US20140069654A1 - Downhole Tool Incorporating Flapper Assembly - Google Patents

Abstract

A downhole tool incorporating a sleeve assembly with an actuatable element, such as the seat of a plug-and-seat combination, and a seal assembly, such as a flapper seal assembly. The sleeve assembly is movable between a first position, in which the seal assembly is opened and inhibited from closing by contact with the sleeve assembly, and a second position in which the seal assembly is closed. Upon closing of the flapper assembly, the downhole tool may withstand higher pressures with reduced risk of failure to maintain a pressure differential across the tool.

Description

CROSS-REFERENCES TO RELATED APPLICATIONS
• This nonprovisional application claims the benefit of and priority to U.S. provisional application Ser. No. 61/729,262, filed Nov. 21, 2012 and entitled “Downhole Tool Incorporating Flapper Assembly,” and is a continuation-in-part of U.S. patent application Ser. No. 14/034,072, which is a Continuation of U.S. application Ser. No. 12/909,446 filed Oct. 21,2010, issued as U.S. Pat. No. 8,540,019, entitled “Fracturing System and Method”; each of which is incorporated by reference as if fully set forth herein.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
• Not applicable.
BACKGROUND
• 1. Field of the Invention
• The present invention relates to a downhole tool for oil and natural gas production. More specifically, the downhole tool enhances the ability of a well operator to hold pressure above a given depth by closure of a flapper assembly.
• 2. Description of the Related Art
• In hydrocarbon wells, fracturing (or “fracing”) is a technique used by well operators to create and/or extend a fracture from the wellbore deeper into the surrounding formation, thus increasing the surface area for formation fluids to flow into the well. Fracing can be accomplished by either injecting fluids into the formation at high pressure (hydraulic fracturing) or injecting fluids laced with round granular material (proppant fracturing) into the formation.
• Fracing multiple-stage production wells requires selective actuation of downhole tools, such as fracing valves, to control fluid flow from the tubing string to the formation. The specific actuator and actuated element for the downhole tool, however, can vary, and may include either mechanical shifting tools that operate on a profile of the tool, hydraulic shifting tools, etc.
• One problem with tools used in fracing procedures and, more generally, oil and gas completion and production procedures, relates to the ability of the actuator and actuated element to withstand heightened pressures that may be achieved. The application of such heightened pressures, which may be generated by pumping equipment at the wellhead, creates a pressure differential across the actuator, applying force thereto. Generally, the actuation system (e.g., a ball-and-seat combination) is the weakest part of the tool, and therefore is most likely to fail under procedures. Despite this fact, actuation systems are commonly used as a fluid seal system for post-actuation procedures, such as fracing, which employ heightened pressures exceeding the plug's rating, i.e. the ability of the plug to maintain its seal against the plug seat. The actuator will fail when the force applied to it becomes sufficiently high—e.g. by breaking, by a plug extruding through the plug seat, by deformation, or other failures—even when all other parts of the tool remain pressure tight and the actuator's pressure rating thereby provides an upper pressure limit that can be exceeded during such procedures. By reducing the probability of the actuation system failing, overall reliability of the system is increased. This minimizes otherwise unexpected costs associated with having to remove all or part of the tubing string upon failure.
• The system and method of the present disclosure addresses this problem by providing a stronger element, a flapper assembly, for withstanding such pressure differential and thereby removing the necessity that the actuation system withstand the heightened pressures as discussed above.
BRIEF SUMMARY
• The embodiments of the present disclosure relate to a downhole tool that reduces the potential of an actuator or actuated element failing during a completion or production procedure. Certain embodiments of the apparatuses disclosed herein incorporate a sleeve assembly with an actuatable element, such as the seat of a ball-and-seat combination, and a flapper assembly. The sleeve assembly is movable, either longitudinally, radially, or both, between a first position, in which the flapper assembly is open and inhibited from closing by the positioning of the sleeve assembly in the first position, and a second position in which the flapper assembly is closed. Upon closing of the flapper assembly, the downhole tool may withstand higher pressures with reduced risk of failure of the actuator, which generally has the highest risk of failure, improving the reliability of the tool for environments or operations requiring higher pressure on one side of the actuator element than on the opposing side of the actuator element.
BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS
• FIGS. 1A-1C are side sectional views of an embodiment of the present invention with a sleeve assembly in a first position and a flapper valve in an open state.
• FIG. 2 is a front sectional view through line2-2 ofFIG. 1A.
