Patent Publication Number: US-9850738-B2

Title: Bottom set downhole plug

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This is a continuation application of U.S. application Ser. No. 13/329,096, filed Dec. 16, 2011, which is a divisional of U.S. patent application Ser. No. 13/194,871, filed Jul. 29, 2011, which is a continuation-in-part of U.S. patent application Ser. No. 12/317,497, filed Dec. 23, 2008, the entirety of which is incorporated by reference herein. 
    
    
     BACKGROUND 
     Field 
     Embodiments described generally relate to downhole tools. More particularly, embodiments described relate to downhole tools that are set within a wellbore with a lower shear mechanism. 
     Description of the Related Art 
     Bridge plugs, packers, and frac plugs are downhole tools that are typically used to permanently or temporarily isolate one wellbore zone from another. Such isolation is often necessary to pressure test, perforate, frac, or stimulate a zone of the wellbore without impacting or communicating with other zones within the wellbore. To reopen and/or restore fluid communication through the wellbore, plugs are typically removed or otherwise compromised. 
     Permanent, non-retrievable plugs and/or packers are typically drilled or milled to remove. Most non-retrievable plugs are constructed of a brittle material such as cast iron, cast aluminum, ceramics, or engineered composite materials, which can be drilled or milled. Problems sometimes occur, however, during the removal or drilling of such non-retrievable plugs. For instance, the non-retrievable plug components can bind upon the drill bit, and rotate within the casing string. Such binding can result in extremely long drill-out times, excessive casing wear, or both. Long drill-out times are highly undesirable, as rig time is typically charged by the hour. 
     In use, non-retrievable plugs are designed to perform a particular function. A bridge plug, for example, is typically used to seal a wellbore such that fluid is prevented from flowing from one side of the bridge plug to the other. On the other hand, drop ball plugs allow for the temporary cessation of fluid flow in one direction, typically in the downhole direction, while allowing fluid flow in the other direction. Depending on user preference, one plug type may be advantageous over another, depending on the completion and/or production activity. 
     Certain completion and/or production activities may require several plugs run in series or several different plug types run in series. For example, one well may require three bridge plugs and five drop ball plugs, and another well may require two bridge plugs and ten drop ball plugs for similar completion and/or production activities. Within a given completion and/or production activity, the well may require several hundred plugs and/or packers depending on the productivity, depths, and geophysics of each well. The uncertainty in the types and numbers of plugs that might be required typically leads to the over-purchase and/or under-purchase of the appropriate types and numbers of plugs resulting in fiscal inefficiencies and/or field delays. 
     There is a need, therefore, for a downhole tool that can effectively seal the wellbore at wellbore conditions; be quickly, easily, and/or reliably removed from the wellbore; and configured in the field to perform one or more functions. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       Non-limiting, illustrative embodiments are depicted in the drawings, which are briefly described below. It is to be noted, however, that these illustrative drawings illustrate only typical embodiments and are not to be considered limiting of its scope, for the invention can admit to other equally effective embodiments. 
         FIG. 1A  depicts a partial section view of an illustrative insert for use with a plug for downhole use, according to one or more embodiments described. 
         FIG. 1B  depicts a partial section view of another illustrative embodiment of the insert for use with a plug for downhole use, according to one or more embodiments described. 
         FIG. 2A  depicts a partial section view of an illustrative plug configured with the insert of  FIG. 1 , according to one or more embodiments described. 
         FIG. 2B  depicts a partial section view of the illustrative plug configured with the insert of  FIG. 1  and a flapper valve, according to one or more embodiments described. 
         FIG. 2C  depicts a partial section view of another illustrative plug with a lower shear mechanism disposed directly on the plug body, according to one or more embodiments. 
         FIG. 3A  depicts a partial section view of the plug of  FIG. 2A  located within a casing prior to installation, according to one or more embodiments described. 
         FIG. 3B  depicts a partial section view of the plug of  FIG. 2B  located within the casing prior to installation, according to one or more embodiments described. 
         FIG. 3C  depicts a partial section view of the plug of  FIG. 2A  located in an expanded or actuated position within the casing, according to one or more embodiments described. 
         FIG. 3D  depicts a partial section view of the plug of  FIG. 2B  located in an expanded or actuated position within the casing, according to one or more embodiments described. 
         FIG. 4  depicts a partial section view of the expanded plug depicted in  FIGS. 3C and 3D , according to one or more embodiments described. 
         FIG. 5  depicts an illustrative, complementary set of angled surfaces that function as anti-rotation features to interact and/or engage between a first plug and a second plug in series, according to one or more embodiments described. 
         FIG. 6  depicts an illustrative, dog clutch anti-rotation feature, allowing a first plug and a second plug to interact and/or engage in series according to one or more embodiments described. 
         FIG. 7  depicts an illustrative, complementary set of flats and slots that serve as anti-rotation features to interact and/or engage between a first plug and a second plug in series, according to one or more embodiments described. 
         FIG. 8  depicts another illustrative, complementary set of flats and slots that serve as anti-rotation features to interact and/or engage between a first plug and a second plug in series, according to one or more embodiments described. 
