proximate end  348  may include an outer taper  348 A. The outer taper  348 A may help prevent the tool from getting stuck or binding. For example, during setting the use of a smaller tool may result in the tool binding on the setting sleeve, whereby the use of the outer taper  348  will allow the tool to slide off easier from the setting sleeve. In an embodiment, the outer taper  348 A may be formed at an angle of about 5 degrees with respect to the axis  358 . The length of the taper  348 A may be about 0.5 inches to about 0.75 inches. 
     There may be a neck or transition portion  349 , such that the mandrel may have variation with its outer diameter. In an embodiment, the mandrel  314  may have a first outer diameter D1 that is greater than a second outer diameter D2. Conventional mandrel components are configured with shoulders (i.e., a surface angle of about 90 degrees) that result in components prone to direct shearing and failure. In contrast, embodiments of the disclosure may include the transition portion  349  configured with an angled transition surface  349 A. A transition surface angle b may be about 25 degrees with respect to the tool (or tool component axis)  358 . 
     The transition portion  349  may withstand radial forces upon compression of the tool components, thus sharing the load. That is, upon compression the bearing plate  383  and mandrel  314 , the forces are not oriented in just a shear direction. The ability to share load(s) among components means the components do not have to be as large, resulting in an overall smaller tool size. 
     In addition to the first set of threads  316 , the mandrel  314  may have a second set of threads  318 . In one embodiment, the second set of threads  318  may be rounded threads disposed along an external mandrel surface  345  at the distal end  346 . The use of rounded threads may increase the shear strength of the threaded connection. 
       FIG. 3D  illustrates an embodiment of component connectivity at the distal end  346  of the mandrel  314 . As shown, the mandrel  314  may be coupled with a sleeve  360  having corresponding threads  362  configured to mate with the second set of threads  318 . In this manner, setting of the tool may result in distribution of load forces along the second set of threads  318  at an angle away from axis  358 . There may be one or more balls  364  disposed between the sleeve  360  and slip  334 . The balls  364  may help promote even breakage of the slip  334 . 
     Accordingly, the use of round threads may allow a non-axial interaction between surfaces, such that there may be vector forces in other than the shear/axial direction. The round thread profile may create radial load (instead of shear) across the thread root. As such, the rounded thread profile may also allow distribution of forces along more thread surface(s). As composite material is typically best suited for compression, this allows smaller components and added thread strength. This beneficially provides upwards of 5-times strength in the thread profile as compared to conventional composite tool connections. 
     With particular reference to  FIG. 3C , the mandrel  314  may have a ball seat  386  disposed therein. In some embodiments, the ball seat  386  may be a separate component, while in other embodiments the ball seat  386  may be formed integral with the mandrel  314 . There also may be a drop ball seat surface  359  formed within the bore  350  at the proximate end  348 . The ball seat  359  may have a radius  359 A that provides a rounded edge or surface for the drop ball to mate with. In an embodiment, the radius  359 A of seat  359  may be smaller than the ball that seats in the seat. Upon seating, pressure may “urge” or otherwise wedge the drop ball into the radius, whereby the drop ball will not unseat without an extra amount of pressure. The amount of pressure required to urge and wedge the drop ball against the radius surface, as well as the amount of pressure required to unwedge the drop ball, may be predetermined. Thus, the size of the drop ball, ball seat, and radius may be designed, as applicable. 
     The use of a small curvature or radius  359 A may be advantageous as compared to a conventional sharp point or edge of a ball seat surface. For example, radius  359 A may provide the tool with the ability to accommodate drop balls with variation in diameter, as compared to a specific diameter. In addition, the surface  359  and radius  359 A may be better suited to distribution of load around more surface area of the ball seat as compared to just at the contact edge/point of other ball seats. 
     Referring now to  FIGS. 6A, 6B, 6C, 6D, 6E, and 6F  together, an isometric view, a longitudinal cross-sectional view, a close-up longitudinal cross-sectional view, a side longitudinal view, a longitudinal cross-sectional view, and an underside isometric view, respectively, of a composite deformable member  320  (and its subcomponents) usable with a downhole tool in accordance with embodiments disclosed herein, are shown. The composite member  320  may be configured in such a manner that upon a compressive force, at least a portion of the composite member may begin to deform (or expand, deflect, twist, unspring, break, unwind, etc.) in a radial direction away from the tool axis (e.g.,  258 ,  FIG. 2C ). Although exemplified as “composite”, it is within the scope of the disclosure that member  320  may be made from metal, including alloys and so forth. 
     During the setting sequence, the seal element  322  and the composite member  320  may compress together. As a result of an angled exterior surface  389  of the seal element  322  coming into contact with the interior surface  388  of the composite member  320 , a deformable (or first or upper) portion  326  of the composite member  320  may be urged radially outward and into engagement the surrounding tubular (not shown) at or near a location where the seal element  322  at least partially sealingly engages the surrounding tubular. There may also be a resilient (or second or lower) portion  328 . In an embodiment, the resilient portion  328  may be configured with greater or increased resilience to deformation as compared to the deformable portion  326 . 
