Not applicable.
1. Field
The described embodiments and claimed invention relate to a tool for sequentially engaging and releasing a restrictor element, also referred to as plug, onto and from its corresponding valve seat, as well as systems and methods incorporating such a tool for producing hydrocarbons from multiple stages in a hydrocarbon production well.
2. Background of the Art
In hydrocarbon wells, tools incorporating valve assemblies having a restrictor element, such as a ball or dart, and a seat element, such as a ball seat or dart seat, have been used for a number of different operations. Such valve assemblies prevent the flow of fluid past the assembly and, with the application of a desired pressure, can actuate one or more tools associated with the assembly.
One use for such remotely operated valve assemblies is in fracturing (or “fracing”), a technique used by well operators to create and/or extend one or more cracks, called “fractures” from the wellbore deeper into the surrounding formation in order to improve the flow of formation fluids into the wellbore. Fracing is typically accomplished by injecting fluids from the surface, through the wellbore, and into the formation at high pressure to create the fractures and to force them to both open wider and to extend further. In many case, the injected fluids contain a granular material, such as sand, which functions to hold the fracture open after the fluid pressure is reduced.
Fracing multiple-stage production wells requires selective actuation of valve assemblies, such as fracing sleeves, to control fluid flow from the tubing string to the formation. For example, U.S. Published Application No. 2008/0302538, entitled Cemented Open Hole Selective Fracing System and which is incorporated by reference herein, describes one system for selectively actuating a fracing sleeve that incorporates a shifting tool. The tool is run into the tubing string and engages with a profile within the interior of the valve. An inner sleeve may then be moved to an open position to allow fracing or to a closed position to prevent fluid flow to or from the formation.
That same application describes a system using multiple valve assemblies which incorporate ball-and-seat seals, each having a differently-sized ball seat and corresponding ball. Frac valves connected to ball and seat seals do not require the running of a shifting tool thousands of feet into the tubing string and are simpler to actuate than frac valves requiring such shifting tools. Such ball and seat seals are operated by placing an appropriately sized ball into the well bore and bringing the ball into contact with a corresponding ball seat. The ball engages on a sealing section of the ball seat to block the flow of fluids past the valve assembly. Application of pressure to the valve assembly causes the valve assembly to “shift”, opening the frac sleeve.
Some valve assemblies are selected for tool actuation by the size of ball or other restrictor element introduced into the well. If the well or tubing string contains multiple ball seats, the ball must be small enough that it will not seal against any of the ball seats it encounters prior to reaching the desired ball seat. For this reason, the smallest ball to be used for the planned operation is the first ball placed into the well or tubing and the smallest ball seat is positioned in the well or tubing the furthest from the wellhead. Thus, these traditional valve assemblies limit the number of valves that can be used in a given tubing string because each ball size is only able to actuate a single valve. Further, systems using these valve assemblies typically require each ball to be at least 0.125 inches larger than the immediately preceding ball. Therefore, the size of the liner restricts the number of valve assemblies with differently-sized ball seats. Certain seat assemblies may allow plug increments of 0.0625 inches, which provides more available seats, but still creates an upper limit on the total available plug sizes. In other words, because a plug must be larger than its corresponding plug seat and smaller than the plug seats of all upwell valves, each plug can only seal against a single plug seat and, if desired, actuate one tool.
The valve assembly provides a method for sequentially sealing multiple valve seats with a single restrictor element and, where desired, actuating tools associated with the valve assembly. One embodiment allows multiple balls, plugs or other restrictor elements of the same size to actuate tools in sequential stages.
The valve assemblies described herein comprise a split ring having a body with a seating surface and an external diameter extending radially from the body. In certain embodiments the split ring is a C-ring having terminated ends that may be compressed such that its terminal ends are in contact. Alternatively, the split ring may be in an uncompressed state wherein the terminal ends, for a C-ring, or the segment edges, for a multi-segmented ring, are not in contact. The split ring may also be comprised of a plurality of segments. The valve assembly further comprises one or more mounting elements, such as a variable diameter surface, to engage the outer diameter of the split ring. Engagement of mounting elements with the outer diameter causes the split ring to expand or contract.
