US20140069654A1 - Downhole Tool Incorporating Flapper Assembly - Google Patents

Downhole Tool Incorporating Flapper Assembly Download PDF

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Publication number
US20140069654A1
US20140069654A1 US14/086,879 US201314086879A US2014069654A1 US 20140069654 A1 US20140069654 A1 US 20140069654A1 US 201314086879 A US201314086879 A US 201314086879A US 2014069654 A1 US2014069654 A1 US 2014069654A1
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US
United States
Prior art keywords
position
sleeve
assembly
plate
plug
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Abandoned
Application number
US14/086,879
Inventor
Raymond Hofman
William Sloane Muscroft
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Peak Completion Technologies Inc
Original Assignee
Peak Completion Technologies Inc
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Priority to US12/909,446 priority Critical patent/US8540019B2/en
Priority to US201261729262P priority
Priority to US14/034,072 priority patent/US20140034294A1/en
Application filed by Peak Completion Technologies Inc filed Critical Peak Completion Technologies Inc
Priority to US14/086,879 priority patent/US20140069654A1/en
Publication of US20140069654A1 publication Critical patent/US20140069654A1/en
Application status is Abandoned legal-status Critical

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    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B34/00Valve arrangements for boreholes or wells
    • E21B34/06Valve arrangements for boreholes or wells in wells
    • E21B34/10Valve arrangements for boreholes or wells in wells operated by control fluid supplied from above ground
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B34/00Valve arrangements for boreholes or wells
    • E21B34/06Valve arrangements for boreholes or wells in wells
    • E21B34/10Valve arrangements for boreholes or wells in wells operated by control fluid supplied from above ground
    • E21B34/102Valve arrangements for boreholes or wells in wells operated by control fluid supplied from above ground with means for locking the closing element in open or closed position
    • E21B34/103Valve arrangements for boreholes or wells in wells operated by control fluid supplied from above ground with means for locking the closing element in open or closed position with a shear pin
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/12Methods or apparatus for controlling the flow of the obtained fluid to or in wells
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/14Obtaining from a multiple-zone well
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/25Methods for stimulating production
    • E21B43/26Methods for stimulating production by forming crevices or fractures
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B34/00Valve arrangements for boreholes or wells
    • E21B2034/005Flapper valves