     The composite member  320  may be a composite component having at least a first material  331  and a second material  332 , but composite member  320  may also be made of a single material. The first material  331  and the second material  332  need not be chemically combined. In an embodiment, the first material  331  may be physically or chemically bonded, cured, molded, etc. with the second material  332 . Moreover, the second material  332  may likewise be physically or chemically bonded with the deformable portion  326 . In other embodiments, the first material  331  may be a composite material, and the second material  332  may be a second composite material. 
     The composite member  320  may have cuts or grooves  330  formed therein. The use of grooves  330  and/or spiral (or helical) cut pattern(s) may reduce structural capability of the deformable portion  326 , such that the composite member  320  may “flower” out. The groove  330  or groove pattern is not meant to be limited to any particular orientation, such that any groove  330  may have variable pitch and vary radially. 
     With groove(s)  330  formed in the deformable portion  326 , the second material  332 , may be molded or bonded to the deformable portion  326 , such that the grooves  330  are filled in and enclosed with the second material  332 . In embodiments, the second material  332  may be an elastomeric material. In other embodiments, the second material  332  may be 60-95 Duro A polyurethane or silicone. Other materials may include, for example, TFE or PTFE sleeve option-heat shrink. The second material  332  of the composite member  320  may have an inner material surface  368 . 
     Different downhole conditions may dictate choice of the first and/or second material. For example, in low temp operations (e.g., less than about 250 F), the second material comprising polyurethane may be sufficient, whereas for high temp operations (e.g., greater than about 250 F) polyurethane may not be sufficient and a different material like silicone may be used. 
     The use of the second material  332  in conjunction with the grooves  330  may provide support for the groove pattern and reduce preset issues. With the added benefit of second material  332  being bonded or molded with the deformable portion  326 , the compression of the composite member  320  against the seal element  322  may result in a robust, reinforced, and resilient barrier and seal between the components and with the inner surface of the tubular member (e.g.,  208  in  FIG. 2B ). As a result of increased strength, the seal, and hence the tool of the disclosure, may withstand higher downhole pressures. Higher downhole pressures may provide a user with better frac results. 
     Groove(s)  330  allow the composite member  320  to expand against the tubular, which may result in a formidable barrier between the tool and the tubular. In an embodiment, the groove  330  may be a spiral (or helical, wound, etc.) cut formed in the deformable portion  326 . In an embodiment, there may be a plurality of grooves or cuts  330 . In another embodiment, there may be two symmetrically formed grooves  330 , as shown by way of example in  FIG. 6E . In yet another embodiment, there may be three grooves  330 . 
     As illustrated by  FIG. 6C , the depth d of any cut or groove  330  may extend entirely from an exterior side surface  364  to an upper side interior surface  366 . The depth d of any groove  330  may vary as the groove  330  progresses along the deformable portion  326 . In an embodiment, an outer planar surface  364 A may have an intersection at points tangent the exterior side  364  surface, and similarly, an inner planar surface  366 A may have an intersection at points tangent the upper side interior surface  366 . The planes  364 A and  366 A of the surfaces  364  and  366 , respectively, may be parallel or they may have an intersection point  367 . Although the composite member  320  is depicted as having a linear surface illustrated by plane  366 A, the composite member  320  is not meant to be limited, as the inner surface may be non-linear or non-planar (i.e., have a curvature or rounded profile). 
     In an embodiment, the groove(s)  330  or groove pattern may be a spiral pattern having constant pitch (p 1  about the same as p 2 ), constant radius (r 3  about the same as r 4 ) on the outer surface  364  of the deformable member  326 . In an embodiment, the spiral pattern may include constant pitch (p 1  about the same as p 2 ), variable radius (r 1  unequal to r 2 ) on the inner surface  366  of the deformable member  326 . 
     In an embodiment, the groove(s)  330  or groove pattern may be a spiral pattern having variable pitch (p 1  unequal to p 2 ), constant radius (r 3  about the same as r 4 ) on the outer surface  364  of the deformable member  326 . In an embodiment, the spiral pattern may include variable pitch (p 1  unequal to p 2 ), variable radius (r 1  unequal to r 2 ) on the inner surface  366  of the deformable member  320 . 
     As an example, the pitch (e.g., p 1 , p 2 , etc.) may be in the range of about 0.5 turns/inch to about 1.5 turns/inch. As another example, the radius at any given point on the outer surface may be in the range of about 1.5 inches to about 8 inches. The radius at any given point on the inner surface may be in the range of about less than 1 inch to about 7 inches. Although given as examples, the dimensions are not meant to be limiting, as other pitch and radial sizes are within the scope of the disclosure. 
