Not applicable.
1. Field
The described embodiments and invention as claimed relate to oil and natural gas production. More specifically, the embodiments described herein relate to downhole tools systems and methods used to selectively pressurize and test a production string or casing and to selectively activate a tool or a series of tools connected together by flow lines.
2. Description of the Related Art
In completion of oil and gas wells, tubing is often inserted into the well to function as a flow path for treating fluids into the well and for production of hydrocarbons from the well. Such tubing may help preserve casing integrity, optimize production, or serve other purposes. Such tubing may be described or labeled as casing, production tubing, liners, tubulars, or other terms. The term “tubing” as used in this disclosure and the claims is not limited to any particular type, shape, size or installation of tubular goods.
To fulfill these purposes, the tubing must maintain structural integrity against the pressures and pressure cycles it will encounter during its functional life. To test this integrity, operators will install the tubing with a closed “toe”—the end of the tubing furthest from the wellhead—and then subject the tubing to a series of pressure tests. These tests are designed to demonstrate whether the tubing will hold the pressures for which it was designed, to which it will be subjected during operation or an acceptable alternative pressure, depending on the particular circumstances.
One detriment to these pressure tests is the necessity for a closed toe. After pressure testing, the toe must be opened to allow for free flow of fluids through the tubing so that further operations may take place. While formation characteristics, cement, or other factors may still restrict fluid flow, the presence of such factors do not alleviate the desirability or necessity for opening the toe of the tubing. Commonly, the toe is opened by positioning a perforating device in the toe and either explosively or abrasively perforating the tubing to create one or more openings. Perforating, however, requires additional time and equipment that increase the cost of the well. Therefore, there exists a need for an improved method to economically pressure test the tubing and open the toe of the tubing after it is installed and pressure tested.
The present disclosure describes an improved device and method for pressure testing the tubing and opening the toe of tubing installed in a well. Further, the device and method may be readily adapted to other well applications as well. The present disclosure also describes embodiments relating to actuating a series of tools using flow lines that communicate fluid pressure between connected tools for actuation.
The described embodiments of the present disclosure address the problems associated with the closed toe required for pressure testing tubing installed in a well. Further, in one aspect of the present disclosure, a chamber, such as a pressure chamber, air chamber, or atmospheric chamber, is in fluid communication with at least one surface of the shifting element, which may be a shifting sleeve, of the device. The chamber is isolated from the interior of the tubing such that fluid pressure inside the tubing is not transferred to the chamber. A second surface of the shifting sleeve is in fluid communication with the interior of the tubing. Application of fluid pressure on the interior of the tubing thereby creates a pressure differential across the shifting element, applying force tending to shift the shifting element in the direction of the pressure chamber, atmospheric chamber, or air chamber.
In a further aspect of the present disclosure, the shifting sleeve is encased in an enclosure such that all surfaces of the shifting element opposing the chamber are isolated from the fluid, and fluid pressure, in the interior of the tubing. Upon occurrence of some predetermined event—such as a minimum fluid pressure, the presence of acid, or electromagnetic signal—at least one surface of the shifting element is exposed to the fluid pressure from the interior of the tubing, creating differential pressure across the shifting sleeve. Specifically, the pressure differential is created relative to the pressure in the chamber, and applies a force on the shifting element in a desired direction. Such force activates the tool.
While specific predetermined events are stated above, any event or signal communicable to the device may be used to expose at least one surface of the shifting element to pressure from the interior of the tubing.
In a further aspect, the downhole tool comprises an inner sleeve with a plurality of sleeve ports. A housing is positioned radially outwardly of the inner sleeve, with the housing and inner sleeve partially defining a space radially therebetween. The space, which is preferably annular, is occupied by a shifting element, which may be a shifting sleeve. A fluid path extends between the interior flowpath of the tool and the space. Thus, the shifting element may be nested between the housing and the inner sleeve. A fluid control device, which is preferably a burst disk, occupies at least portion of the fluid path.
When the toe is closed, the shifting sleeve is in a first position between the housing ports and the sleeve ports to prevent fluid flow between the interior flowpath and exterior of the tool. A control member is installed to prevent or limit movement of the shifting sleeve until a predetermined internal tubing pressure or internal flowpath pressure is reached. Such member may be a fluid control device which selectively permits fluid flow, and thus pressure communication, into the annular space to cause a differential pressure across the shifting sleeve. Any device, including, without limitation, shear pins, springs, and seals, may be used provided such device allows movement of the shifting element, such as shifting sleeve, only after a predetermined internal tubing pressure or other predetermined event occurs. In a preferred embodiment, the fluid control device will permit fluid flow into the annular space only after it is exposed to a predetermined differential pressure. When this differential pressure is reached, the fluid control device allows fluid flow, the shifting sleeve is moved to a second position, the toe is opened, and communication may occur through the housing and sleeve ports between the interior flowpath and exterior of the tool.
