Patent Publication Number: US-2019169951-A1

Title: Extended reach plug having degradable elements

Description:
RELATED APPLICATIONS 
     This application is a continuation-in-part of and claims priority to and incorporates by reference U.S. patent application Ser. No. 15/189,090, filed Jun. 22, 2016, which is a continuation-in-part of U.S. patent application Ser. No. 14/677,242, filed Apr. 2, 2015, which claims priority to and the benefit of U.S. Patent Application Nos. 61/974,065, filed Apr. 2, 2014, 62/003,616, filed May 28, 2014, and 62/019,679, filed Jul. 1, 2014, and is a continuation-in-part of application Ser. No. 13/893,205, filed May 13, 2013; U.S. patent application Ser. No. 15/697,572, filed Sep. 7, 2017, which is a continuation of and claims priority to application Ser. No. 14/999,637, filed Jun. 9, 2016, which is a continuation of and claims priority to application Ser. No. 13/373,223, filed Nov. 8, 2011, now U.S. Pat. No. 9,388,662; U.S. patent application Ser. No. 15/355,346, field Nov. 18, 2016, which claims priority to U.S. Provisional Application 62/372,550, filed Aug. 9, 2016, U.S. Provisional Application 62/374,454, filed Aug. 12, 2016, and U.S. Provisional Application 62/406,195, filed Oct. 10, 2016, which is a continuation of U.S. patent application Ser. No. 14/132,608, filed Dec. 18, 2013 and issued as U.S. Pat. No. 9,500,061 and is a continuation-in-part of U.S. patent application Ser. No. 13/969,066, filed Aug. 16, 2013, which is a continuation-in-part of U.S. patent application Ser. No. 13/895,707, filed May 23, 2013, which is a continuation-in-part of U.S. patent application Ser. No. 13/894,649, filed May 15, 2013, issued as U.S. Pat. No. 9,217,319 on Dec. 22, 2015, which is a continuation of and claims priority to U.S. patent application Ser. No. 13/843,051, filed Mar. 15, 2013, which claims the benefit of U.S. Provisional Application 61/648,749, filed May 18, 2012, and U.S. Provisional Application 61/738,519, filed Dec. 18, 2012; and application Ser. No. 15/672,790, filed Aug. 9, 2017, which is a continuation-in-part of application Ser. No. 15/403,739, filed Jan. 11, 2017. 
     This application also incorporates by reference U.S. Pat. Nos. 6,951,956; 10,119,359; 9,850,736; and 9,127,527. 
    
    
     BACKGROUND OF THE INVENTION 
     An important development in oil and gas production in recent decades has been the drilling of horizontal legs of hydrocarbon wells in combination with improvements in hydraulic or other types of fracturing techniques for stimulating production from previously uneconomically tight formations. For some years the fastest growing segment of production has been from shales or very silty zones that previously have not been considered economic. The current areas of increasing activity in the United States include the Barnett Shale, the Haynesville Shale, the Fayetteville Shale, the Marcellus Shale, the Eagle Ford Shale, the Bakken formation and other shale, or similar formations. There are similar formations in other parts of the world. 
     Currently, one procedure is to drill a horizontal leg through the productive formation, perform several frac jobs to generate fractures at horizontally spaced locations along the horizontal leg of the well and produce the contents of the formation to the surface through conventional surface equipment. In order to frac a series of spaced locations in the horizontal leg, it may be necessary to set a bridge plug or other settable well tool to isolate the previously fraced zone from the next zone to be fraced. After all frac jobs are done, the settable well tools are removed, typically by drilling with a coiled tubing unit or with a work string and workover/completion rig. 
     There has been a trend to make bridge plugs and other drillable equipment from composite materials that can be more readily drilled than conventional cast iron. Thus, the only cast iron component of many currently available bridge plugs and other drillable downhole equipment is the slips that wedge the plug in the well. There has been a development of so-called “button” type slips that include a composite body having metal teeth embedded therein. These button slips are more easily drilled than conventional cast iron slips but there is a place for cast iron or other metal slips that are more easily drilled than current metal slips. 
     Cast iron metal slips are more time consuming to drill up when one has the luxury of a workover rig working in a vertical well where drill collars can be used to apply weight to the bit. It is considerably more tedious to drill up a bridge plug using cast iron slips in a horizontal well or using a coiled tubing unit where very little weight can be applied to the bit. 
     Shales or other tight formations completed in a horizontal well section have a history of rapidly declining production so an economic limit is reached sooner than desired. One proposed technique to continue producing such a well is to refrac the well at intervals between the original fractures. This is currently accomplished by squeezing off the old fracture with cement, drilling out cement inside the casing string, re-perforating the well between the old fractures and then refracing the well through the new perforations. The problem with squeezing off the old perforations is that one is never confident that the squeeze job will not fail at frac pressure in one or more of the perforations so frac fluid is diverted into an old fracture. If the original well had seven frac stages of four feet each with six perforations per foot, which is typical, there would be a total of a hundred sixty eight perforations to be squeezed. 
     It has been proposed to refrac old horizontal wells by setting a patch in the casing to cover the old perforations—a much more secure technique than squeezing with cement. After the casing patches are set, new perforations are sequentially created between the casing patches and the new perforations are sequentially traced. In order to isolate a zone that has been traced from the next zone to be traced in such a well, a bridge plug or similar tool is passed through the casing and casing patches to a location above the new perforations and then set against the casing. There are commercially available cast iron bridge plugs that are capable of passing through the reduced I.D. (internal diameter) of a casing patch set in a casing string and then expanding into gripping and sealing engagement with the casing. Such cast iron bridge plugs are commercially available from all major oilfield service companies and have typically been used in vertical wells. In vertical wells, using a work over rig, a drill string and drill collars, enough weight can be put on the cast iron bridge plug to drill it up in a reasonable length of time. The problem is it is difficult and slow to drill up a single cast iron bridge plug in a horizontal well segment where very little weight can be applied to the bit. To date, it has not been possible to drill up two or more cast iron bridge plugs in a horizontal well because debris from the upper bridge plug interferes with and prevents drilling up the lower bridge plug due, in large measure, because not much weight can be put on the bit. In addition, it has not been possible to drill up two or more cast iron bridge plugs in a single bit run in a horizontal well because the effort completely wears out bits. 
     Cast iron slips are typically manufactured in one or two relatively large pieces. When the tool is assembled, two piece slips are held together in some fashion so they act as a one piece device. When the tool is set in the well, the slips are forced onto an expander cone, which fractures the slips into a series of segments that are trapped between the expander cone and the inside of the casing. In the past, the slip segments are of one piece and extend along the axis of the well. When the tool is drilled up in order to conduct another operation, the expander cone is drilled up thereby freeing the slip segments. Because the slip segments are so large, they must be either ground up by the bit and circulated out of the well or allowed to fall into the rat hole below the lowest perforations in the case of a vertical well. In the case of a horizontal well, large slip segments must be reduced in size by the bit or mill in order to circulate to the surface. 
     SUMMARY 
     A settable downhole tool is disclosed which is composed of some or substantially all degradable elements and has increased expansibility. The improvement in expansibility can be partially due to an expander cone having an increased ramp angle and corresponding slips relative to similar tools and partially due to increasing the thickness of the slips. The increased expansibility can also be due to an expander cone/slip body ramp angle, which is lower than normal for similar tools, but also longer than normal. The degradable elements of the tool may be one element, some elements, or all elements and comprised of material that is degradable in a downhole fluid. Downhole fluids may be fluids naturally in the well, such as formation fluids or production fluids, or fluid added by the operator at the wellhead. The tools may contain degradable elements, some of which may be metallic and/or non-metallic. In some embodiments, all of the tool&#39;s elements except cast iron parts, buttons, and/or set screws are comprised of degradable materials. 
     A settable well tool can be made of, or made, at least partly, of degradable materials and can be of smaller O.D. than prior art tools and still be able to expand into setting engagement with a production string. The smaller O.D. (outer diameter) tool may also be longer than prior art similar tools to provide a greater aspect ratio (length divided by unset O.D.). This allows the settable well tool to pass through a section of the production string that is restricted for one reason or other. 
     In some situations, the heel or curved section of a horizontal well is more restricted than expected. This can occur because the drilled hole has dogleg sections that restrict the passage of tools of conventional O.D. This can also occur because the production string cemented in the well has become corrugated or ovate on the inside of the bend. Other examples will be apparent to those skilled in the art. 
     In some situations, the restriction in the production string is from a casing patch set over a damaged section of a production string or set over old perforations in the process of refracing an existing horizontal well. In this situation, the well tool described herein can pass through the reduced I.D. of the casing patch and still expand into gripping and sealing engagement with the inside of an unpatched (or unrestricted) section of the casing. 
     In order to make a plug having an extended reach capability, it may be necessary to increase the expansibility of the slips in a radial direction, i.e. perpendicular to the axis of the well. Conventional settable plugs, such as bridge plugs, flow back plugs, drop ball plugs or other settable plugs as a practical matter, must have some range of expansibility because of the different wall thicknesses of well casing. For example, conventional 4½″ O.D. casing comes in a variety of weights, e.g. from 9.5#/foot J-55 through 13.5#/foot N-80 to 15.1#/foot P-110, meaning they have the same O.D. but progressively smaller I.D.&#39;s as the weight of the casing increases. Thus, as a practical matter, a conventional plug passes through the heaviest wall I.D. pipe but must expand enough to wedge against the interior of the lightest wall I.D. pipe. 
     