     In an exemplary embodiment reflected in  FIG. 6B , the composite member  320  may have a groove pattern cut on a back angle β. A pattern cut or formed with a back angle may allow the composite member  320  to be unrestricted while expanding outward. In an embodiment, the back angle β may be about 75 degrees (with respect to axis  258 ). In other embodiments, the angle β may be in the range of about 60 to about 120 degrees 
     The presence of groove(s)  330  may allow the composite member  320  to have an unwinding, expansion, or “flower” motion upon compression, such as by way of compression of a surface (e.g., surface  389 ) against the interior surface of the deformable portion  326 . For example, when the seal element  322  moves, surface  389  is forced against the interior surface  388 . Generally the failure mode in a high pressure seal is the gap between components; however, the ability to unwind and/or expand allows the composite member  320  to extend completely into engagement with the inner surface of the surrounding tubular. 
     Referring now to  FIGS. 4A and 4B  together, a longitudinal cross-sectional view and an isometric view of a seal element (and its subcomponents), respectively, usable with a downhole tool in accordance with embodiments disclosed herein are shown. The seal element  322  may be made of an elastomeric and/or poly material, such as rubber, nitrile rubber, Viton or polyurethane, and may be configured for positioning or otherwise disposed around the mandrel (e.g.,  214 ,  FIG. 2C ). In an embodiment, the seal element  322  may be made from 75 Duro A elastomer material. The seal element  322  may be disposed between a first slip and a second slip (see  FIG. 2C , seal element  222  and slips  234 ,  236 ). 
     The seal element  322  may be configured to buckle (deform, compress, etc.), such as in an axial manner, during the setting sequence of the downhole tool ( 202 ,  FIG. 2C ). However, although the seal element  322  may buckle, the seal element  322  may also be adapted to expand or swell, such as in a radial manner, into sealing engagement with the surrounding tubular ( 208 ,  FIG. 2B ) upon compression of the tool components. In a preferred embodiment, the seal element  322  provides a fluid-tight seal of the seal surface  321  against the tubular. 
     The seal element  322  may have one or more angled surfaces configured for contact with other component surfaces proximate thereto. For example, the seal element may have angled surfaces  327  and  389 . The seal element  322  may be configured with an inner circumferential groove  376 . The presence of the groove  376  assists the seal element  322  to initially buckle upon start of the setting sequence. The groove  376  may have a size (e.g., width, depth, etc.) of about 0.25 inches. 
     Referring now to  FIGS. 5A, 5B, 5C, 5D, 5E, 5F, and 5G  together, an isometric view, a lateral view, and a longitudinal cross-sectional view of one or more slips, and an isometric view of a metal slip, a lateral view of a metal slip, a longitudinal cross-sectional view of a metal slip, and an isometric view of a metal slip without buoyant material holes, respectively, (and related subcomponents) usable with a downhole tool in accordance with embodiments disclosed herein are shown. The slips  334 ,  342  described may be made from metal, such as cast iron, or from composite material, such as filament wound composite. During operation, the winding of the composite material may work in conjunction with inserts under compression in order to increase the radial load of the tool. 
     Slips  334 ,  342  may be used in either upper or lower slip position, or both, without limitation. As apparent, there may be a first slip  334 , which may be disposed around the mandrel ( 214 ,  FIG. 2C ), and there may also be a second slip  342 , which may also be disposed around the mandrel. Either of slips  334 ,  342  may include a means for gripping the inner wall of the tubular, casing, and/or well bore, such as a plurality of gripping elements, including serrations or teeth  398 , inserts  378 , etc. As shown in  FIGS. 5D-5F , the first slip  334  may include rows and/or columns  399  of serrations  398 . The gripping elements may be arranged or configured whereby the slips  334 ,  342  engage the tubular (not shown) in such a manner that movement (e.g., longitudinally axially) of the slips or the tool once set is prevented. 
     In embodiments, the slip  334  may be a poly-moldable material. In other embodiments, the slip  334  may be hardened, surface hardened, heat-treated, carburized, etc., as would be apparent to one of ordinary skill in the art. However, in some instances, slips  334  may be too hard and end up as too difficult or take too long to drill through. 
     Typically, hardness on the teeth  398  may be about 40-60 Rockwell. As understood by one of ordinary skill in the art, the Rockwell scale is a hardness scale based on the indentation hardness of a material. Typical values of very hard steel have a Rockwell number (HRC) of about 55-66. In some aspects, even with only outer surface heat treatment the inner slip core material may become too hard, which may result in the slip  334  being impossible or impracticable to drill-thru. 