In a further aspect of this disclosure, embodiments of the downhole tool may be connected in series with one or more other tools to enable fluid pressure and fluid flow at one location in a tool string to actuate another tool in the series. Such embodiments may include a plurality of similar tools such that actuation of one tool also actuates other tools in the series. Such embodiments may include flow lines, separate tubing, annular spaces (such as between tools and casing, housing and inner sleeve or mandrel, through a wall of a housing, inner sleeve or mandrel, or otherwise), other fluid path defining means, or combinations of the above, to transfer fluid pressure from the interior of one tool to pressure chambers within separate tools, thereby creating pressure differentials to effect hydraulic actuation of the separate tools. The first tool in such series may be referred to as an initiator tool while the last tool may be referred to as a terminator tool. Tools in such a series between the initiator and the terminator may be called intermediate tools. Such intermediate tools can receive fluid communication from a preceding tool along a fluid conduit distinct from the internal flowpath of the tubing string and transmit fluid flow and/or pressure with a subsequent tool along a fluid conduit also distinct from the internal flowpath of the tubing string. Some embodiments of such intermediate tools may actuate in response to the fluid communication received from the preceding tool. Further, some embodiments of tools according to the present disclosure are ported valves, having ports allowing fluid communication between the interior and the exterior of the tool following actuation, while other embodiments are portless and do not allow such fluid communication.
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. Further, the directional description of a part or component of a tool, such as “top” or “bottom” connection refers only to a preferred embodiment thereof and does not limit the orientation of the tool as installed in a wellbore except as may be otherwise required by the language of the claims.
An inner sleeve 34 having a cylindrical inner surface 35 is positioned between a lower annular surface 36 of the top connection 22 and an upper annular surface 38 of the bottom connection 28. The inner sleeve 34 has a plurality of radially aligned sleeve ports 40. Each of the sleeve ports 40 is concentrically aligned with a corresponding housing port 26. The inner surfaces 23, 29 of the top and bottom connections 22, 28 and the inner surface 35 of the sleeve 35 define an interior flowpath 37 for the movement of fluids into, out of, and through the tool. In an alternative embodiment, the interior flowpath may be defined, in whole or in part, by the inner surface of the shifting sleeve.
Although the housing ports 26 and sleeve ports 40 are shown as cylindrical channels between the exterior and interior of the tool 20, the ports 26, 40 may be of any shape sufficient to facilitate the flow of fluid therethrough for the specific application of the tool. For example, larger ports may be used to increase flow volumes, while smaller ports may be used to reduce cement contact in cemented applications. Moreover, while preferably concentrically aligned, each of the sleeve ports 40 need not be concentrically aligned with its corresponding housing port 26.
The top connection 22, the bottom connection 28, an interior surface 42 of the ported housing 24, and an exterior surface 44 of the inner sleeve 34 define an annular space 45, which is partially occupied by a shifting sleeve 46 having an upper portion 48 and a lower locking portion 50 having a plurality of radially-outwardly oriented locking dogs 52.
The annular space 45 comprises an upper pressure chamber 53 defined by the top connection 22, burst disk 32, outer housing 24, inner sleeve 34, the shifting sleeve 46, and upper sealing elements 62u. The annular space 45 further comprises a lower pressure chamber 55 defined by the bottom connection 28, the outer housing 24, the inner sleeve 34, the shifting sleeve 46, and lower sealing elements 621. Lower pressure chamber 55 may also be referred to as a receiving chamber as it functions to receive the shifting sleeve 46 following the creation of a pressure differential across the shifting sleeve as described below. In a preferred embodiment, the pressure within the upper and lower pressure chambers 53, 55 is atmospheric when the tool is installed in a well (i.e., the burst disk 32 is intact).
A locking member 58 partially occupies the annular space 45 below the shifting sleeve 46 and ported housing 24. When the sleeve is shifted, the locking dogs 52 engage the locking member 58 and inhibit movement of the shifting sleeve 46 toward the shifting sleeve's first position.