• FIGS. 3A-3C are side sectional views of the embodiment shown inFIGS. 1A-1C, respectively with the sleeve assembly in a second position and the flapper assembly in a closed state.
• FIG. 4 is a front sectional view through line4-4 ofFIG. 3A.
DETAILED DESCRIPTION OF VARIOUS EMBODIMENTS
• When used with reference to the figures, unless otherwise specified, the terms “upwell,” “above,” “top,” “upper,” “downwell,” “below,” “bottom,” “lower,” and like terms are used relative to the direction of normal production and/or flow of fluids and/or gas through the tool and wellbore. Thus, normal production results in migration through the wellbore and production string from the downwell to upwell direction without regard to whether the tubing string is disposed in a vertical wellbore, a horizontal wellbore, or some combination of both. Similarly, during the fracing process, fracing fluids and/or gasses move from the surface in the downwell direction to the portion of the tubing string within the formation.
• As shown inFIGS. 1A-1C, oneembodiment20 according to the present disclosure comprises atop sub26 located at the first end22 and abottom sub28 located at asecond end24. Theembodiment20 includes multiple other annular bodies, such as ahousing30 and anadaptor sub32. Together, these annular bodies define an interior volume of theembodiment20.
• During production, hydrocarbons will generally migrate in afirst direction31 from thesecond end24 to the first end22 through a generally-cylindrical flow path34 defined by alongitudinal axis36 and which intersects the interior volume. During fracing, completion fluids will generally flow in asecond direction33 from the first end22 to thesecond end24.
• Referring specifically toFIG. 1A, thetop sub26 has a threadedsection37 withouter threads38 for engagement with another annular body and has first and secondannular end surfaces40,42. A portion of theflow path34 is defined bycylindrical surfaces44,46 that are separated by a partially-conical shoulder surface48.
• Referring jointly toFIGS. 1A-1B, thehousing30 has afirst end50 and asecond end52. Thefirst end50 is in threaded engagement with the threadedsection37 of thetop sub26. A plurality of circumferentially-alignedset screws54 extends through thehousing30 to thetop sub26. Thesecond end52 hasinner threads56 for engagement with another annular body.
• Referring specifically toFIGS. 1B-1C, theadaptor sub32 has afirst end58 and a second end60. Thefirst end58 is fastened to thesecond end52 of thehousing30 with a plurality of setscrews62. Thefirst end58 hasouter threads64 for engagement with theinner threads56 of the housingsecond end52. Theadaptor sub32 has a generally cylindrical inner surface66 with a first set ofinner threads68 proximal to thefirst end58 and alocking section70 having a plurality ofridges72. A plurality of circumferentially alignedholes76 extend between anouter surface78 and the inner surface66 of theadaptor sub32.
• As shown inFIG. 1C, a second set ofinner threads74 is proximal to the second end60 of theadaptor sub32 for engagement with another annular body. Thebottom sub28 has a first end80 withouter threads82 engagable with the second set ofinner threads74 of theadaptor sub32. A third plurality ofset screws84 fastens the second end60 of theadaptor sub32 to thebottom sub28. Theflow path34 is partially defined by cylindricalinner surfaces86,88 of thebottom sub28, which are separated by a partially-conical shoulder surface90.
• Referring jointly toFIGS. 1A-1B, a flapper assembly91 occupies part of the interior volume. The flapper assembly91 includes a generallycylindrical flapper plate92, amount94, and anannular seat96. Theplate92 is connected to themount94 with a hinge such ashinge pin98. Theseat96 is nested within themount94 and fixed thereto with a plurality of circumferentially-aligned torque pins100. Torsion springs102,104 (seeFIG. 2) are coiled around corresponding spring pins106 and in contact with theplate92 and themount94 to urge theplate92 in a firstrotational direction108 relative to themount94.
• Referring toFIGS. 1A-1C, asleeve assembly110 comprises afirst sleeve112 and asecond sleeve114 threadedly engaged with aseat housing116 that encloses aseat insert118. Thefirst sleeve112 has an annularfirst end surface120 andsecond end122 havingouter threads124. Thesecond sleeve114 has afirst end126 withouter threads128 and a secondannular end surface130.
• Theseat housing116 includes first and second internally-threaded ends132,134 that are engaged with thesecond end122 of thefirst sleeve112 and thefirst end126 of thesecond sleeve114, respectively. Theseat housing116 further includes anintermediate section136 between thefirst end132 and thesecond end134. Theintermediate section136 is defined by first and second annular shoulder surfaces138,140. The seat housing includes a cylindricalouter surface144 extends between thefirst end132 andsecond end134.
• A plurality ofcylindrical recesses142 are formed in, and circumferentially aligned around the cylindricalouter surface144 of theseat housing116. A plurality of circumferentially-aligned shear pins146, each having a predetermined shear strength, extends through theholes76 in theadaptor sub32 into therecesses142.
• Acylindrical groove148 is formed in theouter surface144 of theseat housing116. Alock ring150 havingdogs152 occupies thegroove148. Thelock ring150 is a split ring, or C-ring, radially expandable between compressed and expanded states. As shown inFIG. 1B, thelock ring150 is in a compressed state and is applying a radially-outward force against the inner surface66 of theadaptor sub32.