     Thus, the slip  334  may be configured to include one or more holes  393  formed therein. The holes  393  may be longitudinal in orientation through the slip  334 . The presence of one or more holes  393  may result in the outer surface(s)  307  of the metal slips as the main and/or majority slip material exposed to heat treatment, whereas the core or inner body (or surface)  309  of the slip  334  is protected. In other words, the holes  393  may provide a barrier to transfer of heat by reducing the thermal conductivity (i.e., k-value) of the slip  334  from the outer surface(s)  307  to the inner core or surfaces  309 . The presence of the holes  393  is believed to affect the thermal conductivity profile of the slip  334 , such that that heat transfer is reduced from outer to inner because otherwise when heat/quench occurs the entire slip  334  heats up and hardens. 
     Thus, during heat treatment, the teeth  398  on the slip  334  may heat up and harden resulting in heat-treated outer area/teeth, but not the rest of the slip. In this manner, with treatments such as flame (surface) hardening, the contact point of the flame is minimized (limited) to the proximate vicinity of the teeth  398 . 
     With the presence of one or more holes  393 , the hardness profile from the teeth to the inner diameter/core (e.g., laterally) may decrease dramatically, such that the inner slip material or surface  309  has a HRC of about  ˜ 15 (or about normal hardness for regular steel/cast iron). In this aspect, the teeth  398  stay hard and provide maximum bite, but the rest of the slip  334  is easily drillable. 
     One or more of the void spaces/holes  393  may be filled with useful “buoyant” (or low density) material  400  to help debris and the like be lifted to the surface after drill-thru. The material  400  disposed in the holes  393  may be, for example, polyurethane, light weight beads, or glass bubbles/beads such as the K-series glass bubbles made by and available from 3M. Other low-density materials may be used. 
     The advantageous use of material  400  helps promote lift on debris after the slip  334  is drilled through. The material  400  may be epoxied or injected into the holes  393  as would be apparent to one of skill in the art. 
     The slots  392  in the slip  334  may promote breakage. An evenly spaced configuration of slots  392  promotes even breakage of the slip  334 . The metal slip  334  may 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 in  FIG. 5D  via connectivity reference line  374 . The slip  334  may have at least one lateral groove  371 . The lateral groove may be defined by a depth  373 . The depth  373  may extend from the outer surface  307  to the inner surface  309 . 
     First slip  334  may be disposed around or coupled to the mandrel ( 214 ,  FIG. 2B ) as would be known to one of skill in the art, such as a band or with shear screws (not shown) configured to maintain the position of the slip  334  until sufficient pressure (e.g., shear) is applied. The band may be made of steel wire, plastic material or composite material having the requisite characteristics in sufficient strength to hold the slip  334  in place while running the downhole tool into the wellbore, and prior to initiating setting. The band may be drillable. 
     When sufficient load is applied, the slip  334  compresses against the resilient portion or surface of the composite member (e.g.,  220 ,  FIG. 2C ), and subsequently expand radially outwardly to engage the surrounding tubular (see, for example, slip  234  and composite member  220  in  FIG. 2C ). 
       FIG. 5G  illustrates slip  334  may be a hardened cast iron slip without the presence of any grooves or holes  393  formed therein. 
     Referring briefly to  FIGS. 11A and 11B  together, a side longitudinal view and a longitudinal cross-sectional view, respectively, of a downhole tool  1102  configured with a plurality of composite members  1120 ,  1120 A and metal slips  1134 ,  1142 , according to embodiments of the disclosure, are shown. The slips  1134 ,  1142  may be one-piece in nature, and be made from various materials such as metal (e.g., cast iron) or composite. It is known that metal material results in a slip that is harder to drill-thru compared to composites, but in some applications it might be necessary to resist pressure and/or prevent movement of the tool  1102  from two directions (e.g., above/below), making it beneficial to use two slips  1134  that are metal. Likewise, in high pressure/high temperature applications (HP/HT), it may be beneficial/better to use slips made of hardened metal. The slips  1134 ,  1142  may be disposed around  1114  in a manner discussed herein. 
     It is within the scope of the disclosure that tools described herein may include multiple composite members  1120 ,  1120 A. The composite members  1120 ,  1120 A may be identical, or they may different and encompass any of the various embodiments described herein and apparent to one of ordinary skill in the art. 
     Referring again to  FIGS. 5A-5C , slip  342  may be a one-piece slip, whereby the slip  342  has at least partial connectivity across its entire circumference. Meaning, while the slip  342  itself may have one or more grooves  344  configured therein, the slip  342  has no separation point in the pre-set configuration. In an embodiment, the grooves  344  may be equidistantly spaced or cut in the second slip  342 . In other embodiments, the grooves  344  may have an alternatingly arranged configuration. That is, one groove  344 A may be proximate to slip end  341  and adjacent groove  344 B may be proximate to an opposite slip end  343 . As shown in groove  344 A may extend all the way through the slip end  341 , such that slip end  341  is devoid of material at point  372 . The slip  342  may have an outer slip surface  390  and an inner slip surface  391 . 