     
    
    
     DETAILED DESCRIPTION 
     A plug for isolating a wellbore is provided. The plug can include one or more lower shear or shearable mechanisms for connecting to a setting tool. The lower shear or shearable mechanism can be located directly on the body of the plug or on a separate component or insert that is placed within the body of the plug. The lower shear or shearable mechanism is adapted to engage a setting tool and release the setting tool when exposed to a predetermined stress that is sufficient to deform the shearable threads to release the setting tool but is less than a stress sufficient to break the plug body. The term “stress” and “force” are used interchangeably, and are intended to refer to a system of forces that may in include axial force, radial force, and/or a combination thereof. The terms “shear mechanism” and “shearable mechanism” are used interchangeably, and are intended to refer to any component, part, element, member, or thing that shears or is capable of shearing at a predetermined stress that is less than the stress required to shear the body of the plug. The term “shear” means to fracture, break, or otherwise deform thereby releasing two or more engaged components, parts, or things or thereby partially or fully separating a single component into two or more components/pieces. The term “plug” refers to any tool used to permanently or temporarily isolate one wellbore zone from another, including any tool with blind passages, plugged mandrels, as well as open passages extending completely therethrough and passages that are blocked with a check valve. Such tools are commonly referred to in the art as “bridge plugs,” “frac plugs,” and/or “packers.” And such tools can be a single assembly (i.e. one plug) or two or more assemblies (i.e. two or more plugs) disposed within a work string or otherwise connected thereto that is run into a wellbore on a wireline, slickline, production tubing, coiled tubing or any technique known or yet to be discovered in the art. 
       FIG. 1A  depicts a partial section view of an illustrative, shearable insert  100  for a plug, according to one or more embodiments. The insert  100  can include a body  102  having a first or upper end  112  and a second or lower end  114 . A passageway or bore  110  can be completely or at least partially formed through the body  102 . One or more threads  120  can be disposed or formed on an outer surface of the body  102 . The threads  120  can be disposed on the outer surface of the body  102  toward the upper end  112 . As discussed in more detail below with reference to  FIGS. 2A-2C  and  FIGS. 3A-D , the threads  120  can be used to secure the insert  100  within a surrounding component, such as another insert  100 , setting tool, tubing string, plug, or other tool. 
       FIG. 1B  depicts a partial section view of an alternative embodiment of the illustrative, shearable insert  1 OOB for a plug. The insert  1 OOB can include any combination of features of insert  100 , and additionally, a ball  150  or other solid impediment can seat against either or both ends of the bore  110  to regulate or check fluid flow therethrough. As depicted in  FIG. 1B , the body  102  can include a shoulder  155  formed in, coupled to, or otherwise provided, which can be sized to receive the ball  150  and to seal therewith. Accordingly, the ball  150  can seat against the shoulder  155  to restrict fluid flow through the bore  110  from below the insert IOOB. An adapter pin  160  can be inserted through the body  102  to cage the ball  150  or other solid impediment in the bore  110 , between the pin  160  and the shoulder  155 . 
     One or more shearable threads  130  can be disposed or formed on an inner surface of the body  102 . The shearable threads  130  can be used to couple the insert  100 ,  1 OOB to another insert  100 ,  1 OOB, setting tool, tubing string, plug, or other tool. The shearable threads  130  can be located anywhere along the inner surface of the body  102 , and are not dependent on the location of the outer threads  120 . For example, the location of the shearable threads  130  can be located beneath or above the outer threads  120 ; toward the first end  112  of the insert  100 ,  1 OOB, as depicted in  FIGS. 1 and 1B ; and/or toward the second end  114  of the insert  100 ,  1 OOB. 
     Any number of shearable threads  130  can be used. The number, pitch, pitch angle, and/or depth of the shearable threads  130  can depend, at least in part, on the operating conditions of the wellbore where the insert  100 ,  1 OOB will be used. The number, pitch, pitch angle, and/or depth of the shearable threads  130  can also depend, at least in part, on the materials of construction of both the insert  100 ,  1 OOB and the component, e.g., another insert  100 ,  1 OOB, a setting tool, another tool, plug, tubing string, etc., to which the insert  100 ,  1 OOB is connected. The number of threads  130 , for example, can range from about 2 to about 100, such as about 2 to about 50; about 3 to about 25; or about 4 to about 10. The number of threads  130  can also range from a low of about 2, 4, or 6 to a high of about 7, 12, or 20. The pitch between each thread  130  can also vary depending on the force required to shear, break, or otherwise deform the threads  130 . The pitch between each thread  130  can be the same or different. For example, the pitch between each thread  130  can vary from about 0.1 mm to about 200 mm; 0.2 mm to about 150 mm; 0.3 mm to about 100 mm; or about 0.1 mm to about 50 mm. The pitch between each thread  130  can also range from a low of about O.1 mm, 0.2 mm, or 0.3 mm to a high of about 2 mm, 5 mm or 10 mm. 
     The shearable threads  130  can be adapted to shear, break, or otherwise deform when exposed to a predetermined stress or force, releasing the component engaged within the body  102 . The predetermined stress or force can be less than a stress and/or force required to fracture or break the body  102  of the insert  100 ,  1 OOB. Upon the threads  130  shearing, breaking, or deforming, the component engaged within the body  102  can be freely removed or separated therefrom. 