       
         
           
               
             
               
                 TABLE 1 
               
             
            
               
                   
               
               
                 Example Using conventional 4½″ O.D. Oilfield Casing 
               
            
           
           
               
               
               
               
               
            
               
                   
                 Grade and  
                 I.D. in  
                 Casing patch  
                 I.D. of casing  
               
               
                   
                 weight/ft. 
                 inches  
                 thickness 
                 with patch 
               
               
                   
                   
               
               
                   
                 J-55 9.5# 
                 4.090 
                 .125″ 
                 3.84″ 
               
               
                   
                 N-80 11.6# 
                 4.000 
                 .125″ 
                 3.75″ 
               
               
                   
                 N-80 13.6# 
                 3.920 
                 .125″ 
                 3.67″ 
               
               
                   
                 P-110 13.5# 
                 3.920 
                 .125″ 
                 3.67″ 
               
               
                   
                   
               
            
           
         
       
     
     There is an inherent variation in thickness and straightness of oilfield casing, meaning that anything run into a well has to accommodate normal manufacturing tolerances. Thus, a conventional plug for use in 4½″ casing has an O.D. of no more than about 3.75″ meaning there is nominally about one quarter inch difference between the I.D. of typical 4½″ casing and the O.D of the tool, meaning there is nominally a ⅛″ clearance around the outside of the tool as it is being run into a well. In a 5½″ casing, the clearance is normally about ¼″. In some embodiments of applicant&#39;s settable tools disclosed herein, the difference between the unset tool O.D. and the casing I.D. creates a clearance of ½″ or more around the outside of the tool as it is being run in, as measured in an unrestricted casing. It will be seen this is too small to run into a casing string having one or more casing patches or having some other type restriction in the casing. It will also be seen that conventional settable well tools do not have to expand much to grip the inside of the casing string in which they are run. 
     As explained more fully hereinafter, in some embodiments, the hardness of the degradable expander cone and the strength of the expander cone can be increased to avoid these problems. In one embodiment, a degradable metal can be provided for the expander cone. In another embodiment, a composite material having an increased hardness and strength may be employed. Other embodiments will be apparent to those skilled in the art in light of this disclosure. 
     In order to make a mainly degradable plug having substantially increased expansibility, in some embodiments, the slips can be made thicker in order to provide greater expansibility of the slips. In one aspect of the disclosed well tool, slips can be designed to fracture into much smaller pieces than conventional cast iron slips. These pieces can be small enough that they can be circulated out of a well without requiring further reduction in size. In other words, when a well tool equipped with the disclosed slips is degrading in a downhole fluid, the slip pieces are released from between the expander cone and the casing whereupon the pieces are simply circulated out of the well without further reduction in size. Slips of this design can be used on any settable well tool that can ultimately be drilled up, dissolve or degrade, such as one that is not designed or intended to be run through a casing patch or other restricted casing section. In other words, increasing the drillability and/or degradability of a settable well tool is desirable, regardless of whether the tool is run into a vertical or horizontal well, regardless of whether casing patches have been run into the well or regardless of whether there is a restriction in the casing. 
     One advantage of the disclosed degradable settable tool may be viewed as increased expansibility of the settable tool. Typical prior art tools are capable of expanding about ¼″ in diameter. Thus, tools intended to work inside 4½″ O.D. casing expand about 6% from the unset I.D. or so while tools intended to work inside 5½″ O.D., casing expand about 5% or so. In contrast, some embodiments of the disclosed tool can expand at least 15% and preferably can expand considerably more, e.g. in the range of 20-25%, as will be more fully apparent hereinafter. 
     One feature of this invention is to provide an improved, at least partly degradable settable well tool which can either degrade without drilling or can be drilled up more easily than prior art devices. 
     Another feature of this invention is to provide an improved settable well tool which has both degradability and increased expansibility, e.g. it can be run through casing having some type restriction therein. 
     It is an object of this invention to provide an improved degradable plug or other settable down hole tool that can be run through casing having a patch therein. 
     Another object of this invention is to provide improved slips for wedging a down hole tool in a well where the slips fracture into relatively small pieces in the act of setting the slips and which tool is at least partly degradable. 
     These and other objects and advantages of this invention will become more apparent as this description proceeds, reference being made to the accompanying drawings and appended claims. 
     In particular implementations, a settable isolation tool sized and configured to be capable of being used in fracing past at least one casing patch within 4½ inch to 5½ inch outer diameter (O.D.) casing in a horizontal leg of a hydrocarbon well. The tool may include: a mandrel with a longitudinal axis; first and second expanders around the mandrel, each expander having an outer surface which is not parallel to the mandrel&#39;s axis section and having a first end with a first outer diameter and a second end having a second outer diameter, the first outer diameter being larger than the second outer diameter; first and second annular slips around the mandrel, the first expander and the first slip being a first expander/slip pair and the second expander and the second slip being a second expander/slip pair, each slip having an inner surface complementary to its paired expander&#39;s outer surface section and a slip outer surface having outer teeth or inclusions for setting into the casing; the slips and expanders are sized and configured so each slip, in a retracted slip position, has a slip outer diameter of 3 inches to 3.8 inches, and the slip&#39;s outer diameter is smaller than the first outer diameter of the slip&#39;s associated expander and small enough so the slip may be moved past the casing patch in the horizontal leg while being inserted into the well; the retracted tool has an outer diameter of 3.25 inches to 4.18 inches, and the retracted tool&#39;s outer diameter is small enough so the retracted tool may be moved past the casing patch in the horizontal leg while being inserted into the well; the mandrel, expanders and slips are configured, sized and comprised so the retracted slips&#39; O.D. is small enough so the tool is capable of being run through and past a 0.125 inch thick casing patch with a 4 inch to 4.892 inch inner diameter (I.D.) casing in the horizontal leg; each slip is movable radially outward by axial movement relative to its paired expander to an expanded slip position; the slips and expanders each being large enough to be located about the mandrel and large enough so axial movement of each slip over its paired expander will expand each slip to an expanded slip configuration where the slip has an outer diameter of 4.1 inches to 5.05 inches and is 15% wider than the slip&#39;s outer diameter in the retracted slip position; each expanded slip is capable of gripping the inner diameter of the casing and setting the outer teeth or inclusions into the casing during setting of the tool to the casing; the tool is configured, sized and comprised so the retracted tool is capable of being run past the casing patch in the horizontal leg, and then expanded to set into the casing, and then used in isolating and fracing in the horizontal leg; wherein each of the mandrel, expanders and slips is comprised of a material degradable in a natural aqueous downhole fluid in the well produced from formation flow in the well having a pH less than about 7, wherein the degradable material or materials are selected from the group comprising magnesium, or magnesium alloys or polymer acids, and the degradable materials of each of the mandrel, expanders and slips are either the same or different such degradable materials; the tool is configured and comprised to be interventionless, namely, within less than five days after the tool is immersed in a natural aqueous downhole fluid in the well produced from formation flow in the well having a pH less than about 7, the tool dissolves enough in the downhole fluid so the tool ceases to isolate the zone above the tool from a zone below the tool, without milling out the tool, retrieval of the tool from the well or other intervention on the tool from the surface; the tool is capable of degrading in the wellbore fluid enough to not obstruct production of hydrocarbons from the well without drilling out the tool; the tool is configured, sized and comprised so five such tools are capable of being run past the casing patch in the horizontal leg within the casing, set within the casing, and used in isolating and fracing zones in the horizontal leg past the casing patch; the first tool being run in, set and used in isolating and fracking, then the second tool being run in, set and used in isolating and fracking above the first tool, then the third tool being run in, set and used in isolating and fracking above the second tool, then the fourth tool being run in, set and used in isolating and fracking above the third tool, then the fifth tool being run in, set and used in isolating and fracking above the fourth tool, and the tool is configured, sized and comprised so production of hydrocarbons from the well can begin within less than five days after the tool is immersed in the well&#39;s downhole fluid without drilling out or retrieving the five such tools or other intervention on the  5  such tools from the surface. 
     In particular implementations, the tool&#39;s degradable materials are composed of both magnesium or magnesium alloys and also polymer acids. The tool may release from the well&#39;s casing and cease to isolate the zone above the tool from the zone below the tool more quickly than a similar tool in which the tool&#39;s degradable materials are comprised of only the tool&#39;s magnesium or magnesium alloys, or of only the tool&#39;s polymer acids. 
     In some implementations, the ramp surface of the expander comprises a multiplicity of flat surfaces. 
     In additional implementations, the ramp surface defines a ramp angle of between 12° and 18°. 
     The expanded slip&#39;s outer diameter may be 20% wider than the retracted slip&#39;s outer diameter. The slips may be composed of a body that is comprised of the degradable material and also comprised of inserts or wickers which are not degradable. 
     The tool may be configured, sized and composed so production of hydrocarbons from the well can begin within less than two days after the tool is immersed in the well&#39;s downhole fluid without drilling out or retrieving the five such tools or other intervention on the five such tools from the surface. 
     The tool may also be configured, sized and comprised so production of hydrocarbons from the well can begin within less than two days after the tool is immersed in the well&#39;s downhole fluid without drilling out or retrieving the five such tools or other intervention on the five such tools from the surface. 