     Where the slip  342  is devoid of material at its ends, that portion or proximate area of the slip may have the tendency to flare first during the setting process. The arrangement or position of the grooves  344  of the slip  342  may be designed as desired. In an embodiment, the slip  342  may be designed with grooves  344  resulting in equal distribution of radial load along the slip  342 . Alternatively, one or more grooves, such as groove  344 B may extend proximate or substantially close to the slip end  343 , but leaving a small amount material  335  therein. The presence of the small amount of material gives slight rigidity to hold off the tendency to flare. As such, part of the slip  342  may expand or flare first before other parts of the slip  342 . There may be one or more grooves  344  that form a lateral opening  394   a  through the entirety of the slip body. That is, groove  344  may extend a depth  394  from the outer slip surface  390  to the inner slip surface  391 . Depth  394  may define a lateral distance or length of how far material is removed from the slip body with reference to slip surface  390  (or also slip surface  391 ).  FIG. 5A  illustrates the at least one of the grooves  344  may be further defined by the presence of a first portion of slip material  335   a  on or at first end  341 , and a second portion of slip material  335   b  on or at second end  343 . 
     The slip  342  may have one or more inner surfaces with varying angles. For example, there may be a first angled slip surface  329  and a second angled slip surface  333 . In an embodiment, the first angled slip surface  329  may have a 20-degree angle, and the second angled slip surface  333  may have a 40-degree angle; however, the degree of any angle of the slip surfaces is not limited to any particular angle. Use of angled surfaces allows the slip  342  significant engagement force, while utilizing the smallest slip  342  possible. 
     The use of a rigid single- or one-piece slip configuration may reduce the chance of presetting that is associated with conventional slip rings, as conventional slips are known for pivoting and/or expanding during run in. As the chance for pre-set is reduced, faster run-in times are possible. 
     The slip  342  may be used to lock the tool in place during the setting process by holding potential energy of compressed components in place. The slip  342  may also prevent the tool from moving as a result of fluid pressure against the tool. The second slip ( 342 ,  FIG. 5A ) may include inserts  378  disposed thereon. In an embodiment, the inserts  378  may be epoxied or press fit into corresponding insert bores or grooves  375  formed in the slip  342 . 
     Referring briefly to  FIGS. 13A-13D  together, an underside isometric view of an insert(s) configured with a hole, an underside isometric views of another insert(s), and a topside isometric view of an insert(s), respectively, usable with the slip(s) of the present disclosure are shown. One or more of the inserts  378  may have a flat surface  380 A or concave surface  380 . In an embodiment, the concave surface  380  may include a depression  377  formed therein. One or more of the inserts  378  may have a sharpened (e.g., machined) edge or corner  379 , which allows the insert  378  greater biting ability. 
     Referring now to  FIGS. 8A and 8B  together, an underside isometric view and a longitudinal cross-sectional view, respectively, of one or more cones  336  (and its subcomponents) usable with a downhole tool in accordance with embodiments disclosed herein, are shown. In an embodiment, cone  336  may be slidingly engaged and disposed around the mandrel (e.g., cone  236  and mandrel  214  in  FIG. 2C ). Cone  336  may be disposed around the mandrel in a manner with at least one surface  337  angled (or sloped, tapered, etc.) inwardly with respect to other proximate components, such as the second slip ( 242 ,  FIG. 2C ). As such, the cone  336  with surface  337  may be configured to cooperate with the slip to force the slip radially outwardly into contact or gripping engagement with a tubular, as would be apparent and understood by one of skill in the art. 
     During setting, and as tension increases through the tool, an end of the cone  336 , such as second end  340 , may compress against the slip (see  FIG. 2C ). As a result of conical surface  337 , the cone  336  may move to the underside beneath the slip, forcing the slip outward and into engagement with the surrounding tubular (see  FIG. 2A ). A first end  338  of the cone  336  may be configured with a cone profile  351 . The cone profile  351  may be configured to mate with the seal element ( 222 ,  FIG. 2C ). In an embodiment, the cone profile  351  may be configured to mate with a corresponding profile  327 A of the seal element (see  FIG. 4A ). The cone profile  351  may help restrict the seal element from rolling over or under the cone  336 . 
     Referring now to  FIGS. 9A and 9B , an isometric view, and a longitudinal cross-sectional view, respectively, of a lower sleeve  360  (and its subcomponents) usable with a downhole tool in accordance with embodiments disclosed herein, are shown. During setting, the lower sleeve  360  will be pulled as a result of its attachment to the mandrel  214 . As shown in  FIGS. 9A and 9B  together, the lower sleeve  360  may have one or more holes  381 A that align with mandrel holes ( 281 B,  FIG. 2C ). One or more anchor pins  311  may be disposed or securely positioned therein. In an embodiment, brass set screws may be used. Pins (or screws, etc.)  311  may prevent shearing or spin off during drilling. 