The shifting sleeve 46 is moveable within the annular space 45 between a first position and a second position by application of hydraulic pressure to the tool 20. When the shifting sleeve 46 is in the first position, which is shown in
To shift the sleeve 46 to the second position (shown in
Following rupture of the burst disk 32, the shifting sleeve 46 is no longer isolated from the fluid flowing through the inner sleeve 34. The resultant increased pressure on the shifting sleeve surfaces in fluid communication with the upper pressure chamber 53 creates a pressure differential relative to the atmospheric pressure within the lower pressure chamber 55. Such pressure differential across the shifting sleeve causes the shifting sleeve 36 to move from the first position to the second position shown in
Upper pressure chamber 53 serves as an inlet chamber, as it receives fluid flow, and therefore fluid pressure, that passes the burst disk 32 following rupture. Similarly, the lower pressure chamber 55 serves as a receiving chamber for receiving the shifting sleeve 46 as it moves to the second position in response to the pressure differential caused by increased fluid pressure in the upper pressure, or inlet, chamber 53.
Prior to using the tubing 198, the well operator may undertake a number of integrity tests by cycling and monitoring the pressure within the tubing 198 and ensuring pressure loss is within acceptable tolerances. This, however, can only be done if the downwell end of the tubing 198 is isolated from the surrounding formation 200 with the isolation member 218 closing off the toe of the tubing 198. After testing is complete, the tool 20 may be actuated as described with reference to
In another embodiment, downhole tools of the present disclosure may be placed in series such that actuation of an embodiment tool facilitates fluid communication between the interior flowpath of the actuated tool and least one other tool.
An inner sleeve 134 having a cylindrical inner surface 135 is positioned between a lower annular surface 136 of the top connection 122 and an upper annular surface 138 of the outlet sub 128. The inner sleeve 134 may have a plurality of radially aligned sleeve ports 140. One or more of the sleeve ports 140 may be aligned with a corresponding housing port 126. The inner surfaces 123, 129 of the top connection 122 and outlet sub 128 and the inner surface 135 of the inner sleeve 134 define an interior flowpath 137 for the movement of fluids into, out of, and through the tool. In an alternative embodiment, the interior flowpath 137 may be defined, in whole or in part, by the inner surface of the shifting sleeve 146.
Although the housing ports 126 and sleeve ports 140 are shown as cylindrical channels between the exterior and interior of the tool 120, the housing ports 126 and sleeve ports 140 may be of any shape sufficient to facilitate the flow of fluid therethrough for the specific application of the tool. For example, larger ports may be used to increase flow volumes, while smaller ports may be used to reduce cement contact in cemented applications or to equalize or otherwise regulate the fluid flow when multiple stages are being treated simultaneously through a plurality of tools, such as through a plurality of open downhole tools of the present disclosure. Housing ports may also have nozzles to control the flow rate through the ports, such as to enable the operator to equalize flow rates through the ports of multiple tools open to fluid flow at the same time. Moreover, while preferably concentrically aligned, each of the sleeve ports 140 need not be concentrically aligned with its corresponding housing port 126 but the ports will generally be arranged to allow for fluid flowing through the sleeve ports 140 to effectively flow through the housing ports 126 as well. The top connection 122, the outlet sub 128, an interior surface 142 of the ported housing 124, and an exterior surface 144 of the inner sleeve 134 define an annular space 145, which is partially occupied by a shifting sleeve 146. Shifting sleeve 146 has an upper portion 148 and a lower portion, such as lower locking portion 150 having a plurality of radially-outwardly oriented locking dogs 152, which may be ratcheting teeth. The locking dogs 152 may be directly milled, cut or otherwise placed into the shifting sleeve 146 or may be placed on a ring or other component that is connected to or engaged with shifting sleeve 146.
The annular space 145 comprises an inlet chamber 153, also referred to as an upper pressure chamber defined by the top connection 122, burst disk 132, outer housing124, inner sleeve 134, the shifting sleeve 146, and upper sealing elements 162u. The annular space 145 further comprises a receiving chamber 155 defined by the outlet sub 128, the outer housing 124, the inner sleeve 134, the shifting sleeve 146, and lower sealing elements 166. Receiving chamber 155 may also be referred to as a lower pressure chamber. In a preferred embodiment, the pressure within the inlet and receiving chambers (153, 155) is atmospheric when the tool is installed in a well (i.e., the burst disk 132 is intact).