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 line 2-2 of FIG. 1A.
  • FIGS. 3A-3C are side sectional views of the embodiment shown in FIGS. 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 line 4-4 of FIG. 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 in FIGS. 1A-1C, one embodiment 20 according to the present disclosure comprises a top sub 26 located at the first end 22 and a bottom sub 28 located at a second end 24. The embodiment 20 includes multiple other annular bodies, such as a housing 30 and an adaptor sub 32. Together, these annular bodies define an interior volume of the embodiment 20.
  • During production, hydrocarbons will generally migrate in a first direction 31 from the second end 24 to the first end 22 through a generally-cylindrical flow path 34 defined by a longitudinal axis 36 and which intersects the interior volume. During fracing, completion fluids will generally flow in a second direction 33 from the first end 22 to the second end 24.
  • Referring specifically to FIG. 1A, the top sub 26 has a threaded section 37 with outer threads 38 for engagement with another annular body and has first and second annular end surfaces 40, 42. A portion of the flow path 34 is defined by cylindrical surfaces 44, 46 that are separated by a partially-conical shoulder surface 48.
  • Referring jointly to FIGS. 1A-1B, the housing 30 has a first end 50 and a second end 52. The first end 50 is in threaded engagement with the threaded section 37 of the top sub 26. A plurality of circumferentially-aligned set screws 54 extends through the housing 30 to the top sub 26. The second end 52 has inner threads 56 for engagement with another annular body.
  • Referring specifically to FIGS. 1B-1C, the adaptor sub 32 has a first end 58 and a second end 60. The first end 58 is fastened to the second end 52 of the housing 30 with a plurality of set screws 62. The first end 58 has outer threads 64 for engagement with the inner threads 56 of the housing second end 52. The adaptor sub 32 has a generally cylindrical inner surface 66 with a first set of inner threads 68 proximal to the first end 58 and a locking section 70 having a plurality of ridges 72. A plurality of circumferentially aligned holes 76 extend between an outer surface 78 and the inner surface 66 of the adaptor sub 32.
  • As shown in FIG. 1C, a second set of inner threads 74 is proximal to the second end 60 of the adaptor sub 32 for engagement with another annular body. The bottom sub 28 has a first end 80 with outer threads 82 engagable with the second set of inner threads 74 of the adaptor sub 32. A third plurality of set screws 84 fastens the second end 60 of the adaptor sub 32 to the bottom sub 28. The flow path 34 is partially defined by cylindrical inner surfaces 86, 88 of the bottom sub 28, which are separated by a partially-conical shoulder surface 90.
  • Referring jointly to FIGS. 1A-1B, a flapper assembly 91 occupies part of the interior volume. The flapper assembly 91 includes a generally cylindrical flapper plate 92, a mount 94, and an annular seat 96. The plate 92 is connected to the mount 94 with a hinge such as hinge pin 98. The seat 96 is nested within the mount 94 and fixed thereto with a plurality of circumferentially-aligned torque pins 100. Torsion springs 102, 104 (see FIG. 2) are coiled around corresponding spring pins 106 and in contact with the plate 92 and the mount 94 to urge the plate 92 in a first rotational direction 108 relative to the mount 94.
  • Referring to FIGS. 1A-1C, a sleeve assembly 110 comprises a first sleeve 112 and a second sleeve 114 threadedly engaged with a seat housing 116 that encloses a seat insert 118. The first sleeve 112 has an annular first end surface 120 and second end 122 having outer threads 124. The second sleeve 114 has a first end 126 with outer threads 128 and a second annular end surface 130.
  • The seat housing 116 includes first and second internally-threaded ends 132, 134 that are engaged with the second end 122 of the first sleeve 112 and the first end 126 of the second sleeve 114, respectively. The seat housing 116 further includes an intermediate section 136 between the first end 132 and the second end 134. The intermediate section 136 is defined by first and second annular shoulder surfaces 138, 140. The seat housing includes a cylindrical outer surface 144 extends between the first end 132 and second end 134.
  • A plurality of cylindrical recesses 142 are formed in, and circumferentially aligned around the cylindrical outer surface 144 of the seat housing 116. A plurality of circumferentially-aligned shear pins 146, each having a predetermined shear strength, extends through the holes 76 in the adaptor sub 32 into the recesses 142.
  • A cylindrical groove 148 is formed in the outer surface 144 of the seat housing 116. A lock ring 150 having dogs 152 occupies the groove 148. The lock ring 150 is a split ring, or C-ring, radially expandable between compressed and expanded states. As shown in FIG. 1B, the lock ring 150 is in a compressed state and is applying a radially-outward force against the inner surface 66 of the adaptor sub 32.
  • Still referring to FIG. 1B, the seat insert 118 has first and second annular end surfaces 154, 156, and a generally cylindrical outer surface 158 having an outer diameter marginally less than an inner surface of the seat housing 116. The second end surface 156 is in contact with the first shoulder surface 138 of the seat housing 116. The seat insert 118 has a flow path longitudinally therethrough, which intersects and is coaxially aligned with the flow path 34, and is partially defined by a first and second partially-conical ball-engaging surfaces 160, 162 adjacent to, and on opposing sides of, first and second throat surfaces 164, 166. The first throat surface 164 is partially-conical, and the second throat surface 166 is cylindrical.
  • FIGS. 1A-1C show the embodiment 20 in a first state, in which the sleeve assembly 110 is in a first position. In this state, each of the shear pins 146 is intact, fixing the position of the seat housing 116 relative to the adaptor sub 32. As shown in FIG. 1A, the plate 94 is urged rotationally around the hinge pin 98 in the first rotational direction 108 by torsion springs 102, 104 (see FIG. 2), but rotational movement of the plate 92 is impeded by its contact with the outer surface of the first sleeve 112.
  • FIG. 1B shows a ball 200 engaged with the first surface 160 of the seat insert 118. When so engaged, the ball 200 combined with the seat insert 118 acts as a check valve by resisting fluid flow in the second direction 33, but allowing fluid flow in the first direction 31, as is known in the art. Upon application of a fluid pressure in the second direction 33 to the ball-and-seat combination above the aggregate strength of the shear pins 146, the plurality of shear pins 146 will fracture and terminate the fixed relationship of the housing 116 (and thus the entire sleeve assembly 110) relative to the adaptor sub 32. After fracturing of the shear pins 146, continued application of a fluid pressure in the second direction 33 will move the sleeve assembly 110 toward, and ultimately to, a second position, as will be described with reference to FIG. 3A-3C.
  • After termination of the fixed relationship, longitudinal movement of the sleeve assembly 110 is limited in the first direction 31 by contact of the first end 132 of the seat housing 116 with the flapper mount 94. Longitudinal movement of the sleeve assembly 110 is limited in the second direction 33 by contact of the second end 134 of the seat housing 116 with the first end 80 of the bottom sub 28.
  • FIGS. 3A-3C show the embodiment 20 in a second state in which the sleeve assembly 110 is in a second position with the first annular surface 120 of the first sleeve 112 positioned within the cylindrical space defined by the flapper mount 94. Referring to FIG. 3A, because rotation of the plate 92 is no longer impeded by the first sleeve 112, torsion springs 102, 104 (see FIG. 4) urge rotation of the flapper plate 92 around the hinge pin 98 to a closed position against the seat 96. In this closed position, the plate 92 is positioned longitudinally between the first end 22 and the sleeve assembly 110 and inhibits fluid flow through the flow path 34.
  • Referring to FIG. 3C, the lock ring 150 is positioned within the locking section 70 of the adaptor sub 32 and applies a radially-outward force against the ridges 72 to facilitate engagement with the dogs 152. This locking engagement prevents inadvertent movement of the seat housing 116 (and thus the sleeve assembly 110) in the first direction 31.
  • In this state, fluids may flow through the embodiment in the first direction 31, provided the flow pressure is sufficient to overcome the rotational force of the torsion springs 102, 104 (see FIG. 4) urging the plate 92 to seal against the seat 96. Fluid pressure in the second direction 33, however, is impeded by the plate 92. Because the plate 92, which is sealed against the seat 96, is able to withstand greater pressures than the ball 200, 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 the embodiment 20 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 of claim 1 wherein in the closed position, the plate prevents fluid communication between the first end and the actuatable element.
3. The downhole tool of claim 2 wherein the actuatable element comprises a plug seat configured for receiving a plug.
4. The downhole tool of claim 3 wherein said plug is a plug deployable into a fluid stream adjacent to a wellhead.
5. The downhole tool of claim 1 wherein in the first position, the sleeve assembly contacts the plate.
6. The downhole tool of claim 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 of claim 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 of claim 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 of claim 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 of claim 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 of claim 10 further comprising at least partially opening the flapper assembly after the sleeve assembly has moved to the second position.
13. The method of claim 10 further comprising moving the sleeve to the first sleeve position after moving the sleeve assembly to the second position.
14. The method of claim 12 wherein the sleeve assembly remains in the second position.
15. The method of claim 10 further comprising the step of fracing a formation adjacent the tubing string after moving the sleeve assembly to the second position.
US14/086,879 2010-10-21 2013-11-21 Downhole Tool Incorporating Flapper Assembly Abandoned US20140069654A1 (en)