     As the lower sleeve  360  is pulled, the components disposed about mandrel between the may further compress against one another. The lower sleeve  360  may have one or more tapered surfaces  361 ,  361 A which may reduce chances of hang up on other tools. The lower sleeve  360  may also have an angled sleeve end  363  in engagement with, for example, the first slip ( 234 ,  FIG. 2C ). As the lower sleeve  360  is pulled further, the end  363  presses against the slip. The lower sleeve  360  may be configured with an inner thread profile  362 . In an embodiment, the profile  362  may include rounded threads. In another embodiment, the profile  362  may be configured for engagement and/or mating with the mandrel ( 214 ,  FIG. 2C ). Ball(s)  364  may be used. The ball(s)  364  may be for orientation or spacing with, for example, the slip  334 . The ball(s)  364  and may also help maintain break symmetry of the slip  334 . The ball(s)  364  may be, for example, brass or ceramic. 
     Referring briefly to  FIGS. 9C-9E  together, an isometric, lateral, and longitudinal cross-sectional view, respectively, of the lower sleeve  360  configured with stabilizer pin inserts, and usable with a downhole tool in accordance with embodiments disclosed herein, are shown. In addition to the ball(s)  364 , the lower sleeve  360  may be configured with one or more stabilizer pins (or pin inserts)  364 A. 
     A possible difficulty with a one-piece metal slip is that instead of breaking evenly or symmetrically, it may be prone to breaking in a single spot or an uneven manner, and then fanning out (e.g., like a fan belt). If this it occurs, it may problematic because the metal slip (e.g.,  334 ,  FIG. 5D ) may not engage the casing (or surrounding surface) in an adequate, even manner, and the downhole tool may not be secured in place. Some conventional metal slips are “segmented” so the slip expands in mostly equal amounts circumferentially; however, it is commonly understood and known that these type of slips are very prone to pre-setting or inadvertent setting. 
     In contrast, the one-piece slip configuration is very durable, takes a lot of shock, and will not pre-set, but may require a configuration that urges uniform and even breakage. In accordance with embodiments disclosed herein, the metal slip  334  may be configured to mate or otherwise engage with pins  364 A, which may aid breaking the slip  334  uniformly as a result of distribution of forces against the slip  334  (see  FIG. 17A ). 
     It is believed a durable insert pin  364 A may perform better than an integral pin/sleeve configuration of the lower sleeve  360  because of the huge massive forces that are encountered (i.e., 30,000 lbs). The pins  364 A may be made of a durable metal, composite, etc., with the advantage of composite meaning the pins  364 A are easily drillable. 
     This configuration is advantageous over changing breakage points on the metal slip because doing so would impact the strength of the slip, which is undesired. Accordingly, this configuration may allow improved breakage without impacting strength of the slip (i.e., ability to hold set pressure). In the instances where strength is not of consequence, a composite slip (i.e., a slip more readily able to break evening) could be used—use of metal slip is typically used for greater pressure conditions/setting requirements. 
     The pins  364 A may be formed or manufactured by standard processes, and then cut (or machined, etc.) to an adequate or desired shape, size, and so forth. The pins  364 A may be shaped and sized to a tolerance fit with slots  381 B. In other aspects, the pins  364 A may be shaped and sized to an undersized or oversized fit with slots  381 B. The pins  364 A may be held in situ with an adhesive or glue. 
     In embodiments one or more of the pins  364 ,  364 A may have a rounded or spherical portion configured for engagement with the metal slip (see  FIG. 3D ). In other embodiments, one or more of the pins  364 ,  364 A may have a planar portion  365  configured for engagement with the metal slip  334 . In yet other embodiments, one or more of the pins  364 ,  364 A may be configured with a taper(s)  369 . 
     The presence of the taper(s)  369  may be useful to help minimize displacement in the event the metal slip  334  inadvertently attempts to ‘hop up’ over one of the pins  364 A in the instance the metal slip  334  did not break properly or otherwise. 
     One or more of the pins  364 A may be configured with a ‘cut out’ portion that results in a pointed region on the inward side of the pin(s)  364 A (see 9EE). This may aid in ‘crushing’ of the pin  364 A during setting so that the pin  364 A moves out of the way. 
     Referring briefly to  FIGS. 16A-16D , an isometric view, a lateral view, a longitudinal cross-sectional view, and a rotated longitudinal cross-sectional view, respectively, of a metal slip configured with one or more mating holes, in accordance with embodiments disclosed herein are shown. In the spirit of the disclosure, one or more of the (mating) holes  393 A in the metal slip  334  may be configured in a round, symmetrical fashion or shape. Just the same, one or more of the holes  393 A may additionally or alternatively be configured in an asymmetrical fashion or shape. In an embodiment, one or more of the holes may be configured in a ‘tear drop’ fashion or shape. 
     Each of these aspects may contribute to the ability of the metal slip  334  to break a generally equal amount of distribution around the slip body circumference. That is, the metal slip  334  breaks in a manner where portions of the slip engage the surrounding tubular and the distribution of load is about equal or even around the slip  334 . Thus, the metal slip  334  may be configured in a manner so that upon breakage load may be applied from the tool against the surrounding tubular in an approximate even or equal manner circumferentially (or radially). 