     Any number of outer threads  120  can be used. The number of outer threads  120 , for example, can range from about 2 to about 100, such as about 2 to about 50; about 3 to about 25; or about 4 to about 10. The number of threads  120  can also range from a low of about 2, 4, or 6 to a high of about 7, 12, or 20. The pitch between each thread  120  can also vary. The pitch between each thread  120  can be the same or different. For example, the pitch between each thread  120  can vary from about 0.1 mm to about 200 mm; 0.2 mm to about 150 mm; 0.3 mm to about 100 mm; or about 0.1 mm to about 50 mm. The pitch between each thread  120  can also range from a low of about 0.1 mm, 0.2 mm, or 0.3 mm to a high of about 2 mm, 5 mm or 10 mm. 
     The threads  120  and the shearable threads  130  can be right-handed and/or left-handed threads. For example, to facilitate connection of the insert  100 ,  1 OOB to a setting tool when the setting tool is coupled to, for example, screwed into the insert  100 ,  1 OOB, the threads  120  can be right-handed threads and the shearable threads  130  can be left-handed threads, or vice versa. 
     The outer surface of the insert  100 ,  1 OOB can have a constant diameter, or its diameter can vary, as depicted in  FIGS. 1A and 1B . For example, the outer surface can include a smaller first diameter portion or area  140  that transitions to a larger, second diameter portion or area  142 , forming a ledge or shoulder  144  therebetween. The shoulder  144  can have a first end that is substantially flat, abutting the second diameter  142 , a second end that gradually slopes or transitions to the first diameter  140 , and can be adapted to anchor the insert into the plug. The shoulder  144  can be formed adjacent the outer threads  120  or spaced apart therefrom, and the outer threads  120  can be above or below the shoulder  144 . 
     The insert  100 ,  1 OOB and/or the shearable threads  130  can be made of an alloy that includes brass. Suitable brass compositions include, but are not limited to, admiralty brass, Aich&#39;s alloy, alpha brass, alpha-beta brass, aluminum brass, arsenical brass, beta brass, cartridge brass, common brass, dezincification resistant brass, gilding metal, high brass, leaded brass, lead-free brass, low brass, manganese brass, Muntz metal, nickel brass, naval brass, Nordic gold, red brass, rich low brass, tonval brass, white brass, yellow brass, and/or any combinations thereof. 
     The insert  100 ,  1 OOB can also be formed or made from other metallic materials (such as aluminum, steel, stainless steel, copper, nickel, cast iron, galvanized or non-galvanized metals, etc.), fiberglass, wood, composite materials (such as ceramics, wood/polymer blends, cloth/polymer blends, etc.), and plastics (such as polyethylene, polypropylene, polystyrene, polyurethane, polyethylethylketone (PEEK), polytetrafluoroethylene (PTFE), polyamide resins (such as nylon 6 (N6), nylon 66 (N66)), polyester resins (such as polybutylene terephthalate (PBT), polyethylene terephthalate (PET), polyethylene isophthalate (PEI), PET/PEI copolymer) polynitrile resins (such as polyacrylonitrile (PAN), polymethacrylonitrile, aerylonitrile-styrene copolymers (AS), methacrylonitrile-styrene copolymers, methacrylonitrile-styrene-butadiene copolymers; and acrylonitrile-butadiene-styrene (ABS)), polymethacrylate resins (such as polymethyl methacrylate and polyethylacrylate), cellulose resins (such as cellulose acetate and cellulose acetate butyrate); polyimide resins (such as aromatic polyimides), polycarbonates (PC), elastomers (such as ethylene-propylene rubber (EPR), ethylene propylene-diene monomer rubber (EPDM), styrenic block copolymers (SBC), polyisobutylene (PIB), butyl rubber, neoprene rubber, halobutyl rubber and the like)), as well as mixtures, blends, and copolymers of any and all of the foregoing materials. 
       FIG. 2A  depicts a partial section view of an illustrative plug  200  configured with the insert  100 ,  1 OOB and adapted to receive a ball type impediment or another type of impediment, according to one or more embodiments. The plug  200  can include a mandrel or body  210  having a first or upper end  207  and a second or lower end  208 . A passageway or bore  255  can be formed at least partially through the body  210 . The body  210  can be a single, monolithic component as shown, or the body  210  can be or include two or more components connected, engaged, or otherwise attached together. The body  210  serves as a centralized support member, made of one or more components or parts, for one or more outer components to be disposed thereon or thereabout. 
     The insert  100 ,  1 OOB can be threaded or otherwise disposed within the plug  200  at a lower end  208  of the body  210 . A setting tool, tubing string, plug, or other tool can enter the bore  255  through the first end  207  of the body  210  and can be threaded to or otherwise coupled to and/or disposed within the insert  100 . As further described herein, the shearable threads  130  on the insert  100  can be sheared, fractured, or otherwise deformed, releasing the setting tool, tubing string, plug, or other tool from the plug  200 . 
     The bore  255  can have a constant diameter throughout, or its diameter can vary, as depicted in  FIG. 2A . For example, the bore  255  can include a larger, first diameter portion or area  226  that transitions to a smaller, second diameter portion or area  227 , forming a seat or shoulder  228  therebetween. The shoulder  228  can have a tapered or sloped surface connecting the two diameter portions or areas  226 ,  227 . Although not shown, the shoulder  228  can be flat or substantially flat, providing a horizontal or substantially horizontal surface connecting the two diameters  226 ,  227 . As will be explained in more detail below, the shoulder  228  can serve as a seat or receiving surface for plugging off the bore  255  when a ball (shown in  FIG. 3C ) or other impediment, such as a flapper member  215  (shown in  FIG. 3D ), is placed within the bore  255 . 