• Still referring toFIG. 1B, theseat insert118 has first and second annular end surfaces154,156, and a generally cylindricalouter surface158 having an outer diameter marginally less than an inner surface of theseat housing116. Thesecond end surface156 is in contact with thefirst shoulder surface138 of theseat housing116. Theseat insert118 has a flow path longitudinally therethrough, which intersects and is coaxially aligned with theflow path34, and is partially defined by a first and second partially-conical ball-engagingsurfaces160,162 adjacent to, and on opposing sides of, first and second throat surfaces164,166. The first throat surface164 is partially-conical, and thesecond throat surface166 is cylindrical.
• FIGS. 1A-1C show theembodiment20 in a first state, in which thesleeve assembly110 is in a first position. In this state, each of the shear pins146 is intact, fixing the position of theseat housing116 relative to theadaptor sub32. As shown inFIG. 1A, theplate94 is urged rotationally around thehinge pin98 in the firstrotational direction108 by torsion springs102,104 (seeFIG. 2), but rotational movement of theplate92 is impeded by its contact with the outer surface of thefirst sleeve112.
• FIG. 1B shows aball200 engaged with thefirst surface160 of theseat insert118. When so engaged, theball200 combined with theseat insert118 acts as a check valve by resisting fluid flow in thesecond direction33, but allowing fluid flow in thefirst direction31, as is known in the art. Upon application of a fluid pressure in thesecond direction33 to the ball-and-seat combination above the aggregate strength of the shear pins146, the plurality of shear pins146 will fracture and terminate the fixed relationship of the housing116 (and thus the entire sleeve assembly110) relative to theadaptor sub32. After fracturing of the shear pins146, continued application of a fluid pressure in thesecond direction33 will move thesleeve assembly110 toward, and ultimately to, a second position, as will be described with reference toFIG. 3A-3C.
• After termination of the fixed relationship, longitudinal movement of thesleeve assembly110 is limited in thefirst direction31 by contact of thefirst end132 of theseat housing116 with theflapper mount94. Longitudinal movement of thesleeve assembly110 is limited in thesecond direction33 by contact of thesecond end134 of theseat housing116 with the first end80 of thebottom sub28.
• FIGS. 3A-3C show theembodiment20 in a second state in which thesleeve assembly110 is in a second position with the firstannular surface120 of thefirst sleeve112 positioned within the cylindrical space defined by theflapper mount94. Referring toFIG. 3A, because rotation of theplate92 is no longer impeded by thefirst sleeve112, torsion springs102,104 (seeFIG. 4) urge rotation of theflapper plate92 around thehinge pin98 to a closed position against theseat96. In this closed position, theplate92 is positioned longitudinally between the first end22 and thesleeve assembly110 and inhibits fluid flow through theflow path34.
• Referring toFIG. 3C, thelock ring150 is positioned within thelocking section70 of theadaptor sub32 and applies a radially-outward force against theridges72 to facilitate engagement with thedogs152. This locking engagement prevents inadvertent movement of the seat housing116 (and thus the sleeve assembly110) in thefirst direction31.
• In this state, fluids may flow through the embodiment in thefirst direction31, provided the flow pressure is sufficient to overcome the rotational force of the torsion springs102,104 (seeFIG. 4) urging theplate92 to seal against theseat96. Fluid pressure in thesecond direction33, however, is impeded by theplate92. Because theplate92, which is sealed against theseat96, is able to withstand greater pressures than theball200, the operator may use increased pressure with reduced risk of ball failure, which would prevent the ability to pressure up the well at the depth at which theembodiment20 is installed within the well and require removal of all or part of the tubing string.
• Movement of the sleeve assembly to the second position may not, in certain embodiments, directly allow the plate to move and seal against the flapper seat. For example, Applicant's U.S. patent application Ser No. 13/694,509 filed on Dec. 7, 2102 and entitled “Flow Bypass Device and Method” (the '509 Application) discloses a lock system which is released when a sleeve assembly is moved from a first position to a second position, releasing a second sleeve or other element to then move. It will be appreciated that the sleeve assembly and seal assembly of the present disclosure could be engaged with such a locking system, such that movement of the sleeve assembly releases the lock. An additional step, such as movement of a second sleeve, may then permit movement of the plate and formation of a seal between the plate and the flapper seat. Other methods for releasing the plate upon, including methods for releasing the plate in response to movement of the sleeve assembly, will become apparent upon study of the present disclosure and are within the scope of the invention as claimed.
• The disclosure made herein describes one or more preferred embodiments of systems and methods within the scope of the claims. Those skilled in the art will recognize that alternative embodiments of such a systems and methods can be used in carrying out the claimed invention. Other aspects and advantages of the disclosed systems and methods may be obtained from a study of this disclosure and the drawings, along with the appended claims.