     The metal slip  334  may be configured in an optimal one-piece configuration that prevents or otherwise prohibits pre-setting, but ultimately breaks in an equal or even manner comparable to the intent of a conventional “slip segment” metal slip. 
     Referring now to  FIGS. 7A and 7B  together, an isometric view and a longitudinal cross-sectional view, respectively, of a bearing plate  383  (and its subcomponents) usable with a downhole tool in accordance with embodiments disclosed herein are shown. The bearing plate  383  may be made from filament wound material having wide angles. As such, the bearing plate  383  may endure increased axial load, while also having increased compression strength. 
     Because the sleeve ( 254 ,  FIG. 2C ) may held rigidly in place, the bearing plate  383  may likewise be maintained in place. The setting sleeve may have a sleeve end  255  that abuts against bearing plate end  284 ,  384 . Briefly,  FIG. 2C  illustrates how compression of the sleeve end  255  with the plate end  284  may occur at the beginning of the setting sequence. As tension increases through the tool, and other end  239  of the bearing plate  283  may be compressed by slip  242 , forcing the slip  242  outward and into engagement with the surrounding tubular ( 208 ,  FIG. 2B ). 
     Inner plate surface  319  may be configured for angled engagement with the mandrel. In an embodiment, plate surface  319  may engage the transition portion  349  of the mandrel  314 . Lip  323  may be used to keep the bearing plate  383  concentric with the tool  202  and the slip  242 . Small lip  323 A may also assist with centralization and alignment of the bearing plate  383 . 
     Referring now to  FIGS. 10A and 10B  together, an isometric view and a longitudinal cross-sectional view, respectively, of a ball seat  386  (and its subcomponents) usable with a downhole tool in accordance with embodiments disclosed herein are shown. Ball seat  386  may be made from filament wound composite material or metal, such as brass. The ball seat  386  may be configured to cup and hold a ball  385 , whereby the ball seat  386  may function as a valve, such as a check valve. As a check valve, pressure from one side of the tool may be resisted or stopped, while pressure from the other side may be relieved and pass therethrough. 
     In an embodiment, the bore ( 250 ,  FIG. 2D ) of the mandrel ( 214 ,  FIG. 2D ) may be configured with the ball seat  386  formed therein. In some embodiments, the ball seat  386  may be integrally formed within the bore of the mandrel, while in other embodiments, the ball seat  386  may be separately or optionally installed within the mandrel, as may be desired. As such, ball seat  386  may have an outer surface  386 A bonded with the bore of the mandrel. The ball seat  386  may have a ball seat surface  386 B. 
     The ball seat  386  may be configured in a manner so that when a ball ( 385 ,  FIG. 3C ) seats therein, a flowpath through the mandrel may be closed off (e.g., flow through the bore  250  is restricted by the presence of the ball  385 ). The ball  385  may be made of a composite material, whereby the ball  385  may be capable of holding maximum pressures during downhole operations (e.g., fracing). 
     As such, the ball  385  may be used to prevent or otherwise control fluid flow through the tool. As applicable, the ball  385  may be lowered into the wellbore ( 206 ,  FIG. 2A ) and flowed toward a ball seat  386  formed within the tool  202 . Alternatively, the ball  385  may be retained within the tool  202  during run in so that ball drop time is eliminated. As such, by utilization of retainer pin ( 387 ,  FIG. 3C ), the ball  385  and ball seat  386  may be configured as a retained ball plug. As such, the ball  385  may be adapted to serve as a check valve by sealing pressure from one direction, but allowing fluids to pass in the opposite direction. 
     Referring now to  FIGS. 12A and 12B  together, longitudinal side views of an encapsulated downhole tool in accordance with embodiments disclosed herein, are shown. In embodiments, the downhole tool  1202  of the present disclosure may include an encapsulation. Encapsulation may be completed with an injection molding process. For example, the tool  1202  may be assembled, put into a clamp device configured for injection molding, whereby an encapsulation material  1290  may be injected accordingly into the clamp and left to set or cure for a pre-determined amount of time on the tool  1202  (not shown). 
     Encapsulation may help resolve presetting issues; the material  1290  is strong enough to hold in place or resist movement of, tool parts, such as the slips  1234 ,  1242 , and sufficient in material properties to withstand extreme downhole conditions, but is easily breached by tool  1202  components upon routine setting and operation. Example materials for encapsulation include polyurethane or silicone; however, any type of material that flows, hardens, and does not restrict functionality of the downhole tool may be used, as would be apparent to one of skill in the art. 
     Referring now to  FIGS. 14A and 14B  together, longitudinal cross-sectional views of various configurations of a downhole tool in accordance with embodiments disclosed herein, are shown. Components of downhole tool  1402  may be arranged and operable, as described in embodiments disclosed herein and understood to one of skill in the art. 