A locking member 158 partially occupies the annular space 145 below the shifting sleeve 146, i.e. in the receiving chamber 155. When the sleeve is shifted, the locking dogs 152 engage the locking member 158 and inhibit movement of the shifting sleeve 146 toward the shifting sleeve's first position.
In the embodiment of
The shifting sleeve 146 is moveable within the annular space 145 between a first position and a second position by application of hydraulic pressure to the tool 120. When the shifting sleeve 146 is in the first position, which is shown in
To shift the sleeve 146 to the second position (shown in
Following rupture of the burst disk 132, the shifting sleeve 146 is no longer isolated from the fluid flowing through the inner sleeve 134. The resultant increased pressure on the shifting sleeve 146 surfaces in fluid communication with the inlet chamber 153 creates a pressure differential relative to the atmospheric pressure within the receiving chamber 155. Such pressure differential across the shifting sleeve 146 causes the shifting sleeve 146 to move from the first position to the second position shown in
Movement of shifting sleeve 146 from the first position to the second position establishes fluid communication between the interior flowpath 137 of downhole tool 120 and a second device via flow tubing connected to the outlet flowline connection 170. Specifically, seals 166 are positioned to engage the shifting sleeve when the shifting sleeve is in the first position in order to prevent fluid communication between the interior flowpath 137 and the receiving chamber 155 through the ports 140. When the shifting sleeve 146 moves to the second position, as in
One embodiment intermediate tool 375 is shown in
The inner surfaces 390, 392 of the inlet sub 350 and outlet sub 355 and the inner surface 394 of the inner sleeve 340 define an interior flowpath 337 for the movement of fluids into, out of, and through the tool 375. In an alternative embodiment, the interior flowpath 337 may be defined, in whole or in part, by the inner surface of the shifting sleeve 310. Inlet sub 350, outlet sub 355, an interior surface 401 of ported housing 345, and an exterior surface 400 of the inner sleeve or mandrel 340 define an annular space 315 (indicated by the bracket in
As will be appreciated from the foregoing description, intermediate tool 375 is similar to the other downhole tool embodiments described herein (see, e.g.
Receiving chamber 354 is in fluid communication with outlet flow line connector 322 through outlet conduit 318. Seals (313, 314) discussed in more detail below, prevent fluid communication between the inlet pressure chamber 353 and receiving chamber 354 on the one hand, and the interior flowpath 337 and the exterior of the tool on the other hand.
With reference to
A plurality of inlet sleeve seals 313 and outlet sleeve seals 314 in the mandrel and the ported housing engage sliding sleeve 310 to prevent fluid communication around sliding sleeve's 310 interior side—adjacent to the mandrel 340—and exterior side—adjacent to the ported housing 345. Inlet sleeve seals 313 engage the sliding sleeve 310 on the inlet side of sleeve ports 327 and housing ports 325 while outlet sleeve seals engage the sliding sleeve 310 on the outlet side of the sleeve ports 327 and the housing ports 325. Inlet sleeve seals 313 prevent fluid communication between inlet pressure chamber 353 and both the housing ports 325 and the sleeve ports 327. Outlet sleeve seals 314 prevent fluid communication between the receiving chamber 354 and both the housing ports 325 and sleeve ports 327.
Shear pin 330 may be included to engage the shifting sleeve 310 and mandrel 340, holding the shifting sleeve 310 in place. Other retention elements, such as collets, shear rings, springs, or other elements may be included to hold the shifting sleeve 310 in the first position until a predetermined pressure differential is created across the shifting sleeve 310.
Locking portion 407 partially occupies receiving chamber 354 below the shifting sleeve 310 and may comprise a plurality of mandrel teeth 403 configured to engage opposing ring teeth on a locking ring connected to shifting sleeve 310. When the sleeve 310 is shifted, ring teeth 335 engage mandrel teeth 403 along exterior surface 400 of mandrel 340 and inhibit movement of the shifting sleeve 310 back towards its first, e.g. closed, position.
The shifting sleeve 310 of downhole tool 375 is moveable within the annular space 315 between a first position, which is shown in
Further, movement of shifting sleeve 310 from the first position to the second position establishes fluid communication between the interior flowpath 337 of intermediate tool 375 and outlet flowline connection 322, via outlet conduit 318.