     In particular implementations, a method of working on a hydrocarbon well having a vertical leg and a horizontal leg extending into a hydrocarbon bearing formation, the horizontal leg including a heel and a toe, the well having casing in the horizontal leg with an at least a 4½ inch outer diameter (O.D.) and not more than a 5½ inch outer diameter (O.D.), the casing having an inner diameter (I.D.) in the horizontal leg, and the casing having a series of casing patches reducing the ID of the casing in the horizontal leg may be achieved. The method may include providing at least five retracted settable downhole tools according to claim  1 ; selecting five such retracted tools, each retracted tool narrow enough to be run through and past a 0.125 inch thick casing patch in the horizontal leg, and each tool having slips which are expandable enough so after the tool passes through the casing patch the slips can be expanded to an expanded slip configuration having an O.D. within the range of a radial inner limit of a 15% expansion of the retracted tool&#39;s O.D. and the inner diameter the casing and the expanded tool&#39;s slips are capable of setting against the casing of the horizontal leg and holding the tool to the casing during fracing to isolate an upper zone in the horizontal leg above the tool from a lower zone below the tool; the method further comprising: the steps of running the five tools into the well and immersing the tools in a natural aqueous downhole fluid in the well produced from formation flow in the well having a pH less than 7, running the tools past the casing patch, setting the tools within the casing, and using the tools in isolating and fracing zones in the horizontal leg past one or more of the casing patches; the first tool being run in and set and used in isolating and fracing, then the second tool being run in and set above the first tool and used in isolating and fracing, then the third tool being run in and set above the second tool and used in isolating and fracing, then the fourth tool being run in and set above the third tool and used in isolating and fracing, then the fifth tool being run in and set above the fourth tool and used in isolating and fracing; waiting less than five days after the tools are immersed in the downhole fluid in the well for the tools to degrade in the wellbore fluid enough to permit production of hydrocarbons from the well; and producing hydrocarbons from the horizontal leg within less than 5 days after the tools are immersed in the downhole fluid in the well, without milling out or retrieving the five tools, or intervening on the tools from the surface after the five tools have been used in the fracing operations. 
     In some implementations, the method may include selecting tools which will degrade within less than two days; waiting less than two days after the tools are immersed in the downhole fluid in the well for the tools to degrade in the wellbore fluid enough to permit production of hydrocarbons from the well; and producing hydrocarbons from the horizontal leg within less than two days after the tools are immersed in the downhole fluid in the well, without milling out or retrieving the five tools, or intervening on the tools from the surface after the five tools have been used in the fracing operations. 
     In particular implementations, the method may include selecting tools which will degrade within less than one day; waiting less than one day after the tools are immersed in the downhole fluid in the well for the tools to degrade in the wellbore fluid enough to permit production of hydrocarbons from the well; and producing hydrocarbons from the horizontal leg within less than one day after the tools are immersed in the downhole fluid in the well, without milling out or retrieving the five tools, or intervening on the tools from the surface after the five tools have been used in the fracing operations. 
     In additional implementations, a method of working over a hydrocarbon well having a horizontal leg having casing of at least 4½″ O.D. and not more than 5½″ O.D. which was fraced through a series of first horizontally spaced perforations opening into a series of first horizontally spaced fractures may be provided. The method may include providing at least five retracted settable downhole tools according to claim  1 ; selecting five such retracted tools, each retracted tool narrow enough to be run through and past a 0.125 inch thick casing patch in the horizontal leg, and each tool having slips which are expandable enough so after the tool passes through the casing patch the slips can be expanded to an expanded slip configuration having an O.D. within the range of a radial inner limit of a 15% expansion of the retracted tool&#39;s O.D. and the inner diameter the casing and the expanded tool&#39;s slips are capable of setting against the casing of the horizontal leg and holding the tool to the casing during fracing to isolate an upper zone in the horizontal leg above the tool from a lower zone below the tool; running casing patches in the well, expanding the casing patches past an elastic limit into sealing engagement with the casing over the first series of horizontally spaced perforations and thereby covering up the first series of horizontally spaced perforations; producing second perforations in the casing past at least some of the casing patches and fracing the second perforations; selecting tools narrow enough to fit through casing patches in the horizontal leg&#39;s casing having an inner diameter which is 0.25 inches smaller than the horizontal leg&#39;s casing&#39;s inner diameter, each tool being expandable enough so after the tool passes through the casing patches, each tool&#39;s slips can be expanded to set against the casing, each tool&#39;s seal can be expanded to seal the tool to the casing, and each set tool can hold in the casing against fracing pressure; running a first selected tool into the casing past at least two of the casing patches and setting the first selected tool against the casing by expanding the tool&#39;s slips to within the range of a radial inner limit of a 15% expansion of the tool&#39;s O.D. and a radial outer limit of the interior diameter of the casing so the tool&#39;s slips set against the casing, and the set tool can hold in the casing against fracing pressure thereby isolating the second perforations; producing third perforations in the casing past at least some of the casing patches and fracing the third perforations; running a second selected tool into the casing past at least two of the casing patches and setting the second selected tool against the casing by expanding the tool&#39;s slips to within the range of a radial inner limit of a 15% expansion of the tool&#39;s O.D. and a radial outer limit of the interior diameter of the casing so the tool&#39;s slips set against the casing, and the set tool can hold in the casing against fracing pressure thereby isolating the third perforations; producing fourth perforations in the casing past at least one of the casing patches and fracing the fourth perforations; running a third selected tool into the casing past at least two of the casing patches and setting the third selected tool against the casing by expanding the tool&#39;s slips to within the range of a radial inner limit of a 15% expansion of the tool&#39;s O.D. and a radial outer limit of the interior diameter of the casing so the tool&#39;s slips set against the casing, and the set tool can hold in the casing against fracing pressure thereby isolating the fourth perforations; producing fifth perforations in the casing past at least some of the casing patches and fracing the fifth perforations; waiting less than five days after the tools are immersed in the downhole fluid in the well for the tools to degrade in the wellbore fluid enough to permit production of hydrocarbons from the well; and 
     producing hydrocarbons from the horizontal leg within less than two days after the tools are immersed in the downhole fluid in the well, without milling out or retrieving the five tools, or intervening on the tools from the surface after the five tools have been used in the fracing operations. 
     In some implementations, the method includes selecting tools which will degrade within less than two days; waiting less than two days after the tools are immersed in the downhole fluid in the well for the tools to degrade in the wellbore fluid enough to permit production of hydrocarbons from the well; and producing hydrocarbons from the horizontal leg within less than two days after the tools are immersed in the downhole fluid in the well, without milling out or retrieving the five tools, or intervening on the tools from the surface after the five tools have been used in the fracing operations. 
     In particular implementations, the method includes selecting tools which will degrade within less than one day; waiting less than one day after the tools are immersed in the downhole fluid in the well for the tools to degrade in the wellbore fluid enough to permit production of hydrocarbons from the well; and producing hydrocarbons from the horizontal leg within less than one day after the tools are immersed in the downhole fluid in the well, without milling out or retrieving the five tools, or intervening on the tools from the surface after the five tools have been used in the fracing operations. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a diagrammatic view of a horizontal well showing a set of perforations which have been fraced. 
         FIG. 2  is an enlarged view of a well section where a casing patch has been placed over an existing set of perforations. 
         FIG. 3  is a view, partly in cross-section, of a settable well tool. 
         FIG. 4  is a cross-sectional view of an expander cone used in the well tool of  FIG. 3 , the cross-section being taken along line  4 - 4  of  FIG. 6  as viewed in the direction indicated by the arrows. 
         FIG. 5  is a cross-sectional view of another embodiment of an expander cone. 
         FIG. 6  is an end view of the expander cones of  FIGS. 4-5 . 
         FIG. 7  is an end view of slips used in the well tool of  FIG. 3 . 
         FIG. 8  is a cross-sectional view of the slips of  FIG. 7 , taken substantially along line  9 - 9  thereof as viewed in the direction indicated by the arrows. 
         FIG. 9  is a cross-sectional view of the slips of  FIG. 6 , taken substantially along line  10 - 10  thereof as viewed in the direction indicated by the arrows. 
         FIG. 10  is a side view of the slips of  FIGS. 7 and 8 . 
         FIG. 11  is an isometric view of a slip segment following fracturing of the slips into a series of segments. 
         FIG. 12  is a back view of the slip segment of  FIG. 11 . 
         FIG. 13  is an isometric view of the slip segment of  FIGS. 11-12  after it has been fractured along a zone of weakness perpendicular to the tool axis. 
         FIG. 14  is an isometric view of the upper half of the slip segment of  FIG. 13  after it has been fractured along a second zone of weakness parallel to the tool axis. 
         FIG. 15  is an isometric view of the lower half of the slip segment of  FIG. 13  after it has been fractured along a second zone of weakness parallel to the tool axis. 
         FIG. 16  is an end view, similar to  FIG. 7 , of another embodiment of a set of slips; and 
         FIG. 17  is a partial isometric view of another embodiment of a set of slips. 
         FIG. 18  is a view, partly in cross-section, of a settable tool according to some embodiments of the ramp at the contact area between the slip and the expander cone. 
         FIG. 18A  illustrates the ramp angle where there is direct contact between at least part of the inner surface of a slip and at least part of the outer surface of an expander. 
         FIGS. 19, 19A, 19B, 19C, and 19D  are views of a flat ramp style expander cone. 
         FIGS. 20, 20A, 20B, 20C, 20D, and 20E  are views of a button style slip for use on some embodiments of Applicant&#39;s settable tool. 
     
