Patent Publication Number: US-2022228460-A1

Title: Convertiball

Description:
BACKGROUND 
     1. Field 
     The present disclosure relates generally to plugs that may be used to isolate a portion of a well, and more particularly, to plugs that may be used in fracturing or other processes for stimulating oil and gas wells. 
     2. Description of the Related Art 
     Hydrocarbons, such as oil and gas, may be recovered from various types of subsurface geological formations. The formations typically consist of a porous layer, such as limestone and sands, overlaid by a nonporous layer. Hydrocarbons cannot rise through the nonporous layer. Thus, the porous layer forms a reservoir, that is, a volume in which hydrocarbons accumulate. A well is drilled through the earth until the hydrocarbon bearing formation is reached. Hydrocarbons then are able to flow from the porous formation into the well. 
     In the most basic form of rotary drilling methods, a drill bit is attached to a series of pipe sections or “joints” referred to as a drill string. The drill string is suspended from a derrick and rotated by a motor in the derrick. A drilling fluid or “mud” is pumped down the drill string, through the bit, and into the bore of the well. This fluid serves to lubricate the bit. The drilling mud also carries cuttings from the drilling process back to the surface as it travels up the wellbore. As the drilling progresses downward, the drill string is extended by adding more joints of pipe. 
     A modern oil well typically includes a number of tubes extending wholly or partially within other tubes. That is, a well is first drilled to a certain depth. Large diameter pipes, or casings, are placed in the well and cemented in place to prevent the sides of the borehole from caving in. The casing is cemented in the well by injecting a cement slurry down the casing, out the bottom of the casing, and up into the well annulus, that it, the gap between the casing and the bore of the well. The cement then is allowed to harden into a continuous seal throughout the annulus. 
     After the initial section has been drilled, cased, and cemented, drilling will proceed with a somewhat smaller wellbore. The smaller bore is lined with large, but somewhat smaller pipes or “liners.” The liner is suspended from the original or “host” casing by an anchor or “hanger.” A well may include a series of smaller liners, and may extend for many thousands of feet, commonly up to and over 25,000 feet. 
     Hydrocarbons, however, are not always able to flow easily from a formation to a well. Some subsurface formations, such as sandstone, are very porous. Hydrocarbons can flow easily from the formation into a well. Other formations, however, such as shale rock, limestone, and coal beds, are only minimally porous. The formation may contain large quantities of hydrocarbons, but production through a conventional well may not be commercially practical because hydrocarbons flow though the formation and collect in the well at very low rates. The industry, therefore, relies on various techniques for improving the well and stimulating production from formations and especially from formations that are relatively nonporous. 
     Perhaps the most important stimulation technique is the combination of horizontal wellbores and hydraulic fracturing. A well will be drilled vertically until it approaches a formation. It then will be diverted, and drilled in a more or less horizontal direction, so that the borehole extends along the formation instead of passing through it. More of the formation is exposed to the borehole, and the average distance hydrocarbons must flow to reach the well is decreased. Fractures then are created in the formation which will allow hydrocarbons to flow more easily from the formation. 
     Fracturing a formation is accomplished by pumping fluid, most commonly water, into the well at high pressure and flow rates. Proppants, such as grains of sand, ceramic or other particulates, usually are added to the fluid along with gelling agents to create a slurry. The slurry is forced into the formation at rates faster than can be accepted by the existing pores, fractures, faults, vugs, caverns, or other spaces within the formation. Pressure builds rapidly to the point where the formation fails and begins to fracture. Continued pumping of fluid into the formation will tend to cause the initial fractures to widen and extend further away from the wellbore, creating flow paths to the well. The proppant serves to prevent fractures from closing when pumping is stopped. 
     A formation rarely will be fractured all at once. It typically will be fractured in many different locations or zones and in many different stages. Fluids will be pumped into the well to fracture the formation in a first zone. After the initial zone is fractured, pumping is stopped, and a plug is installed in the liner at a point above the fractured zone. Pumping is resumed, and fluids are pumped into the well to fracture the formation in a second zone located above the plug. That process is repeated for zones further up the formation until the formation has been completely fractured. 
     Fracturing typically involves installing a production liner in the portion of the wellbore passing through the hydrocarbon bearing formation. The production liner may incorporate valves, typically sliding sleeve “ball-drop” valves. The valve may be actuated by deploying a ball into the valve to open ports in the valve and to plug the valve below the ports. The ball restricts flow through the liner and diverts fluid through the ports and into the formation. Once fracturing is complete various operations will be performed to remove the balls and allow fluids from the formation to enter the liner and travel to the surface. 
     In many wells, however, the production liner does not incorporate valves. Instead, fracturing will be accomplished by “plugging and perfing” the liner. In a “plug and perf” job, the production liner is made up from standard joints of liner. The liner does not have any openings through its sidewalls, nor does it incorporate frac valves. It is installed in the wellbore and perforated, that is, holes are punched in the liner walls. The perforations typically are created by so-called “perf” guns which discharge shaped charges through the liner and, if present, adjacent cement. 
     A plug and perf operation can allow a well to be fractured at many different locations in many distinct stages. The liner typically will be perforated first in a zone near the bottom of the well. Fluids then are pumped into the well to fracture the formation in the vicinity of the bottom perforations. Alternately, an initiator or “toe” valve may be incorporated into the liner and used to fracture the initial, bottom zone. 
     After the bottom zone is fractured, a tool string is deployed into the liner. The tool string typically includes a plug, a setting tool, and perf guns. The plug is positioned at a location above the fractured zone and then installed by actuating the setting tool. Once the plug is set, the perf guns are fired to perforate the liner again, this time in a second zone located above the plug. The tool string, less the plug, then is withdrawn from the liner. Very commonly, the plug will be a “ball drop” plug which is shut by deploying or “dropping” a ball onto the plug. The ball will restrict fluids from flowing through and past the plug. When fluids are injected into the liner, therefore, they will be forced to flow out the perforations and into the second zone. After the second zone is fractured, the process is repeated with additional plugs until all zones in the well are fractured. 
     After the well has been fractured, however, plugs may interfere with installation of production equipment in the liner. They also may restrict the flow of production fluids upward through the liner. Thus, the plugs typically are removed from the liner after the well has been fractured, most commonly by drilling out the plugs. Most plugs will be fabricated from softer, more easily drillable materials such as composites and cast iron to speed up that process. 
     Many conventional ball drop plugs, especially those incorporating composite materials, have a common basic design built around a central support mandrel. The support mandrel is generally cylindrical and somewhat elongated. It has a central conduit extending axially through it. The support mandrel serves as a core for the plug and provides support for the other plug components. The other plug components—slips, wedges, and sealing elements—are all generally annular and are carried on and around the support mandrel in an array extending along the length of the mandrel. The plug is set by squeezing the components together to expand the slips and sealing elements radially outward into contact with the liner. 
     The support mandrel has a ball seat at or very near the upper end of the mandrel central conduit. Once the plug is installed, and the setting tool withdrawn, fluids can flow in both directions through the central conduit. When a ball is deployed onto the ball seat, however, the ball will restrict fluid from flowing downward through the plug. Such designs are well known in the art and variations thereof are disclosed, for example, in U.S. Pat. No. 7,475,736 to D. Lehr et al., U.S. Pat. No. 7,789,137 to R. Turley et al., U.S. Pat. No. 8,047,280 to L. Tran et al., and U.S. Pat. No. 9,316,086 to D. VanLue. Plugs of that general design also are commercially available from many different manufacturers, such as the Diamondback composite drillable frac plug available from Schlumberger, Houston, Tex., and the TruFrac composite frac plug available from Weatherford, Houston, Tex. 
     Ball drop plugs, however, do not allow an operator to easily pressure test a plug to ensure that it has been installed properly—the liner typically will have been perforated by the time a ball is deployed. Moreover, a significant amount of fluid must be pumped into a well to deploy balls into the valves, and especially into valves installed in horizontal portions of a well. A ball cannot drop into a plug under the influence of gravity alone. Water may be hard to come by and costly. Disposal or recycling of frac fluids also may be difficult or expensive. Thus, some operators prefer to pump a ball into the well with the plug. The plug may be pressure tested before the perf guns are fired, and the ball may be seated in the plug with little or no extra fluid. 
     “Caged ball” frac plugs represent one approach to accomplish that. Caged ball plugs incorporate a cage or some other sort of restrictor above the ball seat in the plug. A ball is installed in the cage before the plug is run into a well. Thus, the plug may be pressure tested before the perf guns are fired. The ball also may be seated by pumping only a minor amount of fluid. The ball typically is free to flow on or off the seat, but the cage limits travel of the ball to the immediate vicinity of the seat. Many such plugs are commercially sold, including the Boss Hog ball check plugs sold by Downhole Technology LLC, Houston, Tex., and Original Series caged ball plugs sold by JK Enterprises, Bridgeport, Tex. 
