Frac plug with caged ball

Information

  • Patent Grant
  • 6491116
  • Patent Number
    6,491,116
  • Date Filed
    Saturday, March 23, 2002
    22 years ago
  • Date Issued
    Tuesday, December 10, 2002
    22 years ago
Abstract
A downhole tool for sealing a wellbore. The downhole tool includes a packer with a ball seat defined therein. A sealing ball is carried with the packer into the well. The movement of the sealing ball away from the ball seat is limited by a ball cage which is attached to the upper end of the packer. The ball cage has a plurality of ports therethrough for allowing flow into the ball cage and through the packer at certain flow rates. A spring is disposed in a longitudinal opening of the packer and engages the sealing ball to prevent the sealing ball from engaging the ball seat until a predetermined flow rate is reached. When the packer is set in the hole, flow through the frac plug below a predetermined flow rate is permitted. Once a predetermined flow rate in the well is reached, a spring force of the spring will be overcome and the sealing ball will engage the ball seat so that no flow through the frac plug is permitted.
Description




BACKGROUND OF THE INVENTION




This invention relates generally to downhole tools for use in oil and gas wellbores and methods of drilling such apparatus out of wellbores, and more particularly, to such tools having drillable components made from metallic or non-metallic materials, such as soft steel, cast iron, engineering grade plastics and composite materials. This invention relates particularly to downhole packers and frac plugs.




In the drilling or reworking of oil wells, a great variety of downhole tools are used. For example, but not by way of limitation, it is often desirable to seal tubing or other pipe in the casing of the well, such as when it is desired to pump cement or other slurry down the tubing and force the slurry out into a formation. It thus becomes necessary to seal the tubing with respect to the well casing and to prevent the fluid pressure of the slurry from lifting the tubing out of the well. Downhole tools referred to as packers and bridge plugs are designed for these general purposes and are well known in the art of producing oil and gas.




The EZ Drill SV® squeeze packer, for example includes a set ring housing, upper slip wedge, lower slip wedge, and lower slip support made of soft cast iron. These components are mounted on a mandrel made of medium hardness cast iron. The EZ Drill® squeeze packer is similarly constructed. The Halliburton EZ Drill® bridge plug is also similar, except that it does not provide for fluid flow therethrough.




All of the above-mentioned packers are disclosed in Halliburton Services—Sales and Service Catalog No. 43, pages 2561-2562, and the bridge plug is disclosed in the same catalog on pages 2556-2557.




The EZ Drill® packer and bridge plug and the EZ Drill SV® packer are designed for fast removal from the wellbore by either rotary or cable tool drilling methods. Many of the components in these drillable packing devices are locked together to prevent their spinning while being drilled, and the harder slips are grooved so that they will be broken up in small pieces. Typically, standard “tri-cone” rotary drill bits are used which are rotated at speeds of about 75 to about 120 rpm. A load of about 5,000 to about 7,000 pounds of weight is applied to the bit for initial drilling and increased as necessary to drill out the remainder of the packer or bridge plug, depending upon its size. Drill collars may be used as required for weight and bit stabilization.




Such drillable devices have worked well and provide improved operating performance at relatively high temperatures and pressures. The packers and bridge plugs mentioned above are designed to withstand pressures of about 10,000 psi (700 kg/cm


2


) and temperatures of about 425° F. (220° C.) after being set in the wellbore. Such pressures and temperatures require using the cast iron components previously discussed.




However, drilling out iron components requires certain techniques. Ideally, the operator employs variations in rotary speed and bit weight to help break up the metal parts and reestablish bit penetration should bit penetration cease while drilling. A phenomenon known as “bit tracking” can occur, wherein the drill bit stays on one path and no longer cuts into the downhole tool. When this happens, it is necessary to pick up the bit above the drilling surface and rapidly recontact the bit with the packer or plug and apply weight while continuing rotation. This aids in breaking up the established bit pattern and helps to reestablish bit penetration. If this procedure is used, there are rarely problems. However, operators may not apply these techniques or even recognize when bit tracking has occurred. The result is that drilling times are greatly increased because the bit merely wears against the surface of the downhole tool rather than cutting into it to break it up.