    
    
     DETAILED DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS 
     The present invention relates to devices for use in hydrocarbon wells drilled into the earth and completed using a variety of techniques. Some of the components can be of metal, some non-metal, and some can be of composite material. A composite material can be a fabric core impregnated with a resin which is hardened in some suitable manner. Any components left in the well are usually made of drillable or degradable materials. Various changes and adaptations can be made in the tools without departing from the spirit and scope of the invention, which is to be measured solely by the claims themselves. 
     Referring to  FIGS. 1-2 , there is illustrated a hydrocarbon well  10  having a vertical well bore section  12  and a horizontal well bore section  14 . The horizontal well bore section  14  can extend through a hydrocarbon bearing formation  16 . A casing string  18  can be cemented in the well bore sections  12 ,  14  by a cement sheath  20 . The well  10  is illustrated as being a well that has already produced through a series of perforations  22 , which were stimulated by a frac job to provide a series of fractures  24 . In some situations, production from the well  10  can decline to an extent where it can be desirable to blank off the existing perforations  22  and fractures  24  and produce one or more new fractures. 
     The goal is to blank off the old perforations  22  and old fractures  24 , perforate a section between the old perforations  22  or beyond the most distant perforations and frac the new perforations. To this end,  FIG. 2  shows a casing patch  26  that has been run into the well  10  and expanded in a conventional manner to blank off the perforations  22  and the fracture  24 . Casing patches are conventional equipment and are available from Owen Oil Tools, Weatherford International, Baker Hughes Incorporated and various independent oil field service companies. Conventional casing patches are tubular and typically include an inner metal layer and a thin outer rubber or resilient layer. The patches initially have an O.D. slightly less than the I.D. of the casing into which they are run. When the patch is positioned at its desired location, a wedge is pulled through the patch stretching the patch beyond the elastic limit of the metal layer and forcing the patch against the inside of the casing. Because the metal layer is stretched beyond its elastic limit, the patch remains against the casing and does not relax to its original O.D. As mentioned, the difficulty is that the thickness of the casing patch reduces the I.D. of the casing string  18  and thereby complicates expanding a settable well tool against the inside of the casing string  18 . 
     Typically, a series of casing patches can be run into the well  10  and set across some or all existing perforations. Then, a first set of new perforations can be created at the most distant location from the surface, the first set of new perforations is traced to produce a first fracture and a bridge plug is set near the first new fracture to seal it off temporarily. This process is repeated as many times as desired to produce a series of new fractures, which hopefully will reestablish commercial production from the well  10 . This process is illustrated in  FIGS. 1-2  where the old perforations  22  are blanked off, a new set of perforations  28  are created and then fraced to produce a new fracture  30 . 
     To this end, a settable tool  32  which is illustrated, in one embodiment, as a bridge plug can be run above the first new set of perforations  28  in order to shoot a second set of perforations  34  and frac through them to create a second new fracture  36 . The plug  32  is illustrated as being of the type shown in U.S. patent application Ser. No. 12/317,497, filed Dec. 23, 2008, which is incorporated herein by reference for a more complete description thereof. The bridge plug  32  can comprise a mandrel  38 , a pair of slips  40 ,  42  which may be identical, a pair of expanders or expander cones  44 ,  46  which may be identical, an expandable seal  48 , a muleshoe  50  and a setting assembly  52  including a load ring  54  abutting the upper slips  40  and a sliding sleeve  56 . 
     In most applications, the settable tool  32  can be made of degradable materials. The mandrel  30 , the slip expanders  44 ,  46 , the tube  56 , the muleshoe  50 , and the reaction ring  54  are, in some embodiments, made of drillable or degradable materials selected from the group. Composites in some embodiments, including but not limited to, degradable magnesium or other degradable metals and degradable polymer acids (such as polyglycolic acid polymers or polylactic acid polymers) or other degradable non-metals. The seal  48  is typically of rubber or a degradable material and the slips  40 ,  44  may be of cast iron or degradable metal (see  FIG. 1 ). 
     In use, a wire line or other setting tool (not shown) is threaded onto a connection  58  and including a sleeve (not shown) abutting the sleeve  56 . By pulling up on the connection  58  and pushing down on the sleeve  56 , the reaction ring  54  pushes against the upper slips  40 . The expander cones  44 ,  46  are ultimately driven into the slips  40 ,  42 . The slips  40 ,  42  are fractured as explained more fully hereinafter and expand into engagement with the interior of the casing string  18  thereby wedging the bridge plug  32  securely against the inside of the casing string  18 . The seal  48  also expands against the inside of the casing  18  thereby providing a pressure seal. As heretofore described, those skilled in the art will recognize that the sett able tool  32  is set inside the casing  18  in a more-or-less conventional manner. 
     As explained previously, the settable tool  32  is capable of being run through the casing patch  26  or other restriction and then expanded into gripping engagement with the inside of the casing string  18 . Some prior art expander cones are made of a drillable composite material. These type materials can comprise a fabric impregnated with a resin, which is then cured to form a blank, which is then machined into a desired shape. One modification of the settable tool  32  that facilitates increased expansibility is the design of the expander cones  44 ,  46 . Simply increasing the angle of the frustoconical surface  60  of the cones  44 ,  46  and the complementary surface in the slips  40 ,  42 . With conventional east iron slips, the slips may not expand sufficiently to grip lightweight casing while being able to pass through a casing patch in heavy wall casing. Conventional cast iron slips are, of course, made as thin and lightweight as possible because the tools they are used with commonly need to be drilled up to prepare for a subsequent well operation. In addition, in some situations, the surface of the cone extruded between the segments of the slips during setting of the tool thereby failing to expand the slips sufficiently. In other situations, the slips were expanded sufficiently at the outset but the cones later extruded between the slip segments thereby allowing the slips to relax and retract away from the casing wall thereby inappropriately releasing the settable tool, from the casing. 
     In the embodiment of  FIG. 4 , the expander cone  44  is considerably harder, at least in the area of the surface  60 , than is conventional. Conventional composite materials used in well tools, i.e. fiberglass impregnated with a standard plastic resin, has a Rockwell B hardness in the range of 45-50. These materials have been proven to fail when used as an expander cone in an extended reach well tool. In some embodiments of the expander cone  40 , the hardness of a degradable frustoconical surface  60  (which may also be termed ramp angle) is at least 70 on the Rockwell B scale and preferably is at least 80, which, in the right situation, can be sufficient to prevent extruding the expander cone between the slip segments. The ability of the expander cone to withstand the forces of an extended reach tool may depend on other factors such as tensile or compressive strength, meaning the higher the better. 
     Increasing the ramp angle of the surface  60  and increasing the hardness of the surface  60  provides a partial solution to increased expansibility and, in one approach, one might increase the expansibility of settable well tools without providing a single device that would operate over the entire range necessary for operation in a specific sized casing. For example, one might provide two slightly different tools for operation in 5½″ casing, e.g. one tool for 5½″ casing weighing 15.5#- 17 #/foot and a second tool for 5½″ casing weighing 20-26#/foot. In situations like this, one could design a tool using a high angle in a range of 20 degrees or more, expandable cone, which may also be of suitable hardness and strength to provide the increased expansibility. 
     The expander cone  44  can otherwise be of conventional shape and can comprise a body  62  having a central passage  64  and one or more set screw passages  66  for securing the expander cone  44  to the mandrel  30 . In some embodiments, the bottom of the expander cone  44  includes a series of tapered segments  68 , which receive the seal  48 . When the tool  32  is set against the casing  18 , the segments  68  may act like flower petals and constrain movement of the seal  48  into sealing engagement with the casing  18 . In some high pressure situations, a metal cone or anti-extrusion ring can be provided to further constrain movement of the seal. The cone  44  can be scored to split and thereby create the segments  68  in an appropriate manner during expansion of the seal  48 . 
     To promote reliable fracturing of the slips  40 ,  42 , a guide or series of guides  72  may be provided that will act in a manner to be disclosed more fully hereinafter. The guides  72  can comprise a pin glued in a blind passage  74 , can comprise a set screw threaded into the passage  74  or can comprise any mechanism providing an abutment or shoulder  76  extending above the conical surface  60 . 
     Referring to  FIG. 5 , there is illustrated another embodiment of a two-piece expander  98  having a one end  100  of a first material and a conical end section  102  of a second material. First and/or second materials  100 / 102  may be comprised of a degradable material. The end  100  can be shaped and configured as in the expander  44  having a threaded connection  104  for receiving threads  106  provided by the end section  102 . One or the other of the sections  100 ,  102  may have passages  108  for receiving set screws  110  to fix the expander  98  to the mandrel  38 . The expander  98  can have a guide or series of guides  112  on the conical surface  114  to promote reliable fracturing of the slips  40  as explained more fully hereinafter. If desired, the function of the guides  112  can be accomplished by selecting the set screws  110  to extend beyond the conical surface  114  as will become more fully apparent hereinafter. 
     Another approach to increase the expansibility of the settable well tool  32  is to increase the thickness of the cast iron slips. This is counterintuitive because it is often desirable to drill up settable well tools and thicker cast iron slips segments are much harder to drill up, meaning that one has traded one large advantage for one large disadvantage. 
     Upon expansion of the well tool into engagement with the casing, the slips move relative to the expanders. Because the slips are made with a series of external grooves parallel to the tool axis  116 , the slips fracture into a series of substantially identical elongate slip segments which are parallel to the tool axis  116 . When conventional cast iron slips are thickened in an attempt to increase the expansibility of a well tool, the well tool inherently becomes more difficult to drill up. 
     To avoid this disadvantage, the slips  40 ,  42  are designed to fracture into an unusually large number of small pieces. Standard cast iron slips fracture into a number of elongate slip segments corresponding to the number of external grooves that promote fracturing. Thus, conventional cast iron slips typically comprise six or eight grooves causing the slips to fracture into six or eight elongate slip segments. As disclosed herein, the slips  40 ,  42  also fracture into a series of elongate slip segments and each slip segment can further fractured into at least two pieces and may preferably be fractured into at least four pieces. It is believed that fracturing first occurs along the external grooves but it is not material in which order fracturing occurs. The important thing is that the slips are reduced during setting of the well tool to a larger number of pieces. Because there are more slip pieces, each slip piece weighs much less than conventional slip pieces, meaning they are much easier to circulate out of the well without much, if any, drilling of the pieces. 
     Reducing the slips to pieces that are much smaller and lighter is accomplished by providing additional zones of weakness that induce fracturing when the slips  40 ,  42  are being expanded by the expanders  44 ,  46 . Some of these zones of weakness may be parallel to the tool axis  116  and some may be transverse to the tool axis  116 . As shown in  FIGS. 7-15 , the slips  40  include a body  118  that may be of one piece but which may be multipiece that is held together by a suitable mechanism in the retracted position shown in  FIG. 3 . The slip body  118  includes a central passage  120  having a tapered or conical surface  122 , which is at a complementary angle to the conical surfaces  60 ,  86 , and  114  of the expanders  44 ,  78 ,  98 . 