     While caged ball plugs represent a viable option if operations proceed according to plan, they can create significant issues, especially when installed in horizontal portions of a well. That is, if a perf gun fails to fire for whatever reason, another perf gun cannot be pumped into the liner. The plug will prevent fluid from flowing into the liner. The second perf gun will have to deployed into horizontal sections of the well via a tractor tool, which adds the cost of the tractor run and attendant delay to the operation. 
     “Ball on seat” frac plugs provide another option. Many are sold commercially, including the Boss Hog ball in place plugs sold by Downhole Technology. When a ball-on-seat frac plug is readied for deployment into a well, a ball is installed between the plug and the setting tool. Once the plug is set and the setting tool detached, the ball may be seated by pumping a small amount of fluid. The plug may be pressure tested if desired before firing the perf guns. Travel of the ball, however, is not restricted. Thus, if the perf guns fail to fire, the tool string can be pulled out of the well, and the ball will flow up and out of the liner with production fluids. Another perf gun then can be pumped into the liner. While a tractor run will not be necessary, ball-on-seat plugs still add significant delay costs if perf guns fail to fire. 
     The statements in this section are intended to provide background information related to the invention disclosed and claimed herein. Such information may or may not constitute prior art. It will be appreciated from the foregoing, however, that there remains a need for new and improved plugs for use in fracturing oil and gas wells or in other operations that require a portion of the well to be isolated. Such disadvantages and others inherent in the prior art are addressed by various aspects and embodiments of the subject invention. 
     SUMMARY 
     The following is a non-exhaustive listing of some aspects of the present techniques. These and other aspects are described in the following disclosure. 
     Some aspects include a plug apparatus, the apparatus including a cone shaped wedge having a first end and a second end and having an inside surface and an outside surface, the cone shaped wedge having, at least in some part, a decreasing diameter on the outside surface and a constant diameter on the inside surface from the first end to the second end, a slip, comprising a tapered inner surface, configured to encircle the second end of the cone shaped wedge, a sealing ring, having an annular body, encircled around the cone shaped wedge and near the first end of the cone shaped wedge, and a mandrel positioned inside the cone shaped wedge, the mandrel having an open cylindrical shape and having a first end and a second end. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The above-mentioned aspects and other aspects of the present techniques will be better understood when the present application is read in view of the following figures in which like numbers indicate similar or identical elements: 
         FIGS. 1A, 2A, 3A, and 4A  (“ FIGS. 1 ”) are sequential schematic representations showing a well  1  being readied for production or “completed.” 
         FIG. 1A  is a schematic illustration of a liner assembly being cemented in a bore of a well. 
         FIG. 1B  is a schematic illustration of the initial stage of a “plug and perf” fracturing operation showing liner assembly installed and cemented in wellbore. 
         FIG. 1C  is a schematic illustration of an early stage of the plug and perf fracturing operation which shows a tool string deployed into liner assembly. 
         FIG. 1D  is a schematic illustration of liner assembly after completion of the plug and perf fracturing operation, and before removal of plugs from liner. 
         FIGS. 2A, 2B, 2C, and 2D  (“ FIGS. 2 ”) are sequential axial cross-sectional views of a first frac plug in a liner, in accordance with some of the embodiments. 
         FIG. 2A  shows the first frac plug in an unset, open state as it is run into a well to a desired location in a liner, in accordance with some of the embodiments. 
         FIG. 2B  shows the first frac plug after it has been set in a liner and a setting tool has been released from the frac plug, and with the frac plug still in its open state, in accordance with some of the embodiments. 
         FIG. 2C  shows the first set frac plug in the process of being shut with a stopple, in accordance with some of the embodiments. 
         FIG. 2D  shows the first frac plug after it has been shut with a stopple to restrict the flow of fluids downward through the frac plug, in accordance with some of the embodiments. 
         FIG. 3  is an axial cross-sectional view of an annular wedge of the first frac plug, in accordance with some of the embodiments. 
         FIG. 4  is a radial cross-section view of an annular slip, in accordance with some of the embodiments. 
         FIG. 5  is a top elevational view of a setting ring, in accordance with some of the embodiments. 
         FIG. 6  is an axial cross-sectional view of setting ring, in accordance with some of the embodiments. 
         FIG. 7  is an axial cross-sectional view of a gauge ring, in accordance with some of the embodiments. 
         FIG. 8  is a bottom elevational view of a gauge ring, in accordance with some of the embodiments. 
         FIG. 9  is an axial cross-sectional view of a mandrel, in accordance with some of the embodiments. 
         FIG. 10  is an isometric view of a stopple, in accordance with some of the embodiments. 
         FIG. 11  is a top cross-sectional view of a second exemplary frac plug, in accordance with some of the embodiments. 
         FIG. 12  is an isomeric cross-sectional view of the second exemplary frac plug, in accordance with some of the embodiments. 
         FIG. 13  is an isomeric whole view of the second exemplary frac plug, in accordance with some of the embodiments. 
         FIG. 14  is a top exploded cross-sectional view of the second exemplary frac plug, in accordance with some of the embodiments. 
         FIG. 15  is an isomeric cross-sectional view of the second exemplary frac plug, where wireline setting tool is disengaged, in accordance with some of the embodiments. 
         FIG. 16  is an isomeric cross-sectional view of the second exemplary frac plug, during flow and prior to “Conversion”, in accordance with some of the embodiments. 
         FIG. 17  is an isomeric cross-sectional view of the second exemplary frac plug, during flow (the flow shown by the dotted line arrows) and prior to “Conversion”, in accordance with some of the embodiments. 
         FIG. 18  is an isomeric cross-sectional view of the second exemplary frac plug, where the frac plug is converted and sealed, in accordance with some of the embodiments. 
         FIG. 19  is a zoomed isomeric whole view of ports of the second exemplary frac plug, in accordance with some of the embodiments. 
         FIG. 20  is a zoomed isomeric cross-sectional view of ports of the second exemplary frac plug, in accordance with some of the embodiments. 
         FIG. 21  is an isomeric cross-sectional view of the second exemplary frac plug, with isomeric whole view of the mandrel for port visibility, in accordance with some of the embodiments. 
     
    
    
     While the present techniques are susceptible to various modifications and alternative forms, specific embodiments thereof are shown by way of example in the drawings and will herein be described in detail. The drawings may not be to scale. It should be understood, however, that the drawings and detailed description thereto are not intended to limit the present techniques to the particular form disclosed, but to the contrary, the intention is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the present techniques as defined by the appended claims. 
     DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS 
     To mitigate the problems described herein, the inventors had to both invent solutions and, in some cases just as importantly, recognize problems overlooked (or not yet foreseen) by others in the field of oil extraction. Indeed, the inventors wish to emphasize the difficulty of recognizing those problems that are nascent and will become much more apparent in the future should trends in industry continue as the inventors expect. Further, because multiple problems are addressed, it should be understood that some embodiments are problem-specific, and not all embodiments address every problem with traditional systems described herein or provide every benefit described herein. That said, improvements that solve various permutations of these problems are described below. 
     In some embodiments, a frac plug  30  may be described by reference to  FIGS. 1-10 . As may be seen in the schematic representations of  FIG. 1 , frac plug  30  may be used to perform a “plug and perf” fracturing operation in an oil and gas well  1 . Referring first to  FIG. 1A , well  1  is serviced by a derrick  2  and various surface and downhole equipment for pumping cement and circulating fluids (not shown). The upper portion of well  1  is provided with a casing  3 , while the lower portion is an open bore  4  extending generally horizontally through a hydrocarbon bearing formation  5 . 
     In some embodiments, a liner assembly  10  is suspended from casing  3  by a liner hanger  11  and extends through open bore  4 . Liner assembly  10  may include various tools, including toe valve  12  and a float assembly  13 . Float assembly  13  may include various tools that assist in running liner  10  into well  1  and cementing it in bore  4 , such as a landing collar  14 , a float collar  15 , and a float shoe  16 . 