Valve assemblies as described herein may further comprise a sleeve contained within a tubular housing, the sleeve having an inner surface, an outer surface, and a plurality of openings extending between said inner and outer surfaces. The openings are aligned to engage with the external diameter of the split ring. The tubular housing may have one or more mounting elements aligned within the openings in the sleeve, such that the mounting elements may engage the external diameter of the split ring when the sleeve is located at a desired position in the housing.
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 treatment of a well, which may include a fracturing, or “fracing,” process, fluids move from the surface in the downwell direction to the portion of the tubing string within the formation to be treated.
The housing 22 has a first cylindrical inner surface 30 having a first inner diameter, a second cylindrical inner surface 32 located downwell of the first inner surface 30 and having a second inner diameter that is greater than the first inner diameter, and a third cylindrical inner surface 34 having a third inner diameter that is greater than the second cylindrical inner surface 32. The first inner surface 30 is longitudinally adjacent to the second inner surface 32, forming a downwell-facing shoulder having an annular shoulder surface 38. The second and third inner surfaces 32, 34 are separated by a partially-conical surface 40.
The bottom connection 24 includes a first cylindrical inner surface 42 having a first inner diameter and a second cylindrical inner surface 44 having a second inner diameter. The first and second inner cylindrical surfaces 42, 44 are separated by an inner partially-conical inner surface 46. An annular upper end surface 47 is adjacent to the first inner surface 42.
The tool 20 comprises an annular sleeve 48 nested radially within the housing 22 and positioned downwell of the shoulder 38. The sleeve 48 has an upper outer surface 50 with a first outer diameter and a second outer surface 52 with a second outer diameter less than the first inner diameter. The first outer surface 50 and second outer surface 52 are separated by an annular shoulder surface 54. The sleeve 48 further comprises a cylindrical inner surface 56 that extends between annular upper and lower end surfaces 58, 60 of the sleeve 48.
In
The valve assembly may further comprise a guide element to position the split ring in the desired location. The guide element in the embodiment of
In the embodiment illustrated by the figures, the split ring is a C-ring 70 positioned within the annular sleeve 48 between the upper end surface 58 and the shoulder surface 54. The C-ring 70 fits into a groove formed in the inner surface 56 of the shifting sleeve 48. The groove is sufficiently deep to allow the C-ring seating surface to expand to the desired maximum diameter. In some embodiments, the desired maximum diameter may be as large as or larger than the inner diameter of the shifting sleeve. Those of skill in the art will appreciate that, in embodiments in which the C-ring activates a sleeve or other valve assembly, the C-ring 70 may be positioned at any point along the sleeve or tool, or above or below the sleeve, provided that the C-ring and the sleeve or other tool are connected such that sufficient pressure applied to the C-ring will slide the sleeve in relation to the inner housing or otherwise activate the tool.
The C-ring 70 has an inner surface 74 an outer surface 76 defining the outer perimeter of the C-ring, and a seating surface 72 engageable with a restrictor element having a corresponding size. In the illustrated embodiment, the C-ring 70 is held in a radially compressed state by the first inner surface 50 of the housing 22.
Referring to the embodiment in
Referring to
When the sleeve 48 is in the second position shown in
Each tool of the sets of the tools 202, 206, 210 has the features described with reference to
To actuate the lower set of tools 210, the lower-stage ball is caused to move through the tubing string and upper and intermediate sets of tools 202, 206. The lower-stage ball is sized to pass through the upper and intermediate sets of tools 202, 206 without being inhibited from further downwell flow by the corresponding ball seat inserts.
Upon reaching the upwell tool 210a of the lower set of tools 210, the lower-stage ball seats against the closed C-ring of the tool. The well operator can then increase the pressure within the tubing string to overcome the expansive force of the associated coil spring and shift the sleeve to the intermediate third position described with reference to
While the lower set of tools is shown comprising only three stages of tools, the process could be repeated for any number of tools within this stage. In addition, the same process described above with respect to the lower set of tools is repeatable in similar fashion for the intermediate and upper sets of tools 202, 206.
