Not applicable.
1. Field of the Invention
The embodiments disclosed herein and the invention as claimed relate to a valve assembly to prevent the flow of fluids past the assembly, to systems incorporating such assembly, and to methods for using the assembly. In one preferred embodiment, the valve assembly is incorporated into a system of selectively operable frac sleeves for use in completing a well for oil, gas or other hydrocarbons.
2. Background
In hydrocarbon wells, tools incorporating valve assemblies having an engaging element, such as a ball or dart, and a receiving 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, a well operator 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 downhole tools, 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 embodiments which incorporate a shifting tool for selectively actuating a fracing sleeve.
That same application also 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 arrangements 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 arrangements 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 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 to the surrounding the formation.
Some valve assemblies are selected for tool actuation by the size of ball 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 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 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. In other words, because a ball must be larger than its corresponding ball seat and smaller than the ball seats of all upwell valves, each ball can only seal against a single ball seat and, if desired, actuate one tool.
The embodiments disclosed herein relate to an alternative for sequentially engaging multiple receiving elements with a single engaging element and, where desired, actuating tools associated with the valve assembly. One embodiment of the present invention allows multiple balls of the same size to actuate tools in sequential stages.
In fracing operations, the embodiments of the valve assembly disclosed herein, enable an increase in the number of stages that can be performed using ball-and-seat or similar valve assemblies. The increase in frac stages can increase the total number of sleeves that can be opened for fracture treatments, reduce the number of frac valves that are opened for each stage, or both. Further, if additional stages are not needed, the invention valve assembly such as those disclosed herein can be used to limit the valve assemblies used to those having larger diameter balls and ball seats, thus enlarging the fluid path in the wellbore or tubing and improving the flow of fluids form the wellhead to the formation to be treated.
In an alternate aspect, valve assemblies such as those disclosed herein are useful to perform multiple pressure cycles on installed tubing by using a single engaging element sequentially on multiple receiving elements or by sequential engagement of a single receiving element with multiple engaging elements.
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 fracturing, or “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.
In the illustrative embodiment of
In operation, the diameter of the engaging element contacts sealing section 88 between inlet 87 and outlet 89. When the pressure at inlet 87 exceeds the pressure at outlet 89, the engaging element begins to compress or deform, or both, causing the diameter of the engaging element which is contact with seating section 88 to shrink, allowing the engaging element to move towards outlet 89. If the pressure differential between inlet 87 and outlet 89 is sufficiently high, the diameter of the engaging element 114 which contacts seating section 88 shrinks to the diameter of the outlet 89, or to a diameter slightly smaller than the diameter of outlet 89, allowing the engaging element 114 to pass through the outlet 89 and out of the receiving element 84. As appreciated by those of skill in the art, the passage of engaging element 114 through the outlet 89 of the receiving element 84 allows the pressure at outlet 89 to equalize with the pressure at inlet 87.
In one preferred embodiment, the hardness of the ball seat 84 is greater than the hardness of the ball 114. Thus, as force is applied to the ball 114 while in the seating section 88, the ball 114 compresses or otherwise deforms before the ball seat 84 expands. More particularly, the ball 114 compresses or deforms sufficiently to pass through the outlet 89 of the ball seat 84 while the diameter of the outlet 89 remains substantially the same. After passing through the outlet 89, the ball 114 returns substantially back to its original size and shape.
Although virgin PEEK is preferred, other contemplated materials may be used provided that they will predictably deform yet are substantially resilient. For example, one embodiment of the invention contemplates the use of a “carbon black” ball, or CB ball, which is a PEEK ball to which carbon fibers have been added to increase compressive strength. CB balls have a higher pressure limit than the preferred virgin PEEK in a given size, but are more prone to cracking. Yet another alternative is polyamide-imides, such as those sold under the trade name TORLON by Solvay Advanced Polymers of Alpharetta, Ga.