       FIG. 1A  depicts well  1  as liner  10  is being cemented in bore  4 . A quantity or “plug” of cement  6  is being pumped into liner  10 , out its lower end, and into the annulus between liner  10  and bore  4 . As cement  6  is pumped, it displaces drilling fluids  7  already present in liner  10  and the annulus. A wiper plug  17  is being pumped behind cement  6 . It follows the plug of cement  6  as it flows through liner  10 . Wiper plug  17  will help clean and remove cement  6  from the inside of liner  10 . It will pass through toe valve  12  and eventually seat on landing collar  14  in float assembly  13 . Pumping will continue until cement  6  completely fills the annulus between liner  10  and bore  4 . It then will be allowed to set, as seen in  FIG. 1B . 
       FIG. 1B  shows well  1  after the initial stage of a frac job has been completed. Derrick  2  and the cementing equipment have been replaced by well head  8  and other surface equipment (not shown) which will inject frac fluids into well  1  at high pressures and flow rates. Toe valve  12  was run in on liner  10  in its shut position, i.e., with toe valve  12  closed. Toe valve  12  now has been opened. Fluid has been introduced into formation  5  via open toe valve  12 , and fractures  9  extending from toe valve  12  have been created in a first zone near the bottom of well  1 . 
     In some embodiments, a frac job may proceed in stages from the lowermost zone in a well to the uppermost zone. Thus,  FIG. 1C  shows that a “plug and perf” tool string  20  has been run into liner  10  on a wireline  23 . Tool string  20  comprises a perf gun  21 , a setting tool  22 , and a frac plug  30   a . Tool string  20  is positioned in liner  10  such that frac plug  30   a  is uphole from toe valve  12 . Frac plug  30   a  is coupled to setting tool  22  and may be installed in liner  10  by actuating setting tool  22  via wireline  23 . Once plug  30   a  is installed, setting tool  22  may be released from plug  30   a . Perf gun  21  then may be fired to create perforations  24   a  in liner  10  uphole from plug  30   a . Perf gun  21  and setting tool  22  then will be pulled out of well  1  by wireline  23 . 
     As described in detail below, a frac stopple  31  (not shown in  FIG. 1 ) then may be released into plug  30   a  to restrict the downward flow of fluids through plug  30   a . Plug  30   a , therefore, will substantially isolate the lower portion of well  1  and the first fractures  9  extending from toe valve  12 . Fluid then may be pumped into liner  10  and forced out through perforations  24   a  to create fractures  9  (shown in  FIG. 1D ) in a second zone. After fractures  9  have been sufficiently developed, pumping may be stopped and valves in well head  8  will be closed to shut in the well  1 . After a period of time, fluid will be allowed to flow out of fractures  9 , through liner  10  and casing  3 , to the surface. 
     In some embodiments, additional plugs  30   b  to  30   z  then may be run into well  1  and set and shut or in certain embodiments, deployed, liner  10  will be perforated at perforations  24   b  to  24   z , and well  1  will be fractured in succession as described above until, as shown in  FIG. 1D , all stages of the frac job have been completed and fractures  9  have been established in all zones. Once the fracturing operation has been completed, plugs  30  may be drilled out and removed from liner  10 . Production equipment then will be installed in the well and at the surface to control production from well  1 . 
     The terms “upper” and “lower” and “uphole” and “downhole” as used herein to describe location or orientation are relative to the well and to the tool as run into and installed in the well. Thus, “upper” and “uphole” refers to a location or orientation toward the upper or surface end of the well. “Lower” or “downhole” is relative to the lower end or bottom of the well. It also will be appreciated that the course of the wellbore may not necessarily be as depicted schematically in  FIG. 1 . Depending on the location and orientation of the hydrocarbon bearing formation to be accessed, the course of the wellbore may be more or less deviated in any number of directions. 
     In some embodiments, “Axial,” “radial,” “angularly,” and forms thereof reference the central axis of the tools. For example, axial movement or position refers to movement or position generally along or parallel to the central axis. “Lateral” movement and the like also generally refer to up and down movement or positions up and down the tool. “Radial” will refer to positions or movement toward or away from the central axis. 
     As discussed above, frac plugs may run into a well in an unset, open position, but then may be set and shut to force fluid from a liner into a formation. Broad embodiments incorporate a stopple that may be released to shut the plug once it has been set in a liner. For example, consider a frac plug  30  which is shown in greater detail in  FIG. 2 , as a first exemplary frac plug, in accordance with some of the embodiments. 
     As shown in  FIG. 2 , frac plug  30  may comprise an annular wedge  34 , a sealing ring  35 , an annular slip  36 , a setting ring  37 , a gauge ring  38 , a mandrel  39 , and a stopple  31 . Wedge  34 , sealing ring  35 , and slip  36  may have truncated inverted conical or other tapered surfaces. Those surfaces complement each other and allow wedge  34  to be driven into and radially expand sealing ring  35  and slip  36  to seal and anchor plug  30  in liner  10 . In some embodiments, except in that it incorporates mandrel  39  and stopple  31 , plug  30  is similar to frac plug  30  disclosed in U.S. Pat. No. 9,835,003 to M. Harris et al. and the RzrFrac plug sold by Rubicon Oilfield International, Houston, Tex. 
     An example of an annular wedge  34  is shown in isolation in  FIG. 3 . As seen therein, wedge  34  may have an upper portion that may be described in general terms as having an annular or open cylindrical shape. The lower portion of wedge  34  may comprise a plurality of collet fingers  41 . (Certain other embodiments may have structures other than collet fingers, including rods such as those shown in  FIG. 15  item  41 , that perform similar functions). Collet fingers  41  are integrally formed with wedge  34  and extend axially downward from the lower end of the wedge upper portion. Collet fingers  41  are spaced circumferentially around annular wedge  34  and terminate in collet heads  42 . As will be appreciated from the discussion that follows, collet fingers  41  may provide support for slip  36  as it is assembled and a base for connecting gage ring  38 . 
     In some embodiments, wedge  34  may also have an axial passage or bore  43  extending through its upper portion. As seen in  FIG. 3 , an inner mandrel seat  44  may be defined in wedge bore  43 , bore  43  otherwise having a substantially uniform diameter, and in some embodiments there is substantially uniform ID at least in part. In certain other embodiments, the inner diameter is tapered. In some other embodiments, the inner diameter is alternately tapered and substantially uniform. The appropriate inner diameter shape is determined by its function and the corresponding tool portions with which it is to interact. By example, the inner diameter can be designed to interact with the mandrel to, among other things, seat the inner/outer wedge as the mandrel advances downward through the tool and modulate the fluid flow toward the ports in the mandrel, regulating the fluid flow and pressure above and below the tool. Mandrel seat  44  may be provided by a shallow angle, upward facing tapered reduction in the diameter of wedge bore  43  situated axially below the upper end of wedge  34 . 
     In some embodiments, the upper portion of wedge  34  has an outer that may be truncated inverted conical surface  45 . That is, outer conical surface  45  tapers downwardly and inwardly, and the diameter of its upper end is greater than the diameter of its lower end. The upper end of wedge  34  may have a substantially cylindrical outer surface if desired. That is, conical surface  45  does not necessarily extend all the way to the upper end of wedge  34 . In some embodiments, however, it extends along the substantially majority of the upper portion of wedge  34 . 
     In some embodiments, sealing ring  35  of plug  30  may have a relatively short, annular body  51  defining an axial passage or bore. The ring bore may have an inverted truncated conical shape, that is, it tapers radially inward from its upper end to its lower end. The inner taper of the bore of sealing ring  35  may be complementary to the taper provided on outer conical surface  45  of wedge  34 . In some embodiments, sealing ring  35  may be provided with one or more elastomeric seals which ultimately will enhance the seal between plug  30  and liner  10  when plug  30  is set. Thus, ring body  51  is provided with one or more outer elastomeric seals  52  in corresponding grooves on the outer surface of ring body  51 . One or more inner elastomeric seals  53  may be provided in corresponding grooves in the ring bore. Elastomeric seals  52  and  53  may be molded in the grooves or they may be molded and then inserted therein. Other seal configurations may be used, however, or the seals may be eliminated depending on the design of the sealing ring and the materials from which it is fabricated. 
     Slip  36  of plug  30  may be designed to grip and engage liner  10 . Though, in some embodiments referred to in the singular, slip  36  of plug  30  is an assembly of discrete, separate slip segments. As shown in  FIG. 4 , slip  36  may have six individual slip segments  36   a  to  36   f . More or fewer segments may be used if desired, but in any event, individual slip segments  36   a - f  may be visualized as lateral segments of an open cylinder. When plug  30  is in its run-in condition, as shown in  FIG. 2A , segments  36   a - f  are aligned along, and arranged angularly about the tool axis. In some embodiments, slip segments  36   a - f  may be closely adjacent or abuts each other. Thus, slip segments  36   a - f  collectively may define an open cylindrical slip  36  having an axial inner passage or bore  61 . 