     The tool  1402  may include a mandrel  1414  configured as a solid body. In other aspects, the mandrel  1414  may include a flowpath or bore  1450  formed therethrough (e.g., an axial bore). The bore  1450  may be formed as a result of the manufacture of the mandrel  1414 , such as by filament or cloth winding around a bar. As shown in  FIG. 14A , the mandrel may have the bore  1450  configured with an insert  1414 A disposed therein. Pin(s)  1411  may be used for securing lower sleeve  1460 , the mandrel  1414 , and the insert  1414 A. The bore  1450  may extend through the entire mandrel  1414 , with openings at both the first end  1448  and oppositely at its second end  1446 .  FIG. 14B  illustrates the end  1448  of the mandrel  1414  may be fitted with a plug  1403 . 
     In certain circumstances, a drop ball may not be a usable option, so the mandrel  1414  may optionally be fitted with the fixed plug  1403 . The plug  1403  may be configured for easier drill-thru, such as with a hollow. Thus, the plug may be strong enough to be held in place and resist fluid pressures, but easily drilled through. The plug  1403  may be threadingly and/or sealingly engaged within the bore  1450 . 
     The ends  1446 ,  1448  of the mandrel  1414  may include internal or external (or both) threaded portions. In an embodiment, the tool  1402  may be used in a frac service, and configured to stop pressure from above the tool  1401 . In another embodiment, the orientation (e.g., location) of composite member  1420 B may be in engagement with second slip  1442 . In this aspect, the tool  1402  may be used to kill flow by being configured to stop pressure from below the tool  1402 . In yet other embodiments, the tool  1402  may have composite members  1420 ,  1420 A on each end of the tool.  FIG. 14A  shows composite member  1420  engaged with first slip  1434 , and second composite member  1420 A engaged with second slip  1442 . The composite members  1420 ,  1420 A need not be identical. In this aspect, the tool  1402  may be used in a bidirectional service, such that pressure may be stopped from above and/or below the tool  1402 . A composite rod may be glued into the bore  1450 . 
     Advantages 
     Embodiments of the downhole tool are smaller in size, which allows the tool to be used in slimmer bore diameters. Smaller in size also means there is a lower material cost per tool. Because isolation tools, such as plugs, are used in vast numbers, and are generally not reusable, a small cost savings per tool results in enormous annual capital cost savings. 
     A synergistic effect is realized because a smaller tool means faster drilling time is easily achieved. Again, even a small savings in drill-through time per single tool results in an enormous savings on an annual basis. 
     Advantageously, the configuration of components, and the resilient barrier formed by way of the composite member results in a tool that can withstand significantly higher pressures. The ability to handle higher wellbore pressure results in operators being able to drill deeper and longer wellbores, as well as greater frac fluid pressure. The ability to have a longer wellbore and increased reservoir fracture results in significantly greater production. 
     As the tool may be smaller (shorter), the tool may navigate shorter radius bends in well tubulars without hanging up and presetting. Passage through shorter tool has lower hydraulic resistance and can therefore accommodate higher fluid flow rates at lower pressure drop. The tool may accommodate a larger pressure spike (ball spike) when the ball seats. 
     The composite member may beneficially inflate or umbrella, which aids in run-in during pump down, thus reducing the required pump down fluid volume. This constitutes a savings of water and reduces the costs associated with treating/disposing recovered fluids. 
     One piece slips assembly are resistant to preset due to axial and radial impact allowing for faster pump down speed. This further reduces the amount of time/water required to complete frac operations. 
     While preferred embodiments of the invention have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit and teachings of the invention. The embodiments described herein are exemplary only, and are not intended to be limiting. Many variations and modifications of the invention disclosed herein are possible and are within the scope of the invention. Where numerical ranges or limitations are expressly stated, such express ranges or limitations should be understood to include iterative ranges or limitations of like magnitude falling within the expressly stated ranges or limitations. The use of the term “optionally” with respect to any element of a claim is intended to mean that the subject element is required, or alternatively, is not required. Both alternatives are intended to be within the scope of the claim. Use of broader terms such as comprises, includes, having, etc. should be understood to provide support for narrower terms such as consisting of, consisting essentially of, comprised substantially of, and the like. 
     Accordingly, the scope of protection is not limited by the description set out above but is only limited by the claims which follow, that scope including all equivalents of the subject matter of the claims. Each and every claim is incorporated into the specification as an embodiment of the present invention. Thus, the claims are a further description and are an addition to the preferred embodiments of the present invention. The inclusion or discussion of a reference is not an admission that it is prior art to the present invention, especially any reference that may have a publication date after the priority date of this application. The disclosures of all patents, patent applications, and publications cited herein are hereby incorporated by reference, to the extent they provide background knowledge; or exemplary, procedural or other details supplementary to those set forth herein.