In a preferred embodiment, the fluid pressure that the valve assembly will hold is determined by the physical properties of the engaging element, including its size, shape, and material composition, and the diameter of the outlet 89′ of seating section 88′. Specifically, when the fluid pressure is greater at the inlet 87′ than at the outlet 89′, the engaging element is forced towards the outlet. If this difference in pressure between the inlet and outlet (i.e., the “pressure drop”) becomes sufficiently high, the engaging element is forced through the inlet and can then move down the well or tubing to engage the next seat. The pressure drop necessary to force the engaging element through its corresponding seat or other receiving element is a function of the size of the outlet 89 as well as the size of the engaging element and the materials used to make the engaging element.
For example, referring back to
Because the force applied to any given ball is a function of the square of the diameter, the size of the interference fit may be adjusted with different ball sizes so that the pressure necessary to move the ball through the seat 84 is the same, regardless of ball size. For example, if the well operator desires that all balls within a system extrude through the seat at the same pressure (e.g., 2200 psi), larger balls will require a tighter interference fit because of the increased force on the ball resulting from the larger surface area exposed to the tubing pressure. Similarly, smaller balls will require a smaller interference fit for the same pressure to be operative.
The inlet-to-outlet length is preferably one-eighth inch, which allows the ball to extrude through the outlet nearly immediately upon application of the target pressure differential. Increasing the length of the inlet-to-outlet length increases the effect of friction on the ball, which may increase the required time and/or pressure to move the ball 114 through the outlet 89.
The valve assembly's 84 pressure rating can be adjusted by changing, the diameter of the outlet 89, the physical properties of the engaging element 114, or combinations of the above. Changing the angle of the conical profile of seating section 88 may also increase friction and thereby increase the pressure rating or the time required for the ball to extrude in response to its rated pressure. Experiments performed on valve assemblies 84 comprising spherical engaging elements 114 and ball seat receiving elements 84 have identified valve assemblies with interference diameters of 1/16th inch having pressure ratings ranging from less than 1000 psi using virgin PEEK to over 2200 psi using CB ball. Valve assemblies 84 comprising balls made from virgin PEEK as the engaging element 114 have demonstrated pressure ratings of from less than 1000 psi for interference diameters of 1/16th inch to over 2200 psi for interference diameters of about ⅛th inch. As used herein, the term “interference diameter” means the difference between the uncompressed diameter of the ball—or equivalent cross section of a non-spherical engaging element—and the diameter of the outlet 89.
Further, the valve assembly of the present invention encompasses receiving elements with outlets that can expand due to the application of pressure on the valve assembly, provided that such receiving element does not expand to the point that the outlet of the receiving element is as large as or larger than the uncompressed diameter of the ball or equivalent cross section of a non-spherical engaging element. Receiving elements with expandable outlets can be used to create a valve assembly in which the engaging element passes through the receiving element at lower pressure than required for valve assemblies with an outlet that does not expand.
The housing assembly 30 includes an upper housing 40 with a plurality of radially-directed and circumferentially-aligned ports 42 providing fluid communication paths between the internal flowpath and the surrounding formation. In the illustrated embodiment, the ports 42 are generally circular and contain an insert. However, tools incorporating embodiments of the present invention may have any size or shape, and either have inserts or be open to the well bore. In some preferred embodiments, the ports 42 are configured so that flow is prevented through the port by a sleeve until the valve assembly is activated by a required pressure. The upper set of screws 36 extends through the upper housing 40 to engage a lower portion 44 of the top connection 26.
The housing assembly 30 further includes a lower housing 46. The lower set of screws 38 extends through the lower housing 46 to engage an upper portion 48 of the bottom connection 32. The lower housing 46 is fixed to the lower end of the upper housing 40 with an intermediate set of screws 50. The lower housing 46 includes an inner cylindrical surface 52 with a locking section 54 having a plurality of radially-inward directed dogs 56.
An annular sleeve 58 is positioned downwell of the top connection 26 and radially within the housing assembly 30. The sleeve 58 has a cylindrical inner surface 60 having the same diameter as the cylindrical surface 28 of the top connection 26.
Referring specifically to
The outer surface 66 extends between annular upper and lower end surfaces 68, 70. A shoulder 72 having upper and lower annular shoulder surfaces 74, 76 extends radially inward from the inner cylindrical surface. The outer surface 66 of the ball seat carrier 64 defines a lock ring groove 78 that is radially aligned and with the shoulder 72. An annular lock ring 80 having radially-outwardly oriented dogs 82 is positioned in the lock ring groove 78. The lock ring 80 has normal outer diameter greater than the inner diameter of the inner surface 52 and is radially compressed into the lock ring groove 78 and exerts a radially-outward force against the inner surface 52.