     At least one conical member (two are shown:  230 ,  235 ), at least one slip (two are shown:  240 ,  245 ), and at least one malleable element  250  can be disposed about the body  210 . As used herein, the term “disposed about” means surrounding the component, e.g., the body  210 , allowing for relative movement therebetween (e.g., by sliding, rotating, pivoting, or a combination thereof). A first section or second end of the conical members  230 ,  235  has a sloped surface adapted to rest underneath a complementary sloped inner surface of the slips  240 ,  245 . As explained in more detail below, the slips  240 ,  245  travel about the surface of the adjacent conical members  230 ,  235 , thereby expanding radially outward from the body  210  to engage an inner surface of a surrounding tubular or borehole. A second section or second end of the conical members  230 ,  235  can include two or more tapered pedals or wedges adapted to rest about an adjacent malleable element  250 . One or more circumferential voids  236  can be disposed within or between the first and second sections of the conical members  230 ,  235  to facilitate expansion of the wedges about the malleable element  250 . The wedges are adapted to hinge or pivot radially outward and/or hinge or pivot circumferentially. The groove or void  236  can facilitate such movement. The wedges pivot, rotate, or otherwise extend radially outward, and can contact an inner diameter of the surrounding tubular or borehole. Additional details of the conical members  230 ,  235  are described in U.S. Pat. No. 7,762,323. 
     The inner surface of each slip  240 ,  245  can conform to the first end of the adjacent conical member  230 ,  235 . An outer surface of the slips  240 ,  245  can include at least one outwardly-extending serration or edged tooth to engage an inner surface of a surrounding tubular, as the slips  240 ,  245  move radially outward from the body  210  due to the axial movement across the adjacent conical members  230 ,  235 . 
     The slips  240 ,  245  can be designed to fracture with radial stress. The slips  240 ,  245  can include at least one recessed groove  242  milled or otherwise formed therein to fracture under stress allowing the slips  240 ,  245  to expand outward and engage an inner surface of the surrounding tubular or borehole. For example, the slips  240 ,  245  can include two or more, for example, four, sloped segments separated by equally-spaced recessed grooves  242  to contact the surrounding tubular or borehole. 
     The malleable element  250  can be disposed between the conical members  230 ,  235 . A three element  250  system is depicted in  FIG. 2A , but any number of elements  250  can be used. The malleable element  250  can be constructed of any one or more malleable materials capable of expanding and sealing an annulus within the wellbore. The malleable element  250  is preferably constructed of one or more synthetic materials capable of withstanding high temperatures and pressures, including temperatures up to 450° F., and pressure differentials up to 15,000 psi. Illustrative materials include elastomers, rubbers, TEFLON®, blends and combinations thereof. 
     The malleable element(s)  250  can have any number of configurations to effectively seal the annulus defined between the body  210  and the wellbore. For example, the malleable element(s)  250  can include one or more grooves, ridges, indentations, or protrusions designed to allow the malleable element(s)  250  to conform to variations in the shape of the interior of the surrounding tubular or borehole. 
     At least one component, ring, or other annular member  280  for receiving an axial load from a setting tool can be disposed about the body  210  adjacent a first end of the slip  240 . The annular member  280  for receiving the axial load can have first and second ends that are substantially flat. The first end can serve as a shoulder adapted to abut a setting tool (not shown). The second end can abut the slip  240  and transmit axial forces therethrough. 
     Each end of the plug  200  can be the same or different. Each end of the plug  200  can include one or more anti-rotation features  270 , disposed thereon. Each anti-rotation feature  270  can be screwed onto, formed thereon, or otherwise connected to or positioned about the body  210  so that there is no relative motion between the anti-rotation feature  270  and the body  210 . Alternatively, each anti-rotation feature  270  can be screwed onto or otherwise connected to or positioned about a shoe, nose, cap, or other separate component, which can be made of composite, that is screwed onto threads, or otherwise connected to or positioned about the body  210  so that there is no relative motion between the anti-rotation feature  270  and the body  210 . The anti-rotation feature  270  can have various shapes and forms. For example, the anti-rotation feature  270  can be or can resemble a mule shoe shape (not shown), half-mule shoe shape (illustrated in  FIG. 5 ), flat protrusions or flats (illustrated in  FIGS. 7 and 8 ), clutches (illustrated in  FIG. 6 ), or otherwise angled surfaces  285 ,  290 ,  295  (illustrated in  FIGS. 2A, 2B, 2C, 3A, 3B, 3C, 3D and 5 ). 
     As explained in more detail below, the anti-rotation features  270  are intended to engage, connect, or otherwise contact an adjacent plug, whether above or below the adjacent plug, to prevent or otherwise retard rotation therebetween, facilitating faster drill-out or mill times. For example, the angled surfaces  285 ,  290  at the bottom of a first plug  200  can engage the sloped surface  295  at the top of a second plug  200  in series, so that relative rotation therebetween is prevented or greatly reduced. 
     A pump down collar  275  can be located about a lower end of the plug  200  to facilitate delivery of the plug  200  into the wellbore. The pump down collar  275  can be a rubber O-ring or similar sealing member to create an impediment in the wellbore during installation, so that a push surface or resistance can be created. 