In order to overcome the above long standing problems, the assignee of the present invention introduced to the industry a line of drillable packers and bridge plugs currently marketed by the assignee under the trademark FAS DRILL®. The FAS DRILL® line of tools consists of a majority of the components being made of non-metallic engineering grade plastics to greatly improve the drillability of such downhole tools. The FAS DRILL® line of tools has been very successful and a number of U.S. patents have been issued to the assignee of the present invention, including U.S. Pat. No. 5,271,468 to Streich et al., U.S. Pat. No. 5,224,540 to Streich et al., U.S. Pat. No. 5,390,737 to Jacobi et al., U.S. Pat. No. 5,540,279 to Branch et al., U.S. Pat. No. 5,701,959 to Hushbeck et al., U.S. Pat. No. 5,839,515 to Yuan et al., and U.S. Pat. No. 5,984,007 to Yuan et al. The preceding patents are specifically incorporated herein by reference.




The tools described in all of the above references typically make use of metallic or non-metallic slip-elements, or slips, that are initially retained in close proximity to the mandrel but are forced outwardly away from the mandrel of the tool to engage a casing previously installed within the wellbore in which operations are to be conducted upon the tool being set. Thus, upon the tool being positioned at the desired depth, the slips are forced outwardly against the wellbore to secure the packer, or bridge plug as the case may be, so that the tool will not move relative to the casing when for example operations are being conducted for tests, to stimulate production of the well, or to plug all or a portion of the well.




The FAS DRILL® line of tools includes a frac plug which is well known in the industry. A frac plug is essentially a downhole packer with a ball seat for receiving a sealing ball. When the packer is set and the sealing ball engages the ball seat, the casing or other pipe in which the frac plug is set is sealed. Fluid, such as a slurry, can be pumped into the well after the sealing ball engages the seat and forced into a formation above the frac plug. Prior to the seating of the ball, however, flow through the frac plug is allowed.




One way to seal the frac plug is to drop the sealing ball from the surface after the packer is set. Although ultimately the ball will reach the ball seat and the frac plug will perform its desired function, it takes time for the sealing ball to reach the ball seat, and as the ball is pumped downwardly a substantial amount of fluid can be lost through the frac plug.




The ball may also be run into the well with the packer. Fluid loss and lost time to get the ball seated can still be a problem, however, especially in deviated wells. Some wells are deviated to such an extent that even though the ball is run into the well with the packer, the sealing ball can drift away from the packer as it is lowered into the well through the deviated portions thereof As is well known, some wells deviate such that they become horizontal or at some portions may even angle slightly upwardly. In those cases, the sealing ball can be separated from the packer a great distance in the well. Thus, a large amount of fluid and time is taken to get the sealing ball moved to the ball seat, so that the frac plug seals the well to prevent flow therethrough. Thus, while standard frac plugs work well, there is a need for a frac plug which will allow for flow therethrough until it is set in the well and the sealing ball engages the ball seat, but that can be set with a minimal amount of fluid loss and loss of time. The present invention meets that need.




Another object of the present invention is to provide a downhole tool that will not spin as it is drilled out. When the drillable tools described herein are drilled out, the lower portion of the tool being drilled out will be displaced downwardly in the well once the upper portion of the tool is drilled through. If there is another tool in the well therebelow, the portion of the partially drilled tool will be displaced downwardly in the well and will engage the tool therebelow. As the drill is lowered into the well and engages the portion of the tool that has dropped in the well, that portion of the tool sometimes has a tendency to spin and thus can take longer than is desired to drill out. Thus, there is a need for a downhole tool which will not spin when an undrilled portion of that tool engages another tool in the well as it is being drilled out of the well.