     In some embodiments, bore  61  of slip  36  may have a generally truncated inverted conical surface. That is, slip bore  61  tapers radially inward from top to bottom, and the diameter of slip bore  61  at its upper end is greater than the diameter at its lower end. In some embodiments, the taper in slip bore  61  is complementary to the taper on outer conical surface  45  of the upper portion of wedge  34 . 
     In some embodiments, the outer surface of slip  36  may be cylindrical. In some embodiments, it is provided with features to assist slip  36  in engaging and gripping liner  10  when plug  30  is set. Thus, for example, slip  36  may be provided with high-strength or hardened particles, grit or inserts, such as buttons  62  embedded in its outer surface. Buttons  62  may be, for example, a ceramic material containing aluminum, such as a fused alumina or sintered bauxite, or zirconia, such as CeramaZirc available from Precision Ceramics. Buttons also may be fabricated from heat treated steel or cast iron, fused or sintered high-strength materials, or a carbide such as tungsten carbide. The precise number and arrangement of buttons  62  or other such members may be varied. The outer surface of slip  36  also may be provided with teeth or serrations in addition to or in lieu of buttons or other gripping features. 
     In some embodiments, plug  30  may be set in liner  10  by actuating setting tool  22  via wireline  23 . When actuated, setting tool  22  will drive annular wedge  34  into sealing ring  35  and annular slip  36 . As wedge  34  is driven downward, it will force sealing ring  35  and slip  36  to expand and seal and anchor  30  in liner  10 . The setting of plug  30  may be understood in greater detail by comparing  FIG. 2A  and  FIG. 2B .  FIG. 2A  shows plug  30  in its run-in condition.  FIG. 2B  shows plug  30  after it has been set in liner  10 . 
     As shown in  FIG. 2A , when plug  30  is assembled for running into a well, slip  36  may be disposed around collet fingers  41  of wedge  34  with the upper end of slip  36  extending over the lower portion of outer conical surface  45  of wedge  34 . Outer conical surface  45  of wedge  34  thus is received in and engages conical bore  61  of slip  36 . 
     In some embodiments, sealing ring  35  is carried on outer conical surface  45  of wedge  34  near its lower end such that it abuts the upper end of slip  36 . Slip segments  36   a - f , in some embodiments, are secured at their upper ends. Thus, for example, the lower end of sealing ring  35  is provided with an annular projection or lip  54 . Slip segments  36   a - f  have a complementary lip  63  on their upper ends. Sealing ring lip  54  and slip lip  63  engage each other, thus securing the upper end of slip  36 . 
     In some embodiments, collet fingers  41  extend downward through slip bore  61  and terminate beyond the lower end of slip  36 . Setting ring  37  is carried slidably around that lower portion of collet fingers  41 . More particularly, the upper end of setting ring  37  abuts the lower end of slip  36  and the lower end of setting ring  37  abuts heads  42  of collet fingers  41  and an upward facing shoulder on gauge ring  38 . 
     An example of a setting ring  37  is shown in isolation in  FIGS. 5-6 . As shown therein, setting ring  37  may have an annular body  71  having a plurality of keys  72 . Keys  72  are arranged circumferentially on the inner surface or bore of setting ring body  71  and protrude radially inward. Setting ring  37  is slidably carried around the lower portion of collet fingers  41  such that keys  72  on setting ring  37  extend inward into slots  46  between collet fingers  41 . 
     As shown in  FIG. 2A , gauge ring  38  may be viewed as a bottom cap for plug  30 . It is attached to the lower end of collet fingers  41  and extends generally around setting ring  37  and the lower end of slip  36 . More particularly, and referring to  FIG. 2A  and to  FIGS. 7-8  which show gauge ring  38  in isolation, it will be appreciated that the lower portion of gauge ring  38  is generally enlarged and fits around and below heads  42  of collet fingers  41 . Gauge ring  38  may be connected to heads  42  of collet fingers  41 , for example, by fasteners. The fasteners may be screws, bolts, or pins inserted through radial holes  81  in the lower portion of gauge ring  38  (see  FIG. 7 ) and into radial holes  47  provided in collet heads  42  (see  FIG. 3 ). 
     In some embodiments, gauge ring  38  may have a relatively thin upper perimeter wall or skirt  82  extending upwardly from its lower portion. Skirt  82  extends upwardly beyond setting ring  37  and terminates just beyond the lower end of slip  36 . Gauge ring  38  and, in particular, skirt  82  is thus able to hold the lower portions of slip segments  36   a - f  together in a close annular arrangement. 
     In some embodiments, gauge ring  38  may help protect the lower end of plug  30  as it is deployed into a well. Skirt  36  of gauge ring  38  extends around the lower portions of slip segments  36   a - f , thus helping to protect them from catching on debris, protrusions, and the like that might cause them to deploy prematurely. It also will be noted that the outer diameter of gauge ring  38  may be greater than the outer diameter of setting ring  37 , slips  36 , sealing ring  35 , and the upper portion of wedge  36 . More particularly, the outer diameter of gauge ring  38 , relative to the inner walls of liner  10 , may be such that it presents a leading edge sufficient to prevent plug  30  from being lowered into constrictions in liner  10  that are too narrow to allow passage of plug  30 . In some embodiments, the tolerances are such that it provides sufficient clearance for plug  30  to be lowered past more typically encountered obstructions, protrusions, and bends in liner  10  without catching or damage 
     In some embodiments, mandrel  39  of plug  30  may have an open cylindrical shape providing a central, axial mandrel bore  91 . It is received and disposed generally in bore  43  of wedge  34  and extends generally along the central axis of plug  30 . When plug  30  is run into liner  10 , as shown in  FIG. 2A , mandrel  39  is releasably connected at its lower end to plug  30 . Mandrel  39  is releasably connected at its upper end to setting tool  22  (not shown in  FIG. 2A ). As described further below, those releasable connections allow plug  30  to be set and shut and allow setting tool  22  to be released from plug  30 . 
     More particularly, as shown in  FIG. 2A , when plug  30  is run into a well, mandrel  39  is releasably connected to setting ring  37  of plug  30  by a plurality of frangible fasteners  73 . Releases, such as frangible shear screws  73  extend through threaded radial holes  74  (see  FIGS. 5-6 ) in keys  72  of setting ring  37  and into recesses such as grooves  92  (see  FIG. 9 ) at the lower end of mandrel  39 . Shear screws  73  will be designed to break at a desired shear force and thereby release mandrel  39  from plug  30  after plug  30  has been installed in liner  10 . Other frangible connectors, such as pins, may be used for such purposes. Similarly, instead of grooves  92 , mandrel  39  may be provided with a series of detents, spotfaces, or holes. 
     In some embodiments, mandrel  39  is releasably connected to setting tool  22 , either directly or indirectly through an associated adaptor (not shown in  FIG. 2A ), by a plurality of frangible fasteners  93 . Frangible shear screws  93  extend through radial holes in the setting tool  22  (or an associated adaptor) into threaded radial holes  94  in the upper portion of mandrel  39 . Shear screws  93  will be designed to break at a desired shear force and thereby release setting tool  22  from mandrel  39  after plug  30  has been set. Other frangible connectors, such as pins, may be used for such purposes. Similarly, instead of holes  94 , mandrel  39  may be provided with a series of grooves, detents, or spotfaces. 
     As best seen in  FIG. 9  showing mandrel  39  in isolation, though substantially cylindrical, the outer circumference of mandrel  39  and mandrel bore  91  have various radial profiles along the length of mandrel  39 . In particular, the outer diameter of mandrel  39  tapers radially inward from an enlarged diameter mid-portion to provide a downward facing, external annular wedge seat  95 . The enlarged diameter portion and taper is sized such that mandrel  39  can fit closely within wedge  34  with wedge seat  95  seating on mandrel seat  44  in wedge bore  43 . 
     It also will be noted that the upper portion of mandrel  39  has a reduced outer diameter relative to the mid-portion of mandrel  39 . That reduced diameter, upper portion provides annular clearance between mandrel  39  and wedge  34 . Mandrel bore  91  in the upper portion of mandrel  39  tapers inward to provide an upward facing, inner annular stopple seat  96 . Ports  97  extend through the upper portion of mandrel  39  allowing fluid to flow from the clearance between mandrel  39  and wedge  34  into bore  91  of mandrel  39 . 