       FIG. 2B  depicts a partial section view of the illustrative plug  200  configured with a flapper-type impediment for regulating flow through the bore  255 , according to one or more embodiments. The flapper-type impediment can include a flapper member  215  connected to the body  210  using one or more pivot pins  216 . The flapper member  215  can be flat or substantially flat. Alternatively, the flapper member  215  can have an arcuate shape, with a convex upper surface and a concave lower surface. A spring (not shown) can be disposed about the one or more pivot pins  216  to urge the flapper member  215  from a run-in (“first” or “open”) position wherein the flapper member  215  does not obstruct the bore  255  through the plug  200 , to an operating (“second” or “closed”) position, as depicted in  FIG. 2B , where the flapper member  215  assumes a position proximate to the shoulder or valve seat  228 , transverse to the bore  255  of the plug  200 . At least a portion of the spring can be disposed upon or across the upper surface of the flapper member  215  providing greater contact between the spring and the flapper member  215 , offering greater leverage for the spring to displace the flapper member  215  from the run-in position to the operating position. In the run-in position, bi-directional, e.g., upward and downward or side to side, fluid communication through the plug  200  can occur. In the operating position, unidirectional, e.g., upward. as shown. 
     As used herein the term “arcuate” refers to any body, member, or thing having a cross-section resembling an arc. For example, a flat, elliptical member with both ends along the major axis turned downwards by a generally equivalent amount can form an arcuate member. The terms “up” and “down”; “upward” and “downward”; “upper” and “lower”; “upwardly” and “downwardly”; “upstream” and “downstream”; “above” and “below”; and other like terms as used herein refer to relative positions to one another and are not intended to denote a particular spatial orientation since the tool and methods of using same can be equally effective in either horizontal or vertical wellbore uses. Additional details of a suitable flapper assembly can be found in U.S. Pat. No. 7,708,066, which is incorporated by reference herein in its entirety. 
       FIG. 2C  depicts a partial section view of another illustrative plug  200  with a lower shear mechanism disposed directly on the plug body, according to one or more embodiments. This is an alternative configuration where one or more shearable threads  130 A are formed directly on the inner surface of the bore  255 . No insert  100 ,  1 OOB is needed. The shearable threads  130 A can be made of the same composite material as the body  210  of the plug  200 , or can be made from a different material. 
     Any number of shearable threads  130 A can be used. The number of shearable threads  130 A can depend, at least in part, on the operating conditions and/or environment of the wellbore where the plug  200  will be used. The number of threads  130 A, for example, can range from about 2 to about 100, such as about 2 to about 50; about 3 to about 25; or about 4 to about 10. The number of threads  130 A can also range from a low of about 2, 4, or 6 to a high of about 7, 12, or 20. 
     The pitch of the threads BOA can also vary depending on the force required to shear, break, or otherwise deform the threads BOA. The pitch of the threads BOA can be the same or different. For example, the spacing between each thread  130 A can vary from about 0.1 mm to about 200 mm; 0.2 mm to about 150 mm; 0.3 mm to about 100 mm; or about 0.1 mm to about 50 mm. The spacing between each thread  120  can also range from a low of about 0.1 mm, 0.2 mm, or 0.3 mm to a high of about 2 mm, 5 mm or 10 mm. 
     The shearable threads BOA can be adapted to shear, break, or otherwise deform when exposed to a predetermined stress or force, releasing the component engaged within the body  210 . The predetermined stress or force is preferably less than a stress or force required to fracture, break, or otherwise significantly deform the body  210 . Upon the threads  130 A shearing, breaking, or deforming, the component engaged within the plug  200  can be freely removed or separated therefrom. The component engaged within the plug  200  via the shearable threads  130 A or insert  100  will typically be a rod or extender from a setting tool used to install the plug  200  within a wellbore. 
       FIG. 3A  depicts a partial section view of the plug  200  depicted in  FIG. 2A , prior to installation or actuation but after being disposed within casing  300 , according to one or more embodiments.  FIG. 3B  depicts a partial section view of the plug  200  depicted in  FIG. 2B , prior to installation or actuation but after being disposed within casing  300 , according to one or more embodiments. 
     The plug  200  can be installed in a vertical, horizontal, or deviated wellbore using any suitable setting tool adapted to engage the plug  200 . One example of such a suitable setting tool or assembly includes a gas operated outer cylinder powered by combustion products and an adapter rod. The outer cylinder of the setting tool abuts an outer, upper end of the plug  200 , such as against the annular member  280 . The outer cylinder can also abut directly against the upper slip  240 , for example, in embodiments of the plug  200  where the annular member  280  is omitted, or where the outer cylinder fits over or otherwise avoids bearing on the annular member  280 . The adapter rod  310  is threadably connected to the body  210  and/or the insert  100 . Suitable setting assemblies that are commercially-available include the Owen Oil Tools wireline pressure setting assembly or a Model 10, 20 E-4, or E-5 Setting Tool available from Baker Oil Tools, for example. 