     The slip body  118  can include a series of grooves  124 ,  126  which can be on the exterior of the slips and which can divide the slips into a series of more-or-less identical slip segments  128 . In some embodiments, some of the grooves  124  may be considerably deeper or more pronounced than alternate grooves  126 . This is believed to cause fracturing along the grooves  124  first but the order in which fracturing occurs is not material. It will be seen that the grooves  124 ,  126  produce zones of weakness parallel to the tool axis  116 . 
     Each of the slip segments  128  includes teeth or wickers  130  on the exterior that grip the casing  18  when the slips  40  are expanded. It may be preferred to heat treat the slips  40 ,  42  so that only the surface of the wickers  130  is hardened. Some or all of the slip segments  128  can include a second zone of weakness or notch  132  transverse to the tool axis  116  which causes the slip segment  128  to fracture into upper and lower halves  134 ,  136  as shown in  FIG. 14 . As shown best in  FIG. 11 , the notches  132  lie in a common plane. The notch or crease  132  is distinct from the inside edge or inside I.D.  138  of the teeth  130  because conventional east iron slips do not fracture at the edge  138 . In this device, the notches  132  may be coincident with one of the tooth edges  138  and, in the illustrated embodiment, are very close to one of the tooth edges  138 . The second zone of weakness  132  accordingly divides the slip segment  128  into two pieces. 
     As will be explained more fully hereinafter, the segment halves  134 ,  136  may vary in the range of ⅓ to ⅔rds of the weight of the slip segment  128  and may preferably each be about half the weight of the slip segment  128 . Another relevant characteristic is the tendency of the segment halves  134 ,  136  to fall by gravity through an upwardly moving body of liquid. The segment halves  134 ,  136  may preferably be equally propelled upwardly in a column of moving liquid so they may be circulated out of a well with little or no additional reduction in size, as from drilling. Thus, the location of the notch or crease  132  may vary considerably along the long dimension of the slip segment  128 . It will be seen that the slips  40 ,  42  can be wholly of metal (which may, in some embodiments, be degradable, a magnesium alloy, for example) or may comprise non-metallic inclusions but, in any event, the metal of the slips  40 ,  42  is continuous and provides the structural strength and integrity of the slips  40 ,  42 . 
     A more sophisticated approach is to determine a cross-sectional parameter of the upper and lower segment halves  134 ,  136  that is related to their movement in an upwardly moving column of liquid. This parameter and the weight of the segment halves may be combined to provide an optimum location for the crease  132 . 
     As shown best in  FIGS. 7, 11, 13 and 14 , some or all of the slip segments  128  provide a third zone of weakness or passage  140  opening between the conical surface  122  and an end  142  of the slip body  118 . Although the passage  140  is conveniently illustrated as a cylindrical hole, it may be of any desired shape. The third zone of weakness can accordingly be generally parallel to the tool axis  116 . During setting of the slips  40 , the slip segment halves  134 ,  136  can divide roughly into mirror imagine halves  144 ,  146 , meaning that each slip segment  128  has the potential to divide into four slip pieces. 
     It will be apparent that the slip segments  128  can include multiple horizontal creases or notches  132  thereby dividing the slip segments  128  into more than two horizontal pieces. In addition, the slip segments  128  can include multiple zones of weakness parallel to the tool axis thereby dividing the slip segments  128  into more than two vertical pieces. 
     Setting of the well tool  32  will now be described. The tool  32  can be run on wireline and can be conveyed by slickline or wireline and can be dropped, pumped or run on coiled tubing into the well  10 . When it reaches its desired location, a setting tool (not shown) pulls on the connection  58  and pushes on the reaction ring  54 . This causes the mandrel  38  to move upwardly in  FIG. 3  so the expanders  44 ,  46  move into the central passages of the slips  40 ,  42 . In the expanded position of the tool  32 , the guides  92  can be located in or near the entrance to the grooves  124 ,  126  so the guides  92  enter the grooves  124 ,  126  and guide the slips  40 ,  42  in a predictable manner toward the expanders  44 ,  46 . This can prevent the slips  40 ,  42  from fracturing only on one side thereby preventing the slips  40 ,  42  from clamshelling. 
     Continued pulling on the connection  58  causes the expanders  44 ,  46  to nest further in the slips  40 ,  42 . Soon, the slips  40 ,  42  fracture along zones of weakness provided by the grooves  124 ,  126 . It is believed the larger grooves  124  fracture first although the sequence or order of fracturing is not material. This produces the series of separate slip segments  128 . Continued pulling on the connection  58  causes the expanders  44 ,  46  to nest further in the slips  40 ,  42 . Shortly, the slip segments  128  can fracture to produce the pieces  134 ,  136  and the pieces  134 ,  136  can fracture to produce four pieces for every slip segment as shown in  FIGS. 14-15 . 
     Some slips may be designed to run in small enough casing to produce slip pieces of a desirable size if the slip segments  128  fracture into only two pieces. However, it may be preferred for each slip segment  128  to fracture into four pieces regardless of the size casing in which the slips  40  are run. It may be that some of the slip segments  128  do not fracture completely because of strange events but the complete fracturing of any slip segment increases the drillability of the slips  40 ,  42  and is thus of considerable advantage. At the end of relative movement between the slips  40 ,  42  and expanders  44 ,  46 , the upper end of the well tool  32  parts along a necked down area  148  so the connection  58  and sleeve  56  can be pulled out of the well  10 . 
     If one is to drill up the well tool  32 , a bit or mill on the bottom of coiled tubing or on the bottom of a work string is run into the well  10 . The bit is rotated and advanced into engagement with the settable tool  32  thereby drilling up the sleeve  56  part of the mandrel  30 , and the reaction ring  54 . The bit is typically small enough to pass through the expanded slip pieces and can drill on the upper expander  44 . When enough of the upper expander  44  is drilled up, the pieces from the slips  40  are no longer jammed against the casing  18  whereupon the slip pieces are circulated out of the well  10  by liquid pumped down the coiled tubing or down the work string. 
     The slip pieces created by fracturing the slips  40  may preferably be small enough and light enough to be circulated out of the well  10  without further reduction in size. Circulation can be down through a coiled tubing or conventional tubing string and up in the annulus between the tubing and casing  18  or circulation can be down in the annulus between a tubing and casing strings and up inside the tubing. The upward velocity needed to circulate the slip pieces out of the well depends on the density of the circulating liquid or gas and properties of the slip pieces, i.e. their cross-sectional size and weight. The pieces of the slip segments can be as small and as light as possible, consistent with maintaining a grip on the inner casing wall. In well tools of increased expansibility, the pieces may preferably weigh less than one ounce and, in well tools of standard expansibility, the pieces may preferably weigh less than ¾ ounce or even one half ounce. Cast iron pieces of these sizes are readily circulated out of the well  10  at typical pumping volumes. Irregular as they are, pieces of the slip segments are not stable during upward movement as a sphere might be. The slip pieces will likely tumble during movement inside the well  10 . 
     Most wells are completed using a water based completion liquid inside the casing string  18 . A typical completion liquid is 2% by weight KCl in water or 2% by weight KCl in water with some HCl and having a density of about 9#/gallon. An upward velocity sufficient to circulate the slip pieces upwardly is less than about 400 feet/minute in a 9#/gallon completion liquid. In most situations, normal pumping volumes produce upward velocities of less than about 200 feet/minute is adequate to circulate the slip pieces out of the well  10  without further reduction in size. In a typical example, pumping four barrels per minute downwardly through  2 ″ O.D. coiled tubing produces an upward velocity of about 360 ft/minute inside 4½″ O.D.  13 . 5 #/foot casing having an I.D. of 3.925″. It is recognized that not all slips segments might not fracture into two or four pieces. However, reduction of some of the slip segments into smaller pieces will allow the smaller pieces to be easily circulated out of the well  10  thereby facilitating drilling up the well tool  32 . In actual field situations, a screen or basket on the return line recovers large numbers of slip segments without further reduction in size than created by the weakened zones in the slips. 
     Referring to  FIG. 16 , there is illustrated another embodiment of a set of slips  150 . The slips  150  may differ from the slips  40  in the shape of the passage  152  through the slip body. The passage  152  is a groove opening through the tapered section, through one end  154  and through a central passage or side  156  of the slip body. 
     Referring to  FIG. 17 , there is illustrated another embodiment of a set of slips  160  comprising a series of individual elongate unitary metal slip segments  162  which can be more-or-less identical and which extend about the periphery of a mandrel even though only three are shown in  FIG. 18 . The slip segments  162  can be more-or-less identical to the segments  128  except the segments  162  are separate and independent. Some or all of the slip segments  162  include a plane or zone of weakness  164  running parallel to an axis  166  of the slips  160  and axially of a tool of which  FIG. 3  is an example. This may be accomplished by the provision of a passage  168  extending through the slip segments  162 . Some or all of the slip segments  162  include a plane or zone of weakness  170  extending transverse to the axis  166 . The segments  162  can be individually mounted in the manner of the slips  47  and restrained in any suitable manner, as by the provision of frangible wire, frangible pins, or other suitable means. In use, the slips  160  operate in much the same manner as the slips  47  except there is no requirement for the slips to break into parallel segments since the segments  162  start out as independent elements. In other words, the slip segments  162  fracture along the zones of weakness into at least two and preferably four or more slip pieces. 
     One process of working over a horizontal well to frac between old perforations/fractures will now be described in conjunction with  FIGS. 1 and 2 . Casing patches  26  are run into the casing  18  adjacent each set of existing perforations  22  and set, usually by expanding the casing patch  26  into permanent engagement with the inside of the casing. This may seal off all or selected ones of the old perforations. A new set of perforations  28  is created near the end of the horizontal leg  14  of the well  10  and first set of new perforations are fraced to produce a new fracture  30 . A plug  32  is run into the casing  18  past one or more casing patches  26  to a location above the new fracture  30  and then set against the casing  18  thereby isolating the new fracture. A second new set of perforations  28  is created nearer the surface of the well  10  and then traced to produce a second new fracture. A plug  32  is run into the casing  18  past one or more casing patches to a location above the second new fracture and then set against the casing  18  thereby isolating the new fracture. This process is repeated until the desired number of new fractures are created, typically more than five. The settable tools  32  are then drilled up with a bit or mill on the bottom of coiled tubing or on the bottom of a tubing string or, may degrade without drilling. Because the slips  40 ,  42  are broken into so many pieces, the settable tools  32  can be quietly drilled up or may degrade without drilling. This is most unusual because multiple cast iron bridge plugs of the prior art that are capable of passing through casing patches cannot be drilled up by coiled tubing units. Even if one cast iron bridge plug could be drilled up, a second cast iron bridge plug cannot be drilled up because of debris from the first bridge plug and the worn character of the bit. 
     In one example, a set of slips  40  having an O.D. of 4.25″ was designed to run in a tool of conventional expansibility inside unobstructed  5 ½″ casing weighing between 17-26#/foot, meaning that the casing I.D. is in the range of 4.892-4.548″. The slips  40  had ten grooves  124 ,  126  providing ten slip segments  128 . The weight of the slips  40  was 1 pound 7.3 ounces, meaning that each slip segment  128  weighed about 2.3 ounces and each of the slip pieces, after setting, weighed in the range of from less than about ½ ounce to about ¾ ounce, averaging 0.58 ounces. Slip pieces of this size can easily be circulated, out of a horizontal or vertical well without further reduction in size by drilling. 
     Sets of exemplary slips for conventional normally expansible well tools are found in Table II: 
     