In an additional embodiment, the inwardly directed force exerted on the outer surface of the C-ring is caused by a plurality of dogs. In a preferred embodiment, the dogs are positioned in the openings 84 of the sleeve, and each dog has a surface corresponding to the curvature of the second inner surface 50 of the housing 22. The surface profile of the dogs may have other shapes provided the dogs can engage the protrusions 78 defining the outer surface of the C-ring 70 as desired. The dogs are aligned with and adapted to contact and exert a radially inward force on the protrusions 78 of the C-ring 70 to force the C-ring 70 into the compressed state. In this embodiment, the openings 84 have a length along the longitudinal axis of the sleeve to allow the C-ring and sleeve to move in relation to the dogs.
The dogs extend past first outer surface 50 of the sleeve 48, effectively reducing the diameter available to the protrusions. When the C-ring 70 is positioned such that that protrusions 78 engage the dogs, the terminal ends 82 are in contact and the diameter of the seating surface 72 and inner surface 74 of the C-ring 70 are such that a properly-sized ball flowing through the shifting sleeve will engage with the seat of the C-ring 70 as described with reference to
Still referring to
One advantage to the system illustrated in
This arrangement can be continued with any number of valve assemblies in series per stage, with no limit on the number of sleeves. Moreover, this system allows for an increase in the number of stages. For example, a trio of tools using single valve seats configured for a 2.0 inch, 1.875 inch, and 1.75 inch ball respectively, can be placed in a well. A second trio of tools using double valve seats with upper valves configured for use with 2.0 inch, 1.875 inches, and 1.75 inches are then placed upwell of the first trio. The upper valve seats of this second trio of stages are C-rings in the uncompressed state (as described with referenced with respect to
In operation, a first 1.75 inch ball is placed in the well and allowed to engage and activate the 1.75 inch stage of the first trio of stages. A first 1.875 ball is placed in the well and allowed to engage and activate the 1.875 inch stage of the first trio of stages. Following the 1.875 inch ball, a first 2.0 inch ball is placed in the well. This ball first engages the lower seat of the 2.0 inch stage of the second trio of stages causing the seat to shift and moving the upper ring from an uncompressed state to a compressed state. The first 2.0 ball then engages the lower seat of the 1.875 inch stage of the second trio of stages, causing the seat to shift and moving the upper ring from an uncompressed to a compressed state. The first 2.0 inch ball then engages the lower seat of the 1.75 inch stage of second trio of stages, causing the seat to shift and moving the upper ring from an uncompressed state to a compressed state. Finally, the first 2.0 inch ball engages the 2.0 inch stage of the first trio of stages and activates the tools associated with the valve assemblies of this stage.
At this point, three stages, associated with a 1.75 inch, a 1.875 inch, and a 2.0 inch valve assembly have been activated. Further, the well now contains three additional stages that can be activated by sequentially placing a 1.75 inch ball, a 1.875 inch ball, and 2.0 inch ball into the well and allowing the balls to engage their respective seats. This means that 6 stages, each stage having the potential for multiple sleeves, can be activated through use of 3 ball sizes. Further, the embodiments are not limited to the nesting of three sizes. Further nesting is possible with the valve assemblies and method of use contemplated herein, such nesting limited only by the ability of the uncompressed ring to allow larger sized balls to pass without shifting the seat.
It is possible that the lower seat is not a C-ring but rather a solid seat for the ball or other restrictor means. Such a solid seat can be paired with the applicants' resilient deformable ball, described in applicant's U.S. patent application Ser. No. 13/423,154, entitled “Downhole System and Apparatus Incorporating Valve Assembly With Resilient Deformable Engaging Element,” filed Mar. 16, 2012 and incorporated by reference herein, to allow for engagement and subsequent release of the lower seat. In fact, any method or device for engaging the lower seat to initially shift the sleeve is permissible provided that it does not prevent the treatment of any previously untreated stage.