     In some embodiments, stopple  31  may be barrel shaped, having annular tapers  32  at both ends. It is releasably fixed in mandrel bore  91  by a plurality of frangible fasteners  98  at a location that is spaced from stopple seat  96  and above ports  97 . Frangible shear screws  98  extend through threaded radial holes  99  (see  FIG. 9 ) in mandrel  39  and into recesses such as grooves  32  (see  FIG. 9 ) in the mid-portion of stopple  31 . Shear screws  98  will be designed to break at a desired shear force and thereby release stopple  31  from mandrel  39  after plug  30  has been installed in liner  10 . Other frangible connectors, such as pins, may be used for such purposes. Similarly, instead of grooves  33 , stopple  31  may be provided with a series of detents, spotfaces, or holes. 
     Once coupled to setting tool  22 , either directly or through an associated adaptor, frac plug  30  may be deployed and installed in a well. It may be deployed by pumping it along with tool string  20  into liner  10  on wireline  23 . Plug  30  will be installed by actuating setting tool  22  via wireline  23 . Setting tool  22  may be any number of conventional setting tools. Preferred setting tools and adaptors, and the way they may be employed are disclosed in greater detail in Harris &#39;003. In some embodiments, the setting tool and any associated adaptor comprise an inner part and an outer part which move relative to each other. When actuated, the outer part moves downward relative to the inner part and transmits force to wedge  34  of plug  30 . Thus, when actuated setting tool  22  will drive annular wedge  34  into sealing ring  35  and annular slip  36  to force sealing ring  35  and slip  36  to expand and set and seal plug  30  in liner  10  as shown in  FIG. 2B . 
     More particularly, once plug  30  is deployed to the desired location in liner  10 , setting tool  22  may be actuated. Mandrel  39  is releasably connected to the inner part of setting tool  22  or an associated adaptor. The outer part of setting tool  22  will move downward relative to the inner part of setting tool  22 . The outer part of setting tool  22  bears down on the upper end of wedge  34  which, as noted above, carries sealing ring  35  and extends through slip  36  and setting ring  37 . Sealing ring  35  abuts the upper end of slip  36 , and setting ring  37  abuts the lower end of slip  36 . Setting ring  37  is held in position by mandrel  39 , to which it is connected by frangible fasteners  73 . Collet fingers  41  of wedge  34 , however, are able to slide freely within the bore of setting ring  37 . That will allow plug  30  to be installed, in essence, by compressing wedge  34 , sealing ring  35 , and slip  36  together between the outer part of setting tool  22  and setting ring  37 . 
     In some embodiments, as wedge  34  travels axially downward, the complementary conical surfaces on the upper portion of wedge  34  and in the bore of sealing ring  35  and bore  61  of slip  36  allow wedge  34  to ride under sealing ring  35  and slip  36 . As wedge  34  rides under sealing ring  35  and slip  36 , it forces them to expand radially. As sealing ring  35  expands radially, outer elastomeric seal  52  seals against liner  10  and inner elastomeric seal  53  seals against the outer conical surface  45  of wedge  34 . Sealing ring  35  is thus able to provide a seal between plug  30  and liner  10 . 
     As slip  36  is expanded radially by wedge  34 , slip segments  36   a - f  will be forced radially outward and eventually into contact with liner  10 . Thus jammed between outer conical surface  45  of wedge  34  and liner  10 , they are able to anchor plug  30  within liner  10 . Upper end of slip  36  abuts the lower end of sealing ring  35 , thus also providing hard backup for sealing ring  35  as it expands radially to seal against liner  10 . 
     As noted above, mandrel  39  may be releasably connected at its upper end to the inner part of setting tool  22  by frangible fasteners  93 . When wedge  34  has been fully driven into sealing ring  35  and slip  36 , a downward facing, beveled shoulder at the lower end of upper portion of wedge  34  will engage setting ring  37 . Sealing ring  35  and slip  36  also will have been expanded into engagement with liner  10 . At that point the shear forces across frangible fasteners  93  will increase rapidly. When those forces exceed a predetermined limit, frangible fasteners  93  will shear, releasing setting tool  22  from mandrel  39  and relieving any further compressive force on plug  30 . Setting tool  22  then may be pulled from liner  10  via wireline  23 . 
       FIG. 2B  shows plug  30  after it has been set, but before stopple  31  has been deployed. Fluid is still able to flow through plug  30 . Fluid pumped down liner  10  at lower flow rates will flow into the clearance between the upper portion of mandrel  39  and wedge  34 , through ports  97  in mandrel  39 , through mandrel bore  91 , and out plug  30 . If flow exceeds a predetermined rate, however, the resulting back pressure above stopple  31  will cause shear screws  98  to shear, releasing stopple  31  and allowing it to flow downward through mandrel bore  91 . The tapered end  32  of stopple  31  provides a seating surface, and stopple  31  will seat on stopple seat  96  in mandrel  39  as shown in  FIG. 2C . Once seated, stopple  31  will be below ports  97  in mandrel  39  and will substantially restrict or in some embodiments shut off fluid flow through mandrel bore  91 . 
     At that point hydraulic pressure on stopple  31  will increase rapidly, and shear screws  74  securing mandrel  39  to setting ring  37  will shear. Mandrel  39  will be released and will shift downward within wedge bore  43 . As shown in  FIG. 2D , wedge seat  95  of mandrel  39  will seat on mandrel seat  44  of wedge  34  fully shutting plug  30 . Fluid then may be diverted at high pressure and flow rates through perforations  24  into formation  5 . The setting ring  37  in some embodiments will maintain its relative position with respect to the mandrel  39  as shear screws (or retaining screws)  73  remain in place (this action is not shown in  FIG. 2D ). In other embodiments as shown in  FIG. 2D , the mandrel  39  will advance relative to the setting ring  37  upon, among other things, release of shear screws/retaining screws  73 . In certain embodiments, as flow or pressure increases, the order of movement of stopple and seating of the mandrel within the inner wedge  45  can be altered, such that the stopple moves first and the seating occurs second, or vice versa. 
     It will be appreciated, therefore, that the plugs not only may be efficiently and effectively used to isolate portions of the liner, but that they offer significant advantages to operators in situations where failure of perf guns is a particular concern. For example, plug  30  may be installed in liner  10  as shown in  FIG. 2B . Like conventional ball-on-seat plugs, plug  30  allows an operator to pressure test the plug before fracturing operations are commenced. After plug  30  is set, fluid may be pumped into liner  10  at sufficiently high rates and pressures to shear screws  98  and release stopple  31 . Plug  30  will be deployed at this point. If perf gun  21  fails to fire, stopple  31  remains in place and a second perf gun  21  can be circulated into position. In certain other embodiments, stopple  31  may be allowed to flow up and out of liner  10  with production fluids. Another perf gun  21  then may be pumped into liner  10 . 
     Unlike conventional ball-on-seat plugs, however, if plug  30  is not pressure tested, plug  30  may allow a new perf gun  21  to be pumped into liner  10  without having to flow stopple  31  out of the well. If the first perf gun  21  fails to fire, stopple  31  is still held in mandrel  39  and a flow path through plug  30  is still available. Perf gun  21  and setting tool  22  may be pulled out of liner  10 . Another perf gun  21  may be pumped into liner  10  so long as the threshold back pressure above stopple  31  is not exceeded. Fluid essentially flows around stopple  31  via ports  97  in mandrel  39 . Once the new perf gun  21  has been fired successfully, flow may be increased to release stopple  31  from mandrel  39 . Perforations  24  have been provided in liner  10  and plug  30  has been shut—all without flowing stopple  31  back out of liner  10  with production fluids. 
     It will be appreciated that the plugs have been illustrated by reference to barrel-shaped stopple  31 . That configuration is preferred for various reasons. Its cylindrical central portion allows stopple  31  to shift easily and reliably within mandrel bore  91 , yet it provides adequate surface area to facilitate easy and reliable attachment to mandrel  39 . By providing both ends with identical annular tapers  32 , stopple  31  may be installed with either end oriented toward stopple seat  96  in mandrel bore  91 . Stopples, however, may have other geometries. Spherical balls may be used, for example, as they can be moved reliably though tubulars and provide effective seals. In general, any geometry allowing the stopple to shift and seat reliably may be used so long as the configuration of the seat is modified accordingly. 