SUMMARY OF THE INVENTION




The present invention provides a downhole tool for sealing a wellbore. The downhole tool comprises a frac plug which comprises a packer having a ball seat defined therein and a sealing ball for engaging the ball seat. The packer has an upper end, a lower end and a longitudinal flow passage therethrough. The frac plug of the present invention also has a ball cage disposed at the upper end of the packer. The sealing ball is disposed in the ball cage and thus is prevented from moving past a predetermined distance away from the ball seat. The packer includes a packer mandrel having an upper and lower end, and has an inner surface that defines the longitudinal flow passage. The ball seat is defined by the mandrel, and more particularly by the inner surface thereof.




A spring may be disposed in the mandrel and has an upper end that engages the sealing ball. The spring has a spring force such that it will keep the sealing ball from engaging the ball seat until a predetermined flow in the well is achieved. Once the predetermined flow rate is reached, the sealing ball will compress the spring and will engage the ball seat to close the longitudinal flow passage. Flow downwardly through the longitudinal flow passage is prevented when the sealing ball engages the ball seat. The present invention may be used with or without the spring.




The packer includes slips and a sealing element disposed about the mandrel such that when it is set in the wellbore and when the sealing ball is engaged with the ball seat, no flow past the frac plug is allowed. A slurry or other fluid may thus be directed into the formation above the frac plug. The ball cage has a plurality of flow ports therein so that fluid may pass therethrough into the longitudinal central opening thus allowing for fluid flow through the frac plug when the packer is set but the sealing ball has not engaged the ball seat. Fluid can flow through the frac plug so long as the flow rate is below the rate which will overcome the spring force and cause the sealing ball to engage the ball seat. Thus, one object of the present invention is to provide a frac plug which allows for flow therethrough but which alleviates the amount of fluid loss and loss of time normally required for seating a ball on the ball seat of a frac plug. Additional objects and advantages of the invention will become apparent as the following detailed description of the preferred embodiment is read in conjunction with the drawings which illustrate such preferred embodiment.











BRIEF DESCRIPTION OF THE DRAWINGS





FIGS. 1A and 1B

, referred to collectively as

FIG. 1

, schematically show two downhole tools of the present invention positioned in a wellbore with a drill bit disposed thereabove.





FIG. 2

shows a cross-section of the frac plug of the present invention.





FIG. 3

is a cross-sectional view of the frac plug of the present invention in the set position with the slips and the sealing element expanded to engage casing or other pipe in the wellbore.





FIG. 4

shows a lower end of the frac plug of the present invention engaging the upper end of a second tool.











DESCRIPTION OF A PREFERRED EMBODIMENT




In the description that follows, like parts are marked throughout the specification and drawings with the same reference numerals, respectively. The drawings are not necessarily to scale and the proportions of certain parts have been exaggerated to better illustrate details and features of the invention. In the following description, the terms “upper,” “upward,” “lower,” “below,” “downhole” and the like as used herein shall mean in relation to the bottom or furthest extent of the surrounding wellbore even though the well or portions of it may be deviated or horizontal. The terms “inwardly” and “outwardly” are directions toward and away from, respectively, the geometric center of a referenced object. Where components of relatively well known designs are employed, their structure and operation will not be described in detail.




Referring now to the drawings, and more specifically to

FIG. 1

, the downhole tool or frac plug of the present invention is shown and designated by the numeral


10


. Frac plug


10


has an upper end


12


and a lower end


14


. In

FIG. 1

, two frac plugs


10


are shown and may be referred to herein as an upper downhole tool or frac plug


10




a


and a lower downhole tool or frac plug


10




b


. Frac plugs


10


are schematically shown in

FIG. 1

in a set position


15


. The frac plugs


10


shown in

FIG. 1

are shown after having been lowered into a well


20


with a setting tool of any type known in the art. Well


20


comprises a wellbore


25


having a casing


30


set therein.




Referring now to

FIG. 2

, a cross-section of the frac plug


10


is shown in an unset position


32


. The tool shown in

FIG. 2

is referred to as a frac plug since it will be utilized to seal the wellbore to prevent flow past the frac plug. The frac plug disposed herein may be deployed in wellbores having casings or other such annular structure or geometry in which the tool may be set. As is apparent, the overall downhole tool structure is like that typically referred to as a packer, which typically has at least one means for allowing fluid communication through the tool. Frac plug


10


thus may be said to comprise a packer


34


having a ball cage or ball cap


36


extending from the upper end thereof. A sealing ball


38


is disposed or housed in ball cage


36


. Packer


34


comprises a mandrel


40


having an upper end


42


, a lower end


44


, and an inner surface


46


defining a longitudinal central flow passage


48


. Mandrel


40


defines a ball seat


50


. Ball seat


50


is preferably defined at the upper end


42


of mandrel


40


.