     During the setting process, the outer cylinder (not shown) of the setting tool exerts an axial force against the outer, upper end of the plug  200  in a downward direction that is matched by the adapter rod  310  of the setting tool exerting an equal and opposite force from the lower end of the plug  200  in an upward direction. For example, in the embodiment illustrated in  FIGS. 3A and 3B , the outer cylinder of the setting assembly exerts an axial force on the annular member  280 , which translates the force to the slips  240 ,  245  and the malleable elements  250  that are disposed about the body  210  of the plug  200 . The translated force fractures the recessed groove(s)  242  of the slips  240 ,  245 , allowing the slips  240 ,  245  to expand outward and engage the inner surface of the casing or wellbore  300 , while at the same time compresses the malleable elements  250  to create a seal between the plug  200  and the inner surface of the casing or wellbore  300 , as shown in  FIG. 4 .  FIG. 4  depicts an illustrative partial section view of the expanded or actuated plug  200 , according to one or more embodiments described. 
     After actuation or installation of the plug  200 , the setting tool can be released from the shearable threads  130 , BOA of the plug  200 , or the insert  100  that is screwed into the plug  200  by continuing to apply the opposing, axial forces on the body  210  via the adapter rod  310  and the outer cylinder. The opposing, axial forces applied by the outer cylinder and the adapter rod  310  result in a compressive load on the body  210 , which is borne as internal stress once the plug  200  is actuated and secured within the casing or wellbore  300 . The force or stress is focused on the shearable threads  130 ,  130 A, which will eventually shear, break, or otherwise deform at a predetermined amount, releasing the adapter rod  310  therefrom. The predetermined axial force sufficient to deform the shearable threads  130  and/or  130 A to release the setting tool is less than an axial force sufficient to break the plug body  210 . 
     Using a lower set mechanism, be it the insert  100  or shearable threads  130 A directly on the body  210 , allows the plug  200  to be squeezed from opposing ends. This provides a more balanced and efficient translation of force to the moveable components about the body  210 , and reduces the stress directly applied to the body  210  itself. As such, the body  210  and a majority of the outer components of the plug  200  can be made of a softer, drillable material, such as a composite material, since the stress being asserted thereon during the setting process is reduced. Conventional cast iron and other metallic plugs are set from the upper end of the plug, which translates all of the force needed to squeeze and actuate the plug on the plug body itself. As such, the plug body had to be constructed of a more rigid material capable of withstanding such stress and torque. The lower set mechanism described herein, however, alleviates the torque and stress on the plug body  210 , allowing the plug body  210  to be made of lighter, more easily drillable, non-metallic materials. 
     Once actuated and released from the setting tool, the plug  200  is left in the wellbore to serve its purpose, as depicted in  FIGS. 3C and 3D . For example, a ball  320  can be dropped in the wellbore to constrain, restrict, and/or prevent fluid communication in a first direction through the body  210 . For example, the dropped ball  320  can rest on the transition or ball seat  228  to form an essentially fluid-tight seal therebetween, as depicted in  FIG. 3C , preventing downward fluid flow through the plug  200  (“the first direction”) while allowing upward fluid flow through the plug  200  (“the second direction”). Alternatively, the flapper member  215  can rotate toward the closed position to constrain, restrict, and/or prevent downward fluid flow through the plug  200  (“the first direction”) while allowing upward fluid flow through the plug  200  (“the second direction”), as depicted in  FIG. 3D . 
     The ball  150 ,  320  or the flapper member  215  can be fabricated from one or more decomposable materials. Suitable decomposable materials will decompose, degrade, degenerate, or otherwise fall apart at certain wellbore conditions or environments, such as predetermined temperature, pressure, pH, and/or any combinations thereof. As such, fluid communication through the plug  200  can be prevented for a predetermined period of time, e.g., until and/or if the decomposable material(s) degrade sufficiently allowing fluid flow therethrough. The predetermined period of time can be sufficient to pressure test one or more hydrocarbon-bearing zones within the wellbore. In one or more embodiments, the predetermined period of time can be sufficient to workover the associated well. The predetermined period of time can range from minutes to days. For example, the degradable rate of the material can range from about 5 minutes, 40 minutes, or 4 hours to about 12 hours, 24 hours or 48 hours. Extended periods of time are also contemplated. 
     The pressures at which the ball  150 ,  320  or the flapper member  215  decompose can range from about 100 psig to about 15,000 psig. For example, the pressure can range from a low of about 100 psig, 1,000 psig, or 5,000 psig to a high about 7,500 psig, 10,000 psig, or about 15,000 psig. The temperatures at which the ball  320  or the flapper member  215  decompose can range from about 100° F. to about 750° F. For example, the temperature can range from a low of about 100° F., 150° F., or 200° F. to a high of about 350° F., 500° F., or 750° F. 
     The decomposable material can be soluble in any material, such as soluble in water, polar solvents, non-polar solvents, acids, bases, mixtures thereof, or any combination thereof. The solvents can be time-dependent solvents. A time-dependent solvent can be selected based on its rate of degradation. For example, suitable solvents can include one or more solvents capable of degrading the soluble components in about 30 minutes, 1 hour, or 4 hours to about 12 hours, 24 hours, or 48 hours. Extended periods of time are also contemplated. 
     The pHs at which the ball  150 ,  320  or the flapper member  215  can decompose can range from about 1 to about 14. For example, the pH can range from a low of about 1, 3, or 5 to a high about 9, 11, or about 14. 