     Similarly, ports  97  passing through mandrel  39  provide an effective bypass allowing fluid to flow around stopple  31  until stopple  31  is released and plug  30  is shut. Ports  97  may be sized and numbered to provide relative high flow rates through plug  34  without releasing stopple  31 . Other bypass flow paths, however, may be provided. For example, stopple  31  fits relatively closely within mandrel bore  91 , but it may instead have a reduced outer diameter relative to the diameter of mandrel bore  91 . Fluid would be allowed to flow around the periphery of stopple  31 . Alternately, grooves may be provided in the outer surface of stopple  31 , or passages provided near the its periphery to create other axial flow paths, while still providing a sufficiently large seating surface at the end of stopple  31 . Similarly, while stopple  31  is illustrated as being releasably secured within mandrel bore  91 , it may be spaced away from stopple seat  96  and above ports  96  by collapsible or frangible braces. Back pressure caused by fluid flowing through ports  96  would collapse or break the brace when a threshold pressure is reached, allowing stopple  31  to seat on stopple seat  96 . 
     Other modifications may be made to illustrative plug  30  in addition to those mentioned above. For example, outer surface  45  of wedge  34 , the bore of sealing ring  35 , and bore  61  of slip  36  all have been described as having an inverted truncated conical shape. The mating tapered surfaces of wedge  34 , sealing ring  35 , and slip  36 , however, may have different geometries. Wedge  34 , for example, may be provided with a number of discrete, flat ramped surfaces arrayed circumferentially about its outer surface  45 . Such ramps may be visualized as bevels or as grooves on a conical surface or, as the sides of a tapered prism having a polygonal cross-section. The bore of sealing ring  35  and bore  61  of slip  36  would be modified so that they mate with and accommodate wedge  34  as it is driven downward. For example, the plug may be provided with discrete slip segments which ride up flat grooves or tracks provided in the wedge. A slip also may have a break-away configuration. Breakaway slips are designed to break apart into a number of segments as the slip is expanded radially during setting of the plug. Many other configurations also may be used to connect the mandrel to the setting ring or other plug components which allow the plug to be set. Multiple wedges, slips, and sealing elements also may be used. In general, mandrel  39  and stopple  31  and other embodiments thereof may be adapted for use in almost any conventional plug design. 
       FIGS. 11-21  show a frac plug  30 , as a second exemplary frac plug, in accordance with some of the embodiments. 
     As shown in  FIG. 11 , frac plug  30  may comprise an annular wedge  34 , a sealing ring  35 , an annular slip  36 , a setting ring  37 , a gauge ring  38 , a mandrel  39 , and a stopple  31 . Wedge  34 , portions of sealing ring  35 , and slip  36  may have truncated inverted conical or other tapered surfaces. Those surfaces complement each other and allow wedge  34  to be driven into and radially expand sealing ring  35  and slip  36  to seal and anchor plug  30  in liner  10 . 
       FIG. 12-14  show an isomeric cross-sectional view, an isomeric whole view, and a top exploded cross-sectional view of the frac plug  30  shown in  FIG. 11 . 
       FIG. 15  shows a set view of the frac plug  30  shown in  FIG. 11  at moment when wireline setting tool is disengaged (elements and wireline shear screws removed from image for clarity). In this drawing, tool is set in casing and no pressure retaining at this point. 
       FIG. 16  shows a set in view of the frac plug  30  shown in  FIG. 11  during flow and prior to “Conversion”. At this stage, flow is allowed to pass through the ports up to a predetermined rate. Initial flow causes the mandrel to shift back down to the cone.  FIG. 17  is the same view as  FIG. 16  while showing the flow with dotted lines. 
     In some embodiments, ports  97  may extend through the upper portion of mandrel  39  allowing fluid to flow from the clearance between mandrel  39  and wedge  34  into bore  91  of mandrel  39 . Fluid pumped down liner  10  at lower flow rates may flow into the clearance between the upper portion of mandrel  39  and wedge  34 , through ports  97  in mandrel  39 , through mandrel bore  91 , and out plug  30 . If flow exceeds a predetermined rate, however, the resulting back pressure above stopple  31  will cause shear screws  98  to shear (e.g. break), releasing stopple  31  and allowing it to flow downward through mandrel bore  91 . In some embodiments, such a hydraulic back pressure is called hydraulic back pressure threshold, meaning by exceeding this hydraulic back pressure, the stopple will be released and will seal the plug. The tapered end  32  of stopple  31  provides a seating surface, and stopple  31  will seat on stopple seat  96  in mandrel  39 . Once seated, stopple  31  will be below ports  97  in mandrel  39  and will substantially restrict or in some embodiments shut off (e.g seal) fluid flow through mandrel bore  91 . 
     In some embodiments, multiple ports are positioned circumferentially around the mandrel. In some embodiments, the number of ports may be 4, 5, 6, 7, 8, 10, or 12. In some embodiments, the ports may have the same dimension. In some embodiments, the ports may have different dimensions. In some embodiments, the ports may have a circle, oval, ellipse, square, triangle, rectangle, trapezoid, kite, pentagon, hexagon, octagon, or other complex cross sectional geometries. 
     In some embodiments, the ports may be protruded at 90 degrees angle of off the axial mandrel bore. In many embodiments, angled ports are preferable, between 10 and 80 degrees off the axial direction of the tool. In some embodiments, the ports may be protruded at 30 degrees angle of off the axial mandrel bore. In some embodiments, the ports may be protruded at 45 degrees angle of off the axial mandrel bore. In some embodiments, the ports may be protruded at 60 degrees angle of off the axial mandrel bore. In some embodiments, the ports may be protruded at different angles of off the axial mandrel bore. In some embodiments, a mandrel may have four identical flow path ports spaced circumferentially at 90 degrees apart from each other and protruded with a 30 degrees angle of off the axial mandrel bore. In various embodiments, tests have shown that angled ports within 5 degrees of 60 degrees off parallel with the axis (i.e., 60°+/−10 degrees, or 20-40° off the axial direction) of the tool have shown superior flow-through capabilities. In these embodiments, the back pressure can have sufficient separation from the low flow pressure to allow release a release (e.g., the shear screws) at achievable pressures but distant enough from ordinary flow pressure to limit accidental shear. 
     In some embodiments, ports may have groves or other features. Such features may be used to direct the flow to a specific direction or cause a specific Reynolds numbers that would yield the hydraulic back pressure threshold. 
     At that point hydraulic pressure on stopple  31  will increase rapidly, and shear screws  74  securing mandrel  39  to setting ring  37  will shear. Mandrel  39  will be released and will shift downward within wedge bore  43 . As shown in  FIG. 2D , wedge seat  95  of mandrel  39  will seat on mandrel seat  44  of wedge  34  fully shutting plug  30 . Fluid then may be diverted at high pressure and flow rates through perforations  24  into formation  5 . 
     It will be appreciated, therefore, that the plugs not only may be efficiently and effectively used to isolate portions of the liner, but that they offer significant advantages to operators in situations where failure of perf guns is a particular concern. For example, plug  30  may be installed in liner  10  as shown in  FIG. 2B . Like conventional ball-on-seat plugs, plug  30  allows an operator to pressure test the plug before fracturing operations are commenced. After plug  30  is set, fluid may be pumped into liner  10  at sufficiently high rates and pressures to shear screws  98  and release stopple  31 . Plug  30  will be shut and may be pressure tested. If perf gun  21  fails to fire, like conventional ball-on-seat plugs, stopple  31  may be allowed to flow up and out of liner  10  with production fluids. Another perf gun  21  then may be pumped into liner  10 . 
     Unlike conventional ball-on-seat plugs, however, if plug  30  is not pressure tested, plug  30  may allow a new perf gun  21  to be pumped into liner  10  without having to flow stopple  31  out of the well. If the first perf gun  21  fails to fire, stopple  31  is still held in mandrel  39  and a flow path through plug  30  is still available. Perf gun  21  and setting tool  22  may be pulled out of liner  10 . Another perf gun  21  may be pumped into liner  10  so long as the threshold back pressure above stopple  31  is not exceeded. Fluid essentially flows around stopple  31  via ports  97  in mandrel  39 . Once the new perf gun  21  has been fired successfully, flow may be increased to release stopple  31  from mandrel  39 , and to release mandrel  39  from setting ring  37 . Perforations  24  have been provided in liner  10  and plug  30  has been shut—all without flowing stopple  31  back out of liner  10  with production fluids. 
     It will be appreciated that the plugs have been illustrated by reference to barrel-shaped stopple  31 . That configuration is preferred for various reasons. Its cylindrical central portion allows stopple  31  to shift easily and reliably within mandrel bore  91 , yet it provides adequate surface area to facilitate easy and reliable attachment to mandrel  39 . By providing both ends with identical annular tapers  32 , stopple  31  may be installed with either end oriented toward stopple seat  96  in mandrel bore  91 . Stopples, however, may have other geometries. Spherical balls may be used, for example, as they can be moved reliably though tubulars and provide effective seals. In general, any geometry allowing the stopple to shift and seat reliably may be used so long as the configuration of the seat is modified accordingly. 