Priority Applications (4)

Application Number Priority Date Filing Date Title
US12/909,446 US8540019B2 (en) 2010-10-21 2010-10-21 Fracturing system and method
US201261729262P true 2012-11-21 2012-11-21
US14/034,072 US20140034294A1 (en) 2010-10-21 2013-09-23 Fracturing System and Method
US14/086,879 US20140069654A1 (en) 2010-10-21 2013-11-21 Downhole Tool Incorporating Flapper Assembly

Applications Claiming Priority (1)

Application Number Priority Date Filing Date Title
US14/086,879 US20140069654A1 (en) 2010-10-21 2013-11-21 Downhole Tool Incorporating Flapper Assembly

Related Parent Applications (1)

Application Number Title Priority Date Filing Date
US14/034,072 Continuation-In-Part US20140034294A1 (en) 2010-10-21 2013-09-23 Fracturing System and Method

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US20140069654A1 true US20140069654A1 (en) 2014-03-13

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US14/086,879 Abandoned US20140069654A1 (en) 2010-10-21 2013-11-21 Downhole Tool Incorporating Flapper Assembly

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US20140158361A1 (en) * 2012-12-07 2014-06-12 CNPC USA Corp. Pressure controlled multi-shift frac sleeve system
WO2017151126A1 (en) * 2016-03-02 2017-09-08 Thru Tubing Solutions, Inc. Flapper valve tool
US10006261B2 (en) 2014-08-15 2018-06-26 Thru Tubing Solutions, Inc. Flapper valve tool

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