In another aspect, the expandable or collapsible split ring may be split in two or more locations, creating a multi-segmented ring. One embodiment of a multi-segmented ring is shown in a compressed or closed configuration in
In the embodiment of
With reference to
The segments have an edge 418 which may be of the same material or a different material as the other portions of the face 417, seating surface 416, top 415 and bottom of the segment. In one embodiment, the edge 418 may comprise an elastomer material to help reduce or eliminate damage to the plug as it passes through the expanded or opened multi-segmented plug seat. Further, such elastomer may facilitate the creation, or improvement, of a fluid seal between the segments when the multi-segmented seat is in the closed or compressed position.
The illustrated embodiment multi-segmented rings have a diameter DC from the center of the arc of one ring to the center of the arc of the opposing ring. Such rings also have a diameter DE from the edge of each segment to the corresponding edge on the opposing segment. For rings having a substantially circular face and seat surface DC and DE have substantially the same value for the closed ring shown in
Multi-segmented seats may also have an odd number of segments, in which case the shortest diameter will not occur between two edges, but at a point along the face determined by the number of segments. Such arrangements are within the scope of embodiments encompassed by the present disclosure.
The plug seat comprising a multi-segmented ring may be disposed within a plug seat carrier, such as the plug seat carrier 402 shown in
The carrier 402, segments 410, spring 424 and plate 422 may comprise a seat assembly 400. The seat assembly 400 may include additional components such as retainer rings 420a and 420b to secure the seats 410 longitudinally within the carrier. Seals, fasteners, and other elements may also be included to ensure that a pressure differential is created across the seat assembly 400 when an appropriate plug engages the seating surfaces 416 of the segments 410.
Interior surfaces of first and second end connections (502, 510), port sleeve 540, seat assembly 400, cement sleeve (if present) at least partially define a flowpath through the tool 500. The ported housing 504 has one or more ports 525 providing fluid communication therethrough. In the first position, the port sleeve 540 prevents fluid communication from the flowpath of tool 500 to the exterior through ports 525. In the second position, not shown, the port sleeve 540 no longer covers the ports 525 and fluid communication between the flowpath and exterior of the tool 500 can occur.
The ball, plug, or other restrictor devices of the present valve assemblies can either seat on the split ring itself or the inside diameter of the sleeve above the split ring, where the sleeve is sized sufficiently small such that the ball creates a fluid seal between a plug and the sleeve, in which case the split ring provides mechanical engagement to prevent extrusion of the plug and allows the pressure differential across the plug and valve assembly necessary to shift the sleeve.
The present disclosure contains descriptions of preferred embodiments in which specific systems and apparatuses are described. Those skilled in the art will recognize that alternative embodiments of such systems and apparatuses can be used. Other aspects and advantages of the embodiments of the invention as claimed may be obtained from a study of this disclosure and the drawings, along with the appended claims. Moreover, the recited order of the steps of any method described herein is not meant to limit the order in which those steps may be performed.
This application claims the benefit of U.S. Provisional Patent Application Ser. No. 61/868,867, filed on Aug. 22, 2013 and entitled “Downhole Tool with Collapsible or Expandable Split Ring”; is a Continuation in Part, and claims the benefit, of U.S. patent application Ser. No. 13/423,158, filed Mar. 16, 2011 entitled “Multistage Production System Incorporating Valve assembly With Collapsible or Expandable C-Ring,” which claims the benefit of U.S. Provisional Patent Application Ser. No. 61/453,288 and U.S. patent application Ser. No. 13/448,284, entitled “Assembly for Actuating a Downhole Tool” filed on Apr. 16, 2012, which claims the benefit of U.S. Provisional Application 61/475,333 filed Apr. 14, 2011 entitled “Valve Assembly and System for Producing Hydrocarbons”, each of which is incorporated by reference herein.
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Number | Date | Country | |
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20150167428 A1 | Jun 2015 | US |
Number | Date | Country | |
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61868867 | Aug 2013 | US | |
61453288 | Mar 2011 | US | |
61475333 | Apr 2011 | US |
Number | Date | Country | |
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Parent | 13423158 | Mar 2012 | US |
Child | 14466924 | US | |
Parent | 13448284 | Apr 2012 | US |
Child | 13423158 | US |