     Similarly, ports  97  passing through mandrel  39  provide an effective bypass allowing fluid to flow around stopple  31  until stopple  31  is released and plug  30  is shut. Ports  97  may be sized and numbered to provide relative high flow rates through plug  34  without releasing stopple  31 . Other bypass flow paths, however, may be provided. For example, stopple  31  fits relatively closely within mandrel bore  91 , but it may instead have a reduced outer diameter relative to the diameter of mandrel bore  91 . Fluid would be allowed to flow around the periphery of stopple  31 . Alternately, grooves may be provided in the outer surface of stopple  31 , or passages provided near the its periphery to create other axial flow paths, while still providing a sufficiently large seating surface at the end of stopple  31 . Similarly, while stopple  31  is illustrated as being releasably secured within mandrel bore  91 , it may be spaced away from stopple seat  96  and above ports  96  by collapsible or frangible braces. Back pressure caused by fluid flowing through ports  96  would collapse or break the brace when a threshold pressure is reached, allowing stopple  31  to seat on stopple seat  96 . 
     In some embodiments, plugs may be fabricated from materials and by methods used in plugs of this type. Such materials may be relatively hard metals, especially if removal of the plugs is not necessary, but the materials may be relatively soft, more easily drilled materials. For example, wedge  34  and slip  36  may be fabricated from non-metallic materials commonly used in plugs, such as fiberglass and carbon fiber resinous materials. The components may be molded, or may be machined from wound fiber resin blanks, such as a wound fiberglass cylinder. Alternately, suitable wedges and slips may be fabricated from softer or more brittle metals that are easier to drill, such as surface hardened cast iron, especially cast iron having a surface hardness in the range of 50-60 Rockwell C. Such materials and methods of fabricating wedge and slip components are well known in the art and may be obtained commercially from many sources. It also will be noted that, as used herein, the term “bore” is only used to indicate that a passage exists and does not imply that the passage necessarily was formed by a boring process. 
     In some embodiments, the sealing ring in the plugs are fabricated from a sufficiently ductile material which allows the ring to expand radially into contact with a liner without breaking. For example, ring body  51  may be fabricated from aluminum, bronze, brass, brass, copper, mild steel, or magnesium and magnesium alloys. Alternately, the ring body may be made of hard, elastomeric rubbers, such as butyl rubber. 
     In some embodiments, however, the sealing ring may be fabricated from a plastic material. Plastic components are more easily drilled, and the resulting debris more easily circulated out of a well. Engineering plastics, that is, plastics having better thermal and mechanical properties than more commonly used plastics, are preferred. Various materials that may be used are disclosed in Harris &#39;003. As noted above, the sealing ring may be provided with elastomeric material around its outer or inner surface. Such elastomeric materials include those commonly employed in downhole tools, such as butyl rubbers, hydrogenated nitrile butadiene rubber (HNBR) and other nitrile rubbers, and fluoropolymer elastomers such as Viton. Such elastomeric materials also may be used to fabricate other types of sealing elements as are commonly used in frac plugs. 
     Though described to a certain extent, it will be appreciated that plug  30  and other embodiments of the plugs may incorporate additional shear screws and the like to immobilize components during assembly, shipping, or run-in of the plug. Additional set screws and the like may be provided to prevent unintentional disassembly. Other sealing elements may be provided between components, and various ports accommodating fluid flow around and through the assembly also may be provided. Such features are shown to a certain degree in the figures, but their design and use in tools such as the plugs is well known and well within the skill of workers in the art. In many respects, therefore, discussion of such features is omitted from this description of preferred embodiments. 
     Plug  30  and other embodiments have been described as installed in a liner and, more specifically, a production liner used to fracture a well in various zones along the wellbore. A “liner,” however, can have a fairly specific meaning within the industry, as do “casing” and “tubing.” In its narrow sense, a “casing” is generally considered to be a relatively large tubular conduit, usually greater than 4.5″ in diameter that extends into a well from the surface. A “liner” is generally considered to be a relatively large tubular conduit that does not extend from the surface of the well, and instead is supported within an existing casing or another liner. In essence, it is a “casing” that does not extend from the surface. “Tubing” refers to a smaller tubular conduit, usually less than 4.5″ in diameter. The plugs, however, are not limited in their application to liners as that term may be understood in its narrow sense. They may be used to advantage in liners, casings, tubing, and other tubular conduits or “tubulars” as are commonly employed in oil and gas wells. A reference to liners shall be understood as a reference to all such tubulars. 
     Likewise, while the exemplified plugs are particularly useful in fracturing a formation and have been exemplified in that context, they may be used advantageously in other processes for stimulating production from a well. For example, an aqueous acid such as hydrochloric acid may be injected into a formation to clean up the formation and ultimately increase the flow of hydrocarbons into a well. In other cases, “stimulation” wells may be drilled near a “production” well. Water or other fluids then would be injected into the formation through the stimulation wells to drive hydrocarbons toward the production well. The plugs may be used in all such stimulation processes where it may be desirable to create and control fluid flow in defined zones through a wellbore. Though fracturing a wellbore is a common and important stimulation process, the plugs are not limited thereto. 
     While this invention has been disclosed and discussed primarily in terms of specific embodiments thereof, it is not intended to be limited thereto. Other modifications and embodiments will be apparent to the worker in the art. 
     Some of those embodiments are described is some detail herein. For the sake of conciseness, however, all features of an actual implementation may not be described or illustrated. In developing any actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve a developers&#39; specific goals. Decisions usually will be made consistent within system-related and business-related constraints, and specific goals may vary from one implementation to another. Development efforts might be complex and time consuming and may involve many aspects of design, fabrication, and manufacture. Nevertheless, it should be appreciated that such development projects would be a routine effort for those of ordinary skill having the benefit of this disclosure. 
     The frac plugs may be used in fracturing operations. They also may be used in other stimulation operations. Broad embodiments of the frac plugs have a mandrel, a wedge, a slip, a sealing element, and a stopple. The mandrel has an axial mandrel bore, a stopple seat, and a port adapted to provide a flow path for fluid between the mandrel bore and the exterior of the mandrel. The wedge, slip, and sealing element all are disposed radially beyond the mandrel. The stopple is releasably spaced from the stopple seat and the port, and it is releasable to seat on the stopple seat by increasing hydraulic back pressure above the ports. 
     The reader should appreciate that the present application describes several independently useful techniques. Rather than separating those techniques into multiple isolated patent applications, applicants have grouped these techniques into a single document because their related subject matter lends itself to economies in the application process. But the distinct advantages and aspects of such techniques should not be conflated. In some cases, embodiments address all of the deficiencies noted herein, but it should be understood that the techniques are independently useful, and some embodiments address only a subset of such problems or offer other, unmentioned benefits that will be apparent to those of skill in the art reviewing the present disclosure. Due to costs constraints, some techniques disclosed herein may not be presently claimed and may be claimed in later filings, such as continuation applications or by amending the present claims. Similarly, due to space constraints, neither the Abstract nor the Summary of the Invention sections of the present document should be taken as containing a comprehensive listing of all such techniques or all aspects of such techniques. 
     It should be understood that the description and the drawings are not intended to limit the present techniques to the particular form disclosed, but to the contrary, the intention is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the present techniques as defined by the appended claims. Further modifications and alternative embodiments of various aspects of the techniques will be apparent to those skilled in the art in view of this description. Accordingly, this description and the drawings are to be construed as illustrative only and are for the purpose of teaching those skilled in the art the general manner of carrying out the present techniques. It is to be understood that the forms of the present techniques shown and described herein are to be taken as examples of embodiments. Elements and materials may be substituted for those illustrated and described herein, parts and processes may be reversed or omitted, and certain features of the present techniques may be utilized independently, all as would be apparent to one skilled in the art after having the benefit of this description of the present techniques. Changes may be made in the elements described herein without departing from the spirit and scope of the present techniques as described in the following claims. Headings used herein are for organizational purposes only and are not meant to be used to limit the scope of the description. 