     To remove the plug  200  from the wellbore, the plug  200  can be drilled-out, milled, or otherwise compromised. As it is common to have two or more plugs  200  located in a single wellbore to isolate multiple zones therein, during removal of one or more plugs  200  from the well bore some remaining portion of a first, upper plug  200  can release from the wall of the wellbore at some point during the drill-out. Thus, when the remaining portion of the first, upper plug  200  falls and engages an upper end of a second, lower plug  200 , the anti-rotation features  270  of the remaining portions of the plugs  200  will engage and prevent, or at least substantially reduce, relative rotation therebetween. 
       FIGS. 5-8  depict schematic views of illustrative anti-rotation features that can be used with the plugs  200  to prevent or reduce rotation during drill-out. These features are not intended to be exhaustive, but merely illustrative, as there are many other configurations that are effective to accomplish the same results. Each end of the plug  200  can be the same or different. For example,  FIG. 5  depicts angled surfaces or half-mule anti-rotation features;  FIG. 6  depicts dog clutch type anti-rotation features; and  FIGS. 7 and 8  depict two flat and slot type anti-rotation features. 
     Referring to  FIG. 5 , a lower end of an upper plug SOOA and an upper end of a lower plug SOOB are shown within the casing  300  where the angled surfaces  285 ,  290  interact with, interface with, interconnect, interlock, link with, join, jam with or within, wedge between, or otherwise communicate with a complementary angled surface  295  and/or at least a surface of the wellbore or casing  300 . The interaction between the lower end of the upper plug SOOA and the upper end of the lower plug SOOB and/or the casing  300  can counteract a torque placed on the lower end of the upper plug SOOA, and prevent or greatly reduce rotation therebetween. For example, the lower end of the upper plug SOOA can be prevented from rotating within the wellbore or casing  300  by the interaction with upper end of the lower plug SOOB, which is held securely within the casing  300 . 
     Referring to  FIG. 6 , dog clutch surfaces of the upper plug  600 A can interact with, interface with, interconnect, interlock, link with, join, jam with or within, wedge between, or otherwise communicate with a complementary dog clutch surface of the lower plug  600 B and/or at least a surface of the wellbore or casing  300 . The interaction between the lower end of the upper plug  600 A and the upper end of the lower plug  600 B and/or the casing  300  can counteract a torque placed on the lower end of the upper plug  600 A, and prevent or greatly reduce rotation therebetween. For example, the lower end of the upper plug  600 A can be prevented from rotating within the wellbore or casing  300  by the interaction with upper end of the lower plug  600 B, which is held securely within the casing  300 . 
     Referring to  FIG. 7 , the flats and slot surfaces of the upper plug  700 A can interact with, interface with, interconnect, interlock, link with, join, jam with or within, wedge between, or otherwise communicate with complementary flats and slot surfaces of the lower plug  700 B and/or at least a surface of the wellbore or casing  300 . The interaction between the lower end of the upper plug  700 A and the upper end of the lower plug  700 B and/or the casing  300  can counteract a torque placed on the lower end of the upper plug  700 A, and prevent or greatly reduce rotation therebetween. For example, the lower end of the upper plug  700 A can be prevented from rotating within the wellbore or casing  300  by the interaction with upper end of the lower plug  700 B, which is held securely within the casing  300 . The protruding perpendicular surfaces of the lower end of the upper plug  700 A can mate in the perpendicular voids of the upper end of the lower plug  700 B. When the lower end of the upper plug  700 A and the upper end of the lower plug  700 B are mated, any further rotational force applied to the lower end of the upper plug  700 A will be resisted by the engagement of the lower plug  700 B with the wellbore or casing  300 , translated through the mated surfaces of the anti-rotation feature  270 , allowing the lower end of the upper plug  700 A to be more easily drilled-out of the wellbore. 
     One alternative configuration of flats and slot surfaces is depicted in  FIG. 8 . The protruding cylindrical or semi-cylindrical surfaces  810  perpendicular to the base  801  of the lower end of the upper plug  800 A mate with the complementary aperture(s)  820  in the complementary base  802  of the upper end of the lower plug  800 B. Protruding surfaces  810  can have any geometry perpendicular to the base  801 , as long as the complementary aperture(s)  820  match the geometry of the protruding surfaces  801  so that the surfaces  801  can be threaded into the aperture(s)  820  with sufficient material remaining in the complementary base  802  to resist rotational force that can be applied to the lower end of the upper plug  800 A, and thus translated to the complementary base  802  by means of the protruding surfaces  801  being inserted into the aperture(s)  820  of the complementary base  802 . The anti-rotation feature  270  may have one or more protrusions or apertures  830 , as depicted in  FIG. 8 , to guide, interact with, interface with, interconnect, interlock, link with, join, jam with or within, wedge between, or otherwise communicate or transmit force between the lower end of the upper plug  800 A and the upper end of the lower plug  800 B. The protrusion or aperture  830  can be of any geometry practical to further the purpose of transmitting force through the anti-rotation feature  270 . 