Packer


34


includes spacer rings


52


secured to mandrel


40


with pins


54


. Spacer ring


52


provides an abutment which serves to axially retain slip segments


56


which are positioned circumferentially about mandrel


40


. Slip segments


56


may utilize ceramic buttons


57


as described in detail in U.S. Pat. No. 5,984,007. Slip retaining bands


58


serve to radially retain slip segments


56


in an initial circumferential position about mandrel


40


as well as slip wedge


60


. Bands


58


are made of a steel wire, a plastic material, or a composite material having the requisite characteristics of having sufficient strength to hold the slip segments


56


in place prior to actually setting the downhole tool


10


and to be easily drillable when the downhole tool


10


is to be removed from the wellbore


25


. Preferably, bands


58


are an inexpensive and easily installed about slip segments


56


. Slip wedge


60


is initially positioned in a slidable relationship to, and partially underneath slip segment


56


. Slip wedge


60


is shown pinned into place by pins


62


. Located below slip wedge


60


is at least one packer element, and as shown in

FIG. 2

, a packer element assembly


64


consisting of three expandable packer elements


66


disposed about packer mandrel


40


. Packer shoes


68


are disposed at the upper and lower ends of packer element assembly


64


and provide axial support thereto. The particular packer seal or element arrangement shown in

FIG. 2

is merely representative as there are several packer element arrangements known and used within the art.




Located below a lower slip wedge


60


are a plurality of slip segments


56


. A mule shoe


70


is secured to mandrel


40


by radially oriented pins


72


. Mule shoe


70


extends below the lower end


44


of packer


40


and has a lower end


74


, which comprises lower end


14


of downhole tool


10


. The lower most portion of downhole tool


10


need not be a mule shoe


70


but could be any type of section which serves to terminate the structure of downhole tool


10


or serves to be a connector for connecting downhole tool


10


with other tools, a valve, tubing or other downhole equipment.




Referring back to the upper end of

FIG. 2

, inner surface


46


defines a first diameter


76


, a second diameter


78


displaced radially inwardly therefrom, and a shoulder


80


which is defined by and extends between first and second diameters


76


and


78


, respectively. A spring


82


is disposed in mandrel


40


. Spring


82


has a lower end


84


and an upper end


86


. Lower end


84


engages shoulder


80


. Sealing ball


38


rests on the upper end


86


of spring


82


.




Ball cage or ball cap


36


comprises a body portion


88


having an upper end cap


90


connected thereto, and has a plurality of ports


92


therethrough. Referring now to the lower end of

FIG. 2

, a plurality of ceramic buttons


93


are disposed at or near the lower end


74


of downhole tool


10


and at the lower end


44


of mandrel


40


. As will be described in more detail hereinbelow, the ceramic buttons


93


are designed to engage and grip tools positioned in the well therebelow to prevent spinning when the tools are being drilled out.




The operation of frac plug


10


is as follows. Frac plug


10


may be lowered into the wellbore


25


utilizing a setting tool of a type known in the art. As is depicted schematically in

FIG. 1

, one, two or several frac plugs or downhole tools


10


may be set in the hole. As the frac plug


10


is lowered into the hole, flow therethrough will be allowed since the spring


82


will prevent sealing ball


38


from engaging ball seat


50


, while ball cage


36


prevents sealing ball


38


from moving away from ball seat


50


any further than upper end cap


90


will allow. Once frac plug


10


has been lowered to a desired position in the well


20


, a setting tool of a type known in the art can be utilized to move the frac plug


10


from its unset position


32


to the set position


15


as depicted in

FIGS. 2 and 3

, respectively. In set position


15


slip segments


56


and expandable packer elements


66


engage casing


30


. It may be desirable or necessary in certain circumstances to displace fluid downward through ports


92


in ball cage


36


and thus into and through longitudinal central flow passage


48


. For example, once frac plug


10


has been set it may be desirable to lower a tool into the well, such as a perforating tool, on a wire line. In deviated wells it may be necessary to move the perforating tool to the desired location with fluid flow into the well. If a sealing ball has already seated and could not be removed therefrom, or if a bridge plug was utilized, such fluid flow would not be possible and the perforating or other tool would have to be lowered by other means.