       
         
           
               
               
               
               
               
               
               
               
             
               
                 TABLE II 
               
               
                   
               
               
                 Size of 
                 O.D. of 
                 I.D. of 
                 Weight of 
                 Number of 
                 Ave wt of 
                 Number of 
                 Ave wt of 
               
               
                 casing 
                 slips 
                 slips 
                 slips 
                 segments 
                 segments 
                 pieces 
                 pieces 
               
               
                   
               
             
            
               
                 4½″ 
                 3.45″ 
                 2.02″ 
                 20.8 oz 
                 8 
                 2.60 oz 
                 8 
                 2.60 oz 
               
               
                 5½″ 
                 4.25″ 
                 2.85″ 
                 34.0 oz 
                 8 
                 4.25 oz 
                 8 
                 4.25 oz 
               
               
                   
               
            
           
         
       
     
     Sets of exemplary slips for improved slips for normally expansible tools are found in Table III: 
     
       
         
           
               
               
               
               
               
               
               
               
             
               
                 TABLE III 
               
               
                   
               
               
                 Size of 
                 O.D. of 
                 I.D. of 
                 Weight of 
                 Number of 
                 Ave wt of 
                 Number of 
                 Ave wt of 
               
               
                 casing 
                 slips 
                 slips 
                 slips 
                 segments 
                 segments 
                 pieces 
                 pieces 
               
               
                   
               
             
            
               
                 4½″ 
                 3.45″ 
                 2.02″ 
                 16.0 oz 
                 10 
                 1.6 oz 
                 40 
                 .40 oz 
               
               
                 5½″ 
                 4.25″ 
                 2.85″ 
                 24.0 oz 
                 10 
                 2.4 oz 
                 40 
                 .60 oz 
               
               
                   
               
            
           
         
       
     
     Sets of slips of exemplary slips for improved slips for extended reach or increased expansibility tools are found in Table IV: 
     
       
         
           
               
               
               
               
               
               
               
               
             
               
                 TABLE IV 
               
               
                   
               
               
                 Size of 
                 O.D. of 
                 I.D. of 
                 Weight of 
                 Number of 
                 Ave wt of 
                 Number of 
                 Ave wt of 
               
               
                 casing 
                 slips 
                 slips 
                 slips 
                 segments 
                 segments 
                 pieces 
                 pieces 
               
               
                   
               
             
            
               
                 4½″ 
                 3.00″ 
                 1.55″ 
                 29.0 oz 
                 6 
                 4.83 oz 
                 24 
                 1.21 oz 
               
               
                 5½″ 
                 3.90″ 
                 2.53″ 
                 32.0 oz 
                 8 
                 4.00 oz 
                 32 
                 1.00 oz 
               
               
                   
               
            
           
         
       
     