     The orientation of the components of the anti-rotation features  270  depicted in all figures is arbitrary. Because plugs  200  can be installed in horizontal, vertical, and deviated wellbores, either end of the plug  200  can have any anti-rotation feature  270  geometry, wherein a single plug  200  can have one end of a first geometry and one end of a second geometry. For example, the anti-rotation feature  270  depicted in  FIG. 5  can include an alternative embodiment where the lower end of the upper plug  500 A is manufactured with geometry resembling  500 B and vice versa. Each end of each plug  200  can be or include angled surfaces, half-mule, mule shape, dog clutch, flat and slot, cleated, slotted, spiked, and/or other interdigitating designs. In the alternative to a plug with complementary anti-rotation feature  270  geometry on each end of the plug  200 , a single plug  200  can include two ends of differently-shaped anti-rotation features, such as the upper end may include a half-mule anti-rotation feature  270 , and the lower end of the same plug  200  may include a dog clutch type anti-rotation feature  270 . Further, two plugs  200  in series may each comprise only one type of anti-rotation feature  270  each, however the interface between the two plugs  200  may result in two different anti-rotation feature  270  geometries that can interface with, interconnect, interlock, link with, join, jam with or within, wedge between, or otherwise communicate or transmit force between the lower end of the upper plug  200  with the first geometry and the upper end of the lower plug  200  with the second geometry. 
     Any of the aforementioned components of the plug  200 , including the body, rings, cones, elements, shoe, anti-rotation features, etc., can be formed or made from any one or more non-metallic materials or one or more metallic materials (such as aluminum, steel, stainless steel, brass, copper, nickel, cast iron, galvanized or non-galvanized metals, etc.). Suitable non-metallic materials include, but are not limited to, fiberglass, wood, composite materials (such as ceramics, wood/polymer blends, cloth/polymer blends, etc.), and plastics (such as polyethylene, polypropylene, polystyrene, polyurethane, polyethylethylketone (PEEK), polytetrafluoroethylene (PTFE), polyamide resins (such as nylon 6 (N6), nylon 66 (N66)), polyester resins (such as polybutylene terephthalate (PBT), polyethylene terephthalate (PET), polyethylene isophthalate (PEI), PET/PET copolymer) polynitrile resins (such as polyacrylonitrile (PAN), polymethacrylonitrile, acrylonitrile-styrene copolymers (AS), methacrylonitrile-styrene copolymers, methacrylonitrile-styrene-butadiene copolymers; and acrylonitrile-butadiene-styrene (ABS)), polymethacrylate resins (such as polymethyl methacrylate and polyethylacrylate), cellulose resins (such as cellulose acetate and cellulose acetate butyrate); polyimide resins (such as aromatic polyimides), polycarbonates (PC), elastomers (such as ethylene-propylene rubber (EPR), ethylene propylene-diene monomer rubber (EPDM), styrenic block copolymers (SBC), polyisobutylene (PIB), butyl rubber, neoprene rubber, halobutyl rubber and the like)), as well as mixtures, blends, and copolymers of any and all of the foregoing materials. 
     However, as many components as possible are made from one or more non-metallic materials, and preferably made from one or more composite materials. Desirable composite materials can be or include polymeric composite materials that are wound and/or reinforced by one or more fibers such as glass, carbon, or aramid, for example. The individual fibers can be layered parallel to each other, and wound layer upon layer. Each individual layer can be wound at an angle of from about 20 degrees to about 160 degrees with respect to a common longitudinal axis, to provide additional strength and stiffness to the composite material in high temperature and/or pressure downhole conditions. The particular winding phase can depend, at least in part, on the required strength and/or rigidity of the overall composite material. 
     The polymeric component of the composite can be an epoxy blend. The polymer component can also be or include polyurethanes and/or phenolics, for example. In one aspect, the polymeric composite can be a blend of two or more epoxy resins. For example, the polymeric composite can be a blend of a first epoxy resin of bisphenol A and epichlorohydrin and a second cycoaliphatic epoxy resin. Preferably, the cycloaphatic epoxy resin is ARALDITE® RTM liquid epoxy resin, commercially available from Ciga-Geigy Corporation of Brewster, N.Y. A 50:50 blend by weight of the two resins has been found to provide the suitable stability and strength for use in high temperature and/or pressure applications. The 50:50 epoxy blend can also provide suitable resistance in both high and low pH environments. 
     The fibers can be wet wound. A prepreg roving can also be used to form a matrix. The fibers can also be wound with and/or around, spun with and/or around, molded with and/or around, or hand laid with and/or around a metallic material or two or more metallic materials to create an epoxy impregnated metal or a metal impregnated epoxy. 
     A post cure process can be used to achieve greater strength of the material. A suitable post cure process can be a two stage cure having a gel period and a cross-linking period using an anhydride hardener, as is commonly known in the art. Heat can be added during the curing process to provide the appropriate reaction energy that drives the cross-linking of the matrix to completion. The composite may also be exposed to ultraviolet light or a high-intensity electron beam to provide the reaction energy to cure the composite material. 
     Certain embodiments and features have been described using a set of numerical upper limits and a set of numerical lower limits. It should be appreciated that ranges from any lower limit to any upper limit are contemplated unless otherwise indicated. Certain lower limits, upper limits and ranges appear in one or more claims below. All numerical values are “about” or “approximately” the indicated value, and take into account experimental error and variations that would be expected by a person having ordinary skill in the art. 
     Various terms have been defined above. To the extent a term used in a claim is not defined above, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent. Furthermore, all patents, test procedures, and other documents cited in this application are fully incorporated by reference to the extent such disclosure is not inconsistent with this application and for all jurisdictions in which such incorporation is permitted. 
     While the foregoing is directed to embodiments of the present invention, other and further embodiments of the invention can be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.