When it is desired to seat sealing ball


38


, fluid is displaced into the well at a predetermined flow rate which will overcome a spring force of the spring


82


. The flow of fluid at the predetermined rate or higher will cause sealing ball


38


to move downwardly such that it engages ball seat


50


. When sealing ball


38


is engaged with ball seat


50


and the packer


34


is in its set position


15


, fluid flow past frac plug


10


is prevented. Thus, a slurry or other fluid may be displaced into the well


20


and forced out into a formation above frac plug


10


. The position shown in

FIG. 3

may be referred to as a closed position


94


since the longitudinal central flow passage


48


is closed and no flow through frac plug


10


is permitted. The position shown in

FIG. 2

may therefore be referred to as an open position


96


since fluid flow through the frac plug


10


is permitted when the sealing ball


38


has not engaged ball seat


50


. As is apparent, sealing ball


38


is trapped in ball cage


36


and is thus prevented from moving upwardly relative to the ball seat


50


past a predetermined distance, which is determined by the length of the ball cage


36


. The spring


82


acts to keep the sealing ball


38


off of the ball seat


50


such that flow is permitted until the predetermined flow rate is reached. Ball cage


36


thus comprises a retaining means for sealing ball


38


, and carries sealing ball


38


with and as part of frac plug


10


, and also comprises a means for preventing sealing ball


38


from moving upwardly past a predetermined distance away from ball seat


50


.




When it is desired to drill frac plug


10


out of the well, any means known in the art may be used to do so. Once the drill bit


13


connected to the end of a tool string or tubing string


16


has gone through a portion of the frac plug


10


, namely the slip segments


56


and the expandable packer elements


66


, at least a portion of the frac plug


10


, namely the lower end


14


which in the embodiment shown will include the mule shoe


70


, will fall into or will be pushed into the well


20


by the drill bit


13


. Assuming there are no other tools therebelow, that portion of the frac plug


10


may be left in the hole. However, as shown in

FIG. 1

, there may be one or more tools below the frac plug


10


. Thus, in the embodiment shown in

FIG. 4

, ceramic buttons


93


in the upper frac plug


10




a


will engage the upper end


12


of lower frac plug


10




b


such that the portion of upper frac plug


10




a


will not spin as it is drilled from the well


20


. Although frac plugs


10


are utilized in the foregoing description, the ceramic buttons


93


may be utilized with any downhole tool such that spinning relative to the tool therebelow is prevented.




Although the invention has been described with reference to a specific embodiment, the foregoing description is not intended to be construed in a limiting sense. Various modifications as well as alternative applications will be suggested to persons skilled in the art by the foregoing specification and illustrations. It is therefore contemplated that the appended claims will cover any such modifications, applications or embodiments as followed in the true scope of this invention.