Claims (15)

We claim:

1. A downhole tool comprising:

a body having a first end, a second end, the body at least partially defining an interior space

a seal assembly in the interior space between the first end and the second end, the seal assembly having a flapper seat and a plate connected to a hinge, the plate radially moveable on the hinge; ;

a sleeve assembly comprising an actuatable element, the sleeve assembly in communication with the seal assembly and movable within said interior space from a first position to a second position,

wherein,

in said first position, said sleeve assembly causes said seal assembly to be in an open position;

in the second position, the sleeve assembly allows movement of the seal assembly to a closed position; and

in the closed position, said plate prevents fluid communication between the first end and the second end of the body.

2. The downhole tool ofclaim 1 wherein in the closed position, the plate prevents fluid communication between the first end and the actuatable element.

3. The downhole tool ofclaim 2 wherein the actuatable element comprises a plug seat configured for receiving a plug.

4. The downhole tool ofclaim 3 wherein said plug is a plug deployable into a fluid stream adjacent to a wellhead.

5. The downhole tool ofclaim 1 wherein in the first position, the sleeve assembly contacts the plate.

6. The downhole tool ofclaim 1 wherein the sleeve assembly further comprises a sleeve, the sleeve having a first sleeve position and a second sleeve position, and the sleeve is configured to be moveable from the second sleeve position to the first sleeve position when the sleeve assembly is in the second position.

7. The downhole tool ofclaim 1 further comprising a spring, said spring engaging the plate to move the plate from the open position to the closed position.

8. The downhole tool ofclaim 1 further comprising:

a locking section formed in an inner surface of the at least one annular body; and

a lock ring in a circumferential groove formed in an outer surface of the sleeve assembly, the lock ring being engagable with the locking section to inhibit movement in a longitudinal direction.

9. The downhole tool ofclaim 1 wherein in the first position the plate is radially between an annular space at least partially defined by the sleeve assembly and the body.

10. A method for actuating a flapper valve installed in a tubing string, the method comprising:

Flowing a fluid stream having a plug therein through the flapper valve, the flapper valve comprising;

A body having a first end and a second end,

A flapper assembly within the body, the flapper assembly having a plate and a flapper seat, the plate configured to engage the flapper seat to form a fluid seal,

A sleeve assembly having a plug seat for engaging the plug, thereby preventing fluid communication through the plug seat;

Engaging the plug with the plug seat;

Creating a pressure differential across the plug seat sufficient to move the sleeve assembly from the first position to the second position;

Moving the plate radially on the hinge to engage the flapper seat, creating a fluid seal between the plate and the flapper seat;

11. The method ofclaim 10 further comprising the step of increasing the pressure differential across the plate to a pressure greater than the rated pressure of the plug engaged with the plug seat.

12. The method ofclaim 10 further comprising at least partially opening the flapper assembly after the sleeve assembly has moved to the second position.

13. The method ofclaim 10 further comprising moving the sleeve to the first sleeve position after moving the sleeve assembly to the second position.

14. The method ofclaim 12 wherein the sleeve assembly remains in the second position.

15. The method ofclaim 10 further comprising the step of fracing a formation adjacent the tubing string after moving the sleeve assembly to the second position.

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