     As used throughout this application, the word “may” is used in a permissive sense (i.e., meaning having the potential to), rather than the mandatory sense (i.e., meaning must). The words “include”, “including”, and “includes” and the like mean including, but not limited to. As used throughout this application, the singular forms “a,” “an,” and “the” include plural referents unless the content explicitly indicates otherwise. Thus, for example, reference to “an element” or “a element” includes a combination of two or more elements, notwithstanding use of other terms and phrases for one or more elements, such as “one or more.” The term “or” is, unless indicated otherwise, non-exclusive, i.e., encompassing both “and” and “or.” Terms describing conditional relationships, e.g., “in response to X, Y,” “upon X, Y,”, “if X, Y,” “when X, Y,” and the like, encompass causal relationships in which the antecedent is a necessary causal condition, the antecedent is a sufficient causal condition, or the antecedent is a contributory causal condition of the consequent, e.g., “state X occurs upon condition Y obtaining” is generic to “X occurs solely upon Y” and “X occurs upon Y and Z.” Such conditional relationships are not limited to consequences that instantly follow the antecedent obtaining, as some consequences may be delayed, and in conditional statements, antecedents are connected to their consequents, e.g., the antecedent is relevant to the likelihood of the consequent occurring. Statements in which a plurality of attributes or functions are mapped to a plurality of objects (e.g., one or more processors performing steps A, B, C, and D) encompasses both all such attributes or functions being mapped to all such objects and subsets of the attributes or functions being mapped to subsets of the attributes or functions (e.g., both all processors each performing steps A-D, and a case in which processor 1 performs step A, processor 2 performs step B and part of step C, and processor 3 performs part of step C and step D), unless otherwise indicated. Further, unless otherwise indicated, statements that one value or action is “based on” another condition or value encompass both instances in which the condition or value is the sole factor and instances in which the condition or value is one factor among a plurality of factors. Unless otherwise indicated, statements that “each” instance of some collection have some property should not be read to exclude cases where some otherwise identical or similar members of a larger collection do not have the property, i.e., each does not necessarily mean each and every. Limitations as to sequence of recited steps should not be read into the claims unless explicitly specified, e.g., with explicit language like “after performing X, performing Y,” in contrast to statements that might be improperly argued to imply sequence limitations, like “performing X on items, performing Y on the X&#39;ed items,” used for purposes of making claims more readable rather than specifying sequence. Statements referring to “at least Z of A, B, and C,” and the like (e.g., “at least Z of A, B, or C”), refer to at least Z of the listed categories (A, B, and C) and do not require at least Z units in each category. Unless specifically stated otherwise, as apparent from the discussion, it is appreciated that throughout this specification discussions utilizing terms such as “processing,” “computing,” “calculating,” “determining” or the like refer to actions or processes of a specific apparatus, such as a special purpose computer or a similar special purpose electronic processing/computing device. Features described with reference to geometric constructs, like “parallel,” “perpendicular/orthogonal,” “square”, “cylindrical,” and the like, should be construed as encompassing items that substantially embody the properties of the geometric construct, e.g., reference to “parallel” surfaces encompasses substantially parallel surfaces. The permitted range of deviation from Platonic ideals of these geometric constructs is to be determined with reference to ranges in the specification, and where such ranges are not stated, with reference to industry norms in the field of use, and where such ranges are not defined, with reference to industry norms in the field of manufacturing of the designated feature, and where such ranges are not defined, features substantially embodying a geometric construct should be construed to include those features within 15% of the defining attributes of that geometric construct. The terms “first”, “second”, “third,” “given” and so on, if used in the claims, are used to distinguish or otherwise identify, and not to show a sequential or numerical limitation. As is the case in ordinary usage in the field, data structures and formats described with reference to uses salient to a human need not be presented in a human-intelligible format to constitute the described data structure or format, e.g., text need not be rendered or even encoded in Unicode or ASCII to constitute text; images, maps, and data-visualizations need not be displayed or decoded to constitute images, maps, and data-visualizations, respectively; speech, music, and other audio need not be emitted through a speaker or decoded to constitute speech, music, or other audio, respectively. 
     The present techniques will be better understood with reference to the following enumerated embodiments: 
     A plug apparatus, the apparatus comprising: a cone shaped wedge having a first end and a second end and having an inside surface and an outside surface, the cone shaped wedge having, at least in some part, a decreasing diameter on the outside surface from the first end to the second end; a slip, comprising a tapered inner surface, configured to encircle the second end of the cone shaped wedge; a sealing ring, having an annular body, encircled around the cone shaped wedge and near the first end of the cone shaped wedge; and a mandrel positioned inside the cone shaped wedge, the mandrel having an open cylindrical shape and having a first end and a second end, the mandrel comprising: an axial mandrel bore; a stopple seat in the axial mandrel bore; a plurality of flow path ports adapted to allow fluid to enter the axial mandrel bore, wherein: the plurality of flow path ports are positioned between the first end of the mandrel and the stopple seat; and the plurality of flow path ports are protruded with a 60 degrees angle+/−10 degrees of off the axial mandrel bore; and a stopple positioned between the plurality of flow path ports and the first end of the mandrel; and one or more releases configured to releasably fixing the position of the stopple in the axial mandrel bore. 
     The plug apparatus of claim  1 , wherein: the mandrel having an inside surface and an outside surface; and the plurality of flow path ports are positioned circumferentially around the mandrel, wherein the plurality of flow path ports are configured to direct the fluid from the outside surface of the mandrel to the inside surface of the mandrel and towards the second end of the mandrel. 
     The plug apparatus of claim  2 , wherein: the releases comprise frangible or shearable parts adapted to fail at an identified pressure; and the stopple is releasable to seat on the stopple seat by reaching a hydraulic back pressure threshold above the plurality of flow path ports upon failing of the plurality of frangible or shearable parts. 
     The plug apparatus of claim  2 , wherein: the plurality of flow path ports comprises four identical flow path ports spaced circumferentially at 90 degrees apart from each other. 
     The plug apparatus of claim  1 , the cone shaped wedge further comprising: a plurality of collet fingers or rods extended axially and spaced circumferentially on the second end of the cone shaped wedge. 
     The plug apparatus of claim  5 , the plug further comprising: a setting ring having an annular body, the setting ring comprising: a plurality of keys arranged circumferentially and protruded radially inward on the setting ring; and wherein the setting ring is positioned slidably around the plurality of collet fingers. 
     The plug apparatus of claim  6 , the plug further comprising: a gauge ring attached to the plurality of collet fingers or rods and extended around the setting ring. 
     The plug apparatus of claim  1 , the slip comprising: a plurality of individual slip segments positioned closely adjacent and angularly around the cone shaped wedge. 
     The plug apparatus of claim  8 , wherein: the individual slip segments are equally spaced. 
     The plug apparatus of claim  8 , wherein: each of the individual slip segments comprises a plurality of buttons made of a ceramic material containing aluminum. 
     The plug apparatus of claim  1 , wherein: the stopple comprises a truncated cone portion. 
     The plug apparatus of claim  11 , wherein: the stopple comprises a solid cylindrical portion. 
     The plug apparatus of claim  1 , wherein: the stopple has dimensions suitable for being received in the stopple seat, as a means to restrict longitudinal flow passage through the plug apparatus. 
     The plug apparatus of claim  1 , wherein: the stopple seat comprises a tapered shape facing the first end of the mandrel. 
     The plug apparatus of claim  1 , wherein: the mandrel comprises an outer wedge seat configured to seat on a mandrel seat. 
     The plug apparatus of claim  1 , wherein: the diameter of the cone shaped wedge decreases at a constant linear rate, at least in some part, on the outside surface. 
     The plug apparatus of claim  1 , the sealing ring comprising: a groove configured to receive a plurality of elasticity rings to hydraulically seal a liner. 
     The plug apparatus of claim  1 , wherein the slip further comprises: a plurality of gripping serrations as a means of locking mechanism to prevent any dismantlement. 
     A method of plugging a liner bore; the method comprising: running a plug into a liner to a location to be plugged, the plug comprising: a cone shaped wedge having a first end and a second end and having an inside surface and an outside surface, the cone shaped wedge having, at least in some part, a decreasing diameter on the outside surface from the first end to the second end; a slip, comprising a tapered inner surface, configured to encircle the second end of the cone shaped wedge; a sealing ring, having an annular body, encircled around the cone shaped wedge and near the first end of the cone shaped wedge; and a mandrel positioned inside the cone shaped wedge, the mandrel having an open cylindrical shape and having a first end and a second end, the mandrel comprising: an axial mandrel bore; a stopple seat in the axial mandrel bore; a stopple; a plurality of frangible shear screws positioned near the first end of the mandrel; and a plurality of flow path ports adapted to allow fluid to enter the axial mandrel bore, wherein: the plurality of flow path ports are positioned between the first end of the mandrel and the stopple seat; and the plurality of flow path ports are protruded with a 60 degrees+/−10 degrees angle of off the axial mandrel bore; and setting the plug in the liner; and dropping the stopple into the stopple seat by reaching a hydraulic back pressure threshold in the liner.