Claims
  • 1. A downhole tool for use in a wellbore comprising:a mandrel; at least one slip disposed on the mandrel for engaging the wellbore when the downhole tool is placed in a set position; and at least one gripping member disposed on the downhole tool; wherein the downhole tool is comprised of a drillable material and wherein the at least one gripping member prevents any portion of the downhole tool that falls downwardly in the wellbore, thereby engaging a downhole apparatus positioned in the wellbore below the downhole tool, from spinning relative thereto when the portion of the downhole tool is engaged by a drill to drill the downhole tool out of the wellbore.
  • 2. The downhole tool of claim 1 wherein the at least one gripping member comprises at least one ceramic button.
  • 3. The downhole tool of claim 2 wherein the at least one ceramic button comprises a plurality of ceramic buttons.
  • 4. The downhole tool of claim 1 wherein the at least one gripping member cuts into an outer surface of the downhole apparatus to prevent the portion of the downhole tool that falls downwardly in the wellbore from spinning relative to the downhole apparatus when the portion of the downhole tool is engaged by the drill to drill the downhole tool out of the wellbore.
  • 5. The downhole tool of claim 1 wherein the downhole tool is a frac plug.
  • 6. The frac plug of claim 5 further comprising:a sealing element disposed about the mandrel for sealingly engaging the wellbore; and a sealing ball operably associated with the frac plug so that the sealing ball moves therewith as the frac plug is lowered into the wellbore.
  • 7. A method for drilling out of a wellbore a first downhole tool located above a second downhole tool, comprising the steps of:providing at least one gripping member disposed on the first downhole tool; drilling through the first downhole tool until at least a portion of the first downhole tool falls down the wellbore or is pushed down the wellbore by the drill, thus engaging the second downhole tool; and drilling through the portion of the first downhole tool engaging the second downhole tool; whereby the at least one gripping member prevents the portion of the first downhole tool that engages the second downhole tool from spinning relative thereto when the portion of the first downhole tool is engaged by the drill.
  • 8. The method of claim 7 wherein the at least one gripping member comprises at least one ceramic button.
  • 9. The method of claim 8 wherein the at least one ceramic button comprises a plurality of ceramic buttons.
  • 10. The method of claim 7 wherein the at least one gripping member cuts into an outer surface of the second downhole tool to prevent the portion of the first downhole tool from spinning relative to the second downhole tool when the portion of the first downhole tool is engaged by the drill.
  • 11. The method of claim 7 wherein the first downhole tool is a frac plug.
  • 12. A downhole tool for use in a wellbore comprising:a mandrel; slip means disposed on the mandrel for engaging the wellbore when the downhole tool is placed in a set position; and gripping means disposed on the downhole tool; wherein the downhole tool is comprised of a drillable material and wherein the gripping means prevents any portion of the downhole tool that falls downwardly in the wellbore, thereby engaging a downhole apparatus positioned in the wellbore below the downhole tool, from spinning relative thereto when the portion of the downhole tool is engaged by a drill to drill the downhole tool out of the wellbore.
  • 13. The downhole tool of claim 12 wherein the gripping means comprises at least one ceramic button.
  • 14. The downhole tool of claim 13 wherein the at least one ceramic button comprises a plurality of ceramic buttons.
  • 15. The downhole tool of claim 12 wherein the gripping means cuts into an outer surface of the downhole apparatus to prevent the portion of the downhole tool that falls downwardly in the wellbore from spinning relative to the downhole apparatus when the portion of the downhole tool is engaged by the drill to drill the downhole tool out of the wellbore.
  • 16. The downhole tool of claim 12 wherein the downhole tool is a frac plug.
  • 17. The frac plug of claim 16 further comprising:sealing means disposed about the mandrel for sealingly engaging the wellbore; and a sealing ball operably associated with the frac plug so that the sealing ball moves therewith as the frac plug is lowered into the wellbore.
CROSS-REFERENCE TO RELATED APPLICATION

This application is a divisional of application Ser. No. 09/614,897 filed Jul. 12, 2000 U.S. Pat. No. 6,394,180.

US Referenced Citations (13)
Number Name Date Kind
4583593 Zunkel et al. Apr 1986 A
4664188 Zunkel et al. May 1987 A
4834184 Streich et al. May 1989 A
5224540 Streich et al. Jul 1993 A
5271468 Streich et al. Dec 1993 A
5390737 Jacobi et al. Feb 1995 A
5526884 Lembcke Jun 1996 A
5540279 Branch et al. Jul 1996 A
5701959 Hushbeck et al. Dec 1997 A
5839515 Yuan et al. Nov 1998 A
5984007 Yuan et al. Nov 1999 A
6220360 Connell et al. Apr 2001 B1
6325148 Trahan et al. Dec 2001 B1