     The number of slip segments, in the slips can vary as desired. As larger diameter slips are made, there can be mere grooves  124 ,  126  and thus more slip segments  128 . 
     In an example of the expansibility of a settable well tool described herein, a horizontal well was drilled in Rio Blanco County, Tex. and 5″ O.D., 23#/foot casing cemented therein. Casing of this size has a nominal I.D. of 4.044″. It appears that minor dog legs, or direction changes, in the path of the well bore at the transition of vertical to horizontal, known as the curve or heel, caused the casing to be deformed so the interior of the casing was partially restricted to an extent where conventional 3.85-3.92″ O.D. composite bridge plugs could not be forced through the heel. Because the I.D. of this heavy wall 5″ casing is only 4.044″, a bridge plug for nominal 4½″ casing could, be run into the well. Six 3.25″ O.D. bridge plugs of the type disclosed herein were run through the heel into the horizontal leg of the well with no apparent dragging. In the process of fracing a hydrocarbon formation to create a series of fractures, all six bridge plugs were set against, the casing. At the end of the fracing operation, all of the bridge plugs were drilled up in one bit run to allow hydrocarbon production upwardly in the well. The bridge plugs met all of the required performance expectations during all stages of completing the well. The alternative to the well owner was to redrill the well at a cost above $4,000,000. 
     Although the slips  40  are particularly adapted for use in horizontal wells, it is apparent that an increase in drillability is desirable for settable well tools used in vertical wells. Thus, slips that are fractured in many pieces are likewise advantageously used in vertical wells thereby increasing the drillability of settable well tools. 
     The great majority of horizontal oil or gas wells are completed through 4½″,  5 ″, or 5½″ casing. Standard composite settable tools, for casing strings of these sizes, are capable of expanding, as defined below, about 11%. Extended reach tools or increased expansibility tools have the capability of expanding at least 15% and can preferably expand greater than 20%. The disclosed settable tool is capable of movement between a retracted position and an expanded position gripping the inner casing wall of these size casing strings. The expansibility of the disclosed well tools may be calculated as % expansibility=(exp. O.D.-ret. O.D.)/ret. O.D. times 100 (where exp. O.D. is the expanded outer diameter of the tool and ret. O.D. is the retracted outer diameter of the tool). The O.D. of the packer or rubber element of settable tools is typically slightly larger, e.g. 0.030″, than the O.D. of the slips to prevent the slips from snagging some obstruction in a well. Thus, Table V shows the percent expansibility of the tools of Tables II-IV, as follows: 
     
       
         
           
               
             
               
                 TABLE V 
               
             
            
               
                   
               
               
                 Expansibility of Tools 
               
            
           
           
               
               
               
               
               
               
            
               
                   
                   
                   
                   
                 Maximum 
                   
               
               
                   
                   
                 Slip  
                 Retracted 
                 expanded  
                 %  
               
               
                   
                   
                 O.D. 
                 Tool O.D. 
                 tool O.D. 
                 expansibility 
               
               
                   
                   
               
            
           
           
               
            
               
                 Normally expansible tools of Tables II and III 
               
            
           
           
               
               
               
               
               
               
            
               
                   
                 4½″ 
                 3.00″ 
                 3.25″ 
                 4.10″ 
                  9.3% 
               
               
                   
                 5″ 
                 3.82″ 
                 4.12″ 
                 4.60″ 
                 11.6% 
               
               
                   
                 5½″ 
                 4.25″ 
                 4.55″ 
                 5.05″ 
                 10.9% 
               
            
           
           
               
            
               
                 Extended reach tools of Table IV 
               
            
           
           
               
               
               
               
               
               
            
               
                   
                 4½″ 
                 3.00″ 
                 3.25″ 
                 4.10″ 
                 24.2% 
               
               
                   
                 5″ 
                 3.60″ 
                 3.75″ 
                 4.60″ 
                 21.1% 
               
               
                   
                 5½″ 
                 3.88″ 
                 4.18″ 
                 5.05″ 
                 20.8% 
               
               
                   
                   
               
            
           
         
       