One embodiment of a receiving element, a ball seat 84, is positioned between the sleeve 58 and the upper shoulder surface 74 of the ball seat carrier 64 to hold the ball seat 84 in a fixed position relative to the sleeve 58 with an upper end surface adjacent to the lower end surface of the sleeve 58. As described with reference to
A generally cylindrical lower sleeve 96 extends from the lower shoulder surface 76 of the ball seat carrier 64 to the interior space of the bottom connection 32. The lower sleeve 96 is fixed to the ball seat carrier 64 and moves longitudinally therewith.
In the second position, the upper end surface 59 of the sleeve 58 is positioned downwell of the housing ports 42. Thus, when the sleeve 58 is in the second position, fluid flow is permitted between the interior flowpath and the exterior of the tool through housing ports 42.
When the sleeve 58 is in the second position shown in
After fracing, the differential pressure across the ball 114 may be increased to cause the ball 114 to extrude through the passage 90 of the ball seat 84 and extrude to the next tool in the tubing string or, alternatively, the end of the tubing string. The ball seat 84 may then be milled to remove the passage 90 and increase the flow profile for fluids.
For any given state, the profile of the flowpath is a function of the position of the sleeve 58. In
Differently-sized balls and tools may be used within a single tubing string to actuate a series of tools within stages of the well, with tools requiring a smaller ball size being located downwell of tools requiring larger ball sizes. For example, a 1.5-inch diameter ball may be extruded through one or more tools with seats having a 1.4-inch diameter, and then rest against a “static” seat positioned between stages and designed to hold the ball and not allow it to deform or pass therethrough.
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 seats.
Upon reaching the upwell tool 210a of the lower set of tools 210, the lower-stage ball seats against the ball seat of the tool. The well operator can then increase the pressure within the tubing string to overcome the resistance of the shear pins (e.g., 1800 psi) and shift the sleeve to the second 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. After performing these steps on the intermediate set of tools, the intermediate ball will flow to and seat against the ball seat of the first tool of the lower set of tools. Likewise, after performing these steps on the upper set of tools, the upper ball will flow to and seat against the ball seat of the first tool of the intermediate set of tools.
Each tool of the sets of the tools 302, 306, 310 has the features described with reference to
In addition, each tool 302a, 302b, 306a, 306b, 310a, 310b of the stages has one or more retention elements which prevent the tool from actuating until the fluid pressure meets a desired minimum. In one preferred embodiment, the retention element comprises one or more shear pins. However, any device, assembly, or mechanism that prevents the tools from actuating until a certain minimum pressure is reach may serve as the retention element.
To fully actuate the system embodied in
A second ball having the same diameter as the first ball, and comprising a second, less compressible material is then introduced into the well. One example of a suitable second material is carbon black, that is PEEK into which carbon fibers have been introduced. The second ball passes through upper tool set 302 and the intermediate tool set 306 and engages tool 310a Pressure is applied to the valve assembly until the pressure exceeds the rating of the shear pins or other retaining elements, actuating the tool. Additional pressure is applied to extrude the second through the seat of tool 310a and the second ball engages a second static-seat tool 217, positioned between tool 310a and 310b.
This process may then be repeated, first with the intermediate stage 208 using the VP and CB intermediate-stage balls with the intermediate sets of tools 206 and the intermediate static-seat tool 216, and second with the upper stage 204 using VP and CB upper-stage ball with the upper sets of tools 202 and upper static seat tool 214.
The pressures and materials used to describe operation of the system of
This original nonprovisional application claims the benefit of U.S. Provisional Application Ser. No. 61/453,281, filed Mar. 16, 2011 and entitled “Multistage Production System Incorporating Downhole Tool With Deformable Ball,” which is incorporated by reference herein.
Number | Date | Country | |
---|---|---|---|
61453281 | Mar 2011 | US | |
61453288 | Mar 2011 | US |