     
     Of course, it may be desirable to provide two models for each casing size, one for relatively thin wall pipe, and one for relatively thick wall pipe. This can have an effect on the desired expansibility of any particular tool. 
       FIGS. 18 and 18A  illustrate a configuration of a settable downhole tool  32  that has one or more elements made from a material degradable in a downhole fluid. Some of these degradable materials may be found in the three patents and the patent application that are incorporated by reference in this application. In  FIGS. 18 and 18A , elements  207 / 208  and  213  are expander (or backup) cones. Element  214  is the slip or gripping element, having a body  214   a  and buttons  14   b . Note the expander cone  213  has, in some embodiments, an outer surface that is frustoconical and slip  214  has an inner surface that is frustoconical and in direct contact with at least part of the outer surface of the cone. In some embodiments, slip body  214   a  may be metallic or nonmetallic, and in some embodiments, a degradable metal, such as high strength magnesium alloy under the trademark available as Solumag from Magnesium Electron. Other high strength degradable magnesium alloys are available from Bubbletight, Needville, Tex., and under the Tervalloy trademark, Terves Inc., Euclid, Ohio. Slip  214  may be a button style slip unlike the cast iron wicker slips of earlier embodiments. The slip and cone elements may together act as a “setting couple” which acts functionally to cause, during setting, expansion of the slip as it breaks up while riding up the frustoconical ramp surface provided by the cone (see  FIG. 18A ). This ramp surface  60 , in some embodiments, may be in the range of 12 to 18°, and less than ramp surface angles in similar prior art setting couples. The tool in  FIG. 18 , in some other embodiments, has an overall length of 31.4 inches (in some embodiments, between 29 and 32 inches) and an outer diameter, in an unset position, of 3.75 inches, giving an aspect ratio of 7.3. This is believed to be greater than for prior art similar tools. In some embodiments of the tools disclosed herein, the aspect ratios may range between 4.5 and 9.0. 
     Cones and/or slips and any other elements may be made of a degradable metallic material such as a high strength magnesium alloy, and in one case, SoluMag from Magnesium Elektron. Slip buttons  214   b  may be degradable or nondegradable, such as nondegradable cast-iron. Buttons  214   b  are typically small enough so that when the other elements of the tool dissolve, the buttons will circulate out of the well. There may be other small, non-dissolvable elements in the tool, such as setscrews. The number of pieces that the slip may break into during setting may range from 8 to 40 or any other range disclosed herein. 
     In  FIGS. 18 and 18A , some of the degradable elements include one or more of the following: mandrel  201 , thrust ring  202 , retainer body lock ring  203 , load ring  204 , mandrel lock ring  205 , wicker slip  206 , first part backup cone  207  (typically metal), second part backup cone  208  (may be non-metal), backup rings  209 / 210 , elastomeric element end  211 , and elastomeric element center  212 . Note that in  FIG. 18 , the up hole end (left as seen) of the tool has a two-part expander cone and a cast-iron wicker slip  206 . In another preferred embodiment, settable tool  10  may be symmetrical. Settable couple  213 / 214  as illustrated may be used as the settable couple at the top of the cone “up hole” of the elastomer—that is to say the same settable couple in  FIG. 18  may be on the down hole side of the elastomer. 
     As discussed and described in more detail below, any one or more components of the long reach settable tool  32 , including any of the body, rings, slips, conical members or cones, malleable or sealing elements, shoes, drop or check balls, impediments, etc., can be fabricated from one or more drillable, degradable or decomposable materials. In some embodiments, suitable materials will at least partially decompose, degrade, degenerate, melt, combust, soften, decay, break up, break down, dissolve, disintegrate, break, dissociate, reduce into smaller pieces or components, or otherwise fall apart when exposed to one or more predetermined conditions. These can be or can include certain wellbore conditions or environments, such as predetermined wellbore fluid temperature, pressure, pH, salinity, and/or any combinations thereof. 
     Fluid communication through settable tool  32  can be prevented for a predetermined period of time, e.g., until and/or if the decomposable material(s) falls apart, e.g., degrades 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 some embodiments, the predetermined period of time can be sufficient to workover the well. The predetermined period of time can range from minutes to days. For example, the decomposable or degradable rate of the material can range from about 4 hours to about 12 hours, as 24 hours or 48 hours. In another example, the decomposable or degradable rate of the material can be from a low of about 1 hour, about 2 hours, about 4 hours, about 8 hours, or about 12 hours to a high of about 1 day, about 2 days, about 3 days, about 4 days, or about 5 days. In at least one embodiment, the decomposable or degradable rate of the material can be sufficient so fluid may flow through the settable tool  32  in less than 5 days, less than 4 days, less than 3 days, less than 2.5 days, less than 2 days, less than 1.75 days, less than 1.5 days, less than 1.25 days, less than 1 day, less than 0.75 days, less than 0.5 days, or less than 0.25 days. Extended periods of time are also contemplated. 
     The pressures at which the components of settable tool  32  degrade can range from less than atmospheric pressure to about 15,000 psig, about atmospheric pressure to about 15,000 psig, or 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 component of settable tool  32  made from or otherwise, including the decomposable material, can degrade range from about 0° C. to about 800° F., about 100° F. to about 750° F. For example, the temperature can range from a low of about 20° F., 100° F., 150° F., or 200° F. to a high of about 350° F., 500° F., or 750° F. In another example, the temperature at which the decomposable material can degrade can be at least 100° F., at least 125° F., at least 150° F., (in one range, about 100-150° F.) at least 175° F., at least 200° F., at least 250° F., at least 275° F., at least 300° F., at least 325° F., at least 350° F., at least 375° F., or at least 400° F. and less than 750° F., less than 725° F., less than 700° F., less than 675° F., less than 650° F., less than 625° F., less than 600° F., less than 575° F., or less than 550° F. 
     The degradable material(s) can be soluble in any material, such as soluble in water, polar solvents, non-polar solvents, acids, bases, mixtures thereof, or any combination thereof and any natural downhole fluid, such as formation fluid. 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 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 element(s) of settable tool  32  degrade 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. If the predetermined condition is or includes a pH, the degradable material can be exposed to a fluid having a pH of from a low of about 1, about 2, about 3, about 4, about 5, or about 6 to a high about 8, about 9, about 10, about 11, about 12, about 13, or about 14. In some embodiments, the pH of the fluid around settable tool  32  or at least the element thereof containing the degradable material can be modified, adjusted, controlled, or otherwise changed by introducing one or more acids, one or more bases, or one or more neutral compounds thereto. When one of the elements is comprised of an acid based material, such as PGA or PLA, and another element is a degradable reactive metal, such as magnesium, a synergistic effect may accelerate the rate of degradation. As the polymer acid degrades, it may increase the pH of the local fluid, which may increase the rate of degradation of the metal. The dissolution of the metal may be exothermic, and increase the temperature, to further benefit rapid degradation. As the materials degrade, surface area may increase, also benefitting rapid degradation. One such metal/polymer acid combination is the settable couple disclosed herein. 
     In some embodiments, the degradation occurs by contacting the decomposable material with naturally occurring aqueous downhole fluids. 
     While  FIG. 18  shows a setting couple comprising frustoconical contacting surfaces, the 19 series and 20 series of figures show, respectively, a setting couple comprising flat ramp cone  300  and flat ramp slip  346 .  FIGS. 19, 19A, 19B, and 19C  illustrate a flat ramp style cone  300 . This is in comparison to the cylindrical ramp cones of the preceding figures. Flat ramp cone  300  includes an outer surface  302 , outer surface  302  seen to comprise, as in  FIGS. 19 and 19A  a first section  303  and a second section  305 , the two sections separated by groove  307  defining a gap. Flat ramp cone  300  has an inner surface  308 . A first end wall  304  and a second end wall  306  separates the inner surface from the outer surface. Turning to outer surface  302 , it is seen that first section  303  includes a multiplicity of flats  310  here, six—see  FIG. 19 . There may be any number of flats between 4 and 8, for example. Guides  312  are raised “V” shaped portions between adjacent flats, to help position and guide the slip. Guides  312  are seen to have a nose  316 . Second section  305  is seen to comprise multiple petals  318 , the petals separated from one another by partial cuts  314 . Part of petals  318  have an inner surface comprising a sealing engaging surface  320  for engaging a surface of the elastomeric sealing element, which in some embodiments, is degradable. 
     Ramp cone  300  may be comprised of any suitable material. In some embodiments, ramp cone  300  is a degradable metallic or nonmetallic material. In some embodiments, the degradable metallic material is a magnesium alloy as described elsewhere herein. 
     Functionally, flat ramp cone  300  acts in the manner of prior art cones in the sense that it applies radially outward forces to the slip, here the segmented, button style slip body  340  (see  FIGS. 20 and 20A , for example). The setting couple comprising flat ramp cone  300  and flat ramp button style slip  340  acts, during setting, to cause the slip to grippingly engage the inner wall of the casing. Multiple petals  318  engage, in an unset position, the outer angled walls of the elastomeric sealing element with cuts  314  and groove  307  allowing the petals to peel back on the elastomer during compression and setting to help avoid extrusion of the elastomer during setting and post setting operations, such as fracking operations. 
       FIGS. 20, 20A, 20B, 20C, 20D, and 20E  illustrate the flat ramp, button style slip  340  that, in some embodiments, is used in conjunction with flat ramp cone  300 . Flat ramp button style slip  340  may include a body  342  and multiple buttons  344  angularly recessed partly into the outer surface  352  of the body. The body may also have an inner surface, which may be part multiple flat ramp segments  354 , and the inner surface part may be cylindrical  356 . Multiple flat ramp segments  354  directly contact complementary flats  310  of cone  300  at a ramp angle of, in some embodiments, 12° to 18°. The outer surface and the inner surface may be separated by first (tapered) wall  358  and second (flat) wall  360 . Body  342  may be made of any suitable material. In some embodiments, body  342  may be made of degradable or non-degradable materials as disclosed herein. In some embodiments, the degradable material may be a metal and may be a degradable magnesium as disclosed elsewhere herein. Buttons  344  may be cast-iron buttons (non-degradable) or buttons made of any other suitable material. Body  342  is seen to have multiple segments  346 , the number of segments corresponding to, size and position the flats  310  of the flat ramp style cone, see  FIG. 19 , for example. In this embodiment, there are six segments  346  (each with a flat ramp segment  354 ) corresponding to the six flats  310  and adapted to lay adjacent of the flat ramp style cone. There may be ten or less segments, in some embodiments, and up to six buttons on each segment. Segments  346  are separated by inter segment gaps  348  which are bridged by multiple connection bridges  350 . Here each segment engages an adjacent segment through two common connection bridges  350 , see  FIG. 20  for example. Note the shape of the intersegment gap  348  is complementary to raised guides  312  on flat ramp cone  300 , guides  312  having a “V” shape as a first portion  348   a  of intersegment gap  348 . 
     The present invention is adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. No limitations are intended to limit the details of construction or design shown, other than as described in the claims below. The illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present invention. For example, any structural elements and materials disclosed herein may be used apart from the long-reach configuration of the smaller than normal plug O.D.—on any suitable tool. 
     The terminology used herein is for the purpose of describing particular implementations only and is not intended to be limiting. The singular form “a”, “an”, and “the” are intended to include the plural forms as well, unless the context clearly indicates otherwise. The terms “comprises” and/or “comprising,” when used in the this specification, specify the presence of stated features, integers, steps, operations, elements, and/or components, but do not preclude the presence or addition of one or more other features, integers, steps, operations, elements, components, and/or groups therefore. Compositions and methods described in terms of “comprising,” “containing,” or “including” various components or steps, can also “consist essentially of” or “consist of” the various components and steps. 
     Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. Every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a to b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. The terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. If there is any conflict in the usages of a word or term in this specification and one or more patent(s) or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted. 
     The corresponding structure, materials, acts, and equivalents of all means or steps plus function elements in the claims below are intended to include any structure, material, or act for performing the function in combination with other claimed elements as specifically claimed. The description is presented for the purposes of illustration and description, but is not intended to be exhaustive or limited to the implementations in the form disclosed. Many modifications and variations will be apparent to those of ordinary skill in the art without departing from the scope and spirit of the disclosure. The implementations were chosen and described in order to explain the principles of the disclosure and the practical application and to enable others or ordinary skill in the art to understand the disclosure for various implementations with various modifications as are suited to the particular use contemplated. Those skilled in the art will readily recognize that a variety of additions, deletions, modifications, and substitutions may be made to these implementations. Thus, the scope of the protected subject matter should be judged based on the following claims, which may capture one or more concepts of one or more implementations. 
     Applicant discloses a method of working over a hydrocarbon well having a horizontal leg having casing of at least 4½″ O.D. and not more than 5½″ O.D. which may be fraced, through a series of first horizontally spaced perforations opening into a series of first horizontally spaced fractures. Applicant provides a multiplicity of settable tools according to any of the embodiments herein. Applicant runs casing patches in the well, expanding the casing patches past an elastic limit into sealing engagement with the casing over the first series of horizontally spaced perforations and thereby covering up the first series of horizontally spaced perforations. Applicant produces second perforations in the casing past at least some of the casing patches and fracing the second perforations. Applicant then runs a first settable tool into the casing past at least two of the casing patches and setting the first settable tool against the casing thereby isolating the second perforations. Applicant produces third perforations in the casing past at least some of the casing patches and fracs the third perforations; then runs a second settable tool into the casing past at least one of the casing patches and sets the second settable tool against the casing thereby isolating the third perforations. Applicant produces fourth perforations in the casing past at least one of the casing patches and fracs the fourth perforations; and then allows the settable tools to degrade. 
     Although the invention has been described with reference to a specific embodiment, this description is not meant to be construed in a limiting sense. On the contrary, various modifications of the disclosed embodiments will become apparent to those skilled in the art upon reference to the description of the invention. It is therefore contemplated that the appended claims will cover such modifications, alternatives, and equivalents that fall within the true spirit and scope of the invention.