It will be appreciated that a downhole tool such as in illustrated in
Alternative embodiments of downhole tools according to the present disclosure are also possible. In contrast to the ported valves shown
Systems as described herein may also include a plug actuated initiator tool, such as the tool illustrated in
The embodiment plug seat initiator tool of
One or more shear pins 530 may be connected to the ported housing 545 and the sliding sleeve 510 to prevent movement of the sliding sleeve 510 from the first position to the second position until sufficient force is applied to the sliding sleeve 510, such as by a pressure differential across the plug seat 562, to break the one or more shear pins 530. Shear pins may be placed in additional or other locations, such as connecting the plug seat housing with the seat carrier, or other location, to maintain or help maintain the shifting sleeve in the first position. Further, it will be appreciated that other devices, such as collets, shear rings, springs, or other devices, may be employed to hold the shifting sleeve 510 in the first position until sufficient force is applied to overcome such restriction.
Outlet sub 550, isolation sleeve 580, sliding sleeve 510, plug seat 562, cement sleeve 566, and bottom sub 555 each has a generally tubular inner surface 590, 596, 594, 595, 598, and 592 respectively, which together define an interior flowpath 537 through initiator tool 575.
A pressure differential created across the plug seat 562—typically by applying fluid pressure to the interior of tubing string while plug seat 562 is engaged with an appropriately sized ball, dart, or other suitable plug—will shift the sleeve 510 from the first position to the second position, shown in
Based on the above description of certain embodiments, systems may be assembled by combining initiator, intermediate, and terminator downhole tools in series. One embodiment series is illustrated by
When the burst disk of initiator tool 620 (e.g.
Similarly to the initiator tool 620, movement of the shifting sleeve of intermediate tool 630a to the second position allows fluid communication between the interior flowpath and outlet flowline connector (e.g.
Intermediate tools may be strung together in series as desired. While the illustration in
Multiple series of tools according to the embodiments encompassed herein are possible by placing a plurality of selectively actuatable initiator tools, responsive to different actuation triggers, along the tubing string. Each initiator tool is connected to a series of intermediate and terminator tools, such that each series opens in response to the particular trigger of its associated initiator tool. Such an arrangement is illustrated in
In
Similarly to the first series, second series includes second initiator 720b, second intermediate 730b, and second terminator 740b tools connector by flowlines 750c and 750d. Third series includes third initiator 720c and third terminator 740c tools connected by flowline 750e.
The series are actuated in a desired order by use of the appropriate trigger at the desired time. For example, each initiator 720a-c may be a plug seat initiator, such as initiator 575 of
A second plug, which may be larger than the first plug, then engages the plug seat of initiator 720b actuating the second series of tools 720b, 730b, 740b. Second plug passes through third initiator 720c without actuating the third series 720c and 740c, such as because the second plug is too small to create sufficient pressure differential across the third initiator tool's 750c plug seat to actuate the third series. Further, engagement of the second plug on initiator tool 720b prevents fluid communication through the tubing string to the first series of tools connected to initiator 720a. Thus, such second plug allows treatment of the formation adjacent to the ported valves of the second series while preventing fluid flow through the ported valves of the first series and leaving the tools of the third series not actuated. A third plug may then engage the plug seat of and actuate the third initiator tool 720c and thereby actuate the third series. The engagement of the third plug on the third initiator tool's plug seat may also serve to prevent fluid flow therethrough, thereby allowing treatment of the subterranean formation adjacent to the ported valves of the third series while preventing fluid flow to the ported valves of the second series and the first series.
It will be appreciated that flapper valves or other valves may be incorporated into the tubing string such that plugs do not have to prevent fluid communication to previously actuated series, individual ported valves, perforations, or other structures. The use of flapper valves is contemplated within the scope of the invention as claimed.
Other methods of selectively actuating plug seat operated valves are also known. For example, the initiator tool may comprise a j-slot sleeve and pin assembly or other indexing element, such that the sliding sleeve will not move to the second position until a desired number of pressure cycles have been created across the indexing element. Such indexing element may be paired with an expandable c-ring or other expandable plug seat that releases the plug after generation of the desired pressure differential. Thus, by using plug seat initiators with an indexing element and expandable plug seat, multiple series of tools of the present disclosure may be actuated by using plugs of the same size.
Plug seat initiators may be mixed with burst disk initiators or other initiators in a single tubing string. For example, initiator tool 720a may be a burst disk initiator, either a ported valve version (such as initiator tool 120 of
After treatment of the first series, engagement of an appropriate plug on the plug seat of initiator tool 720b both actuates the second series and isolates the open ported valves of the first series from fluid flow occurring at the second series, as described above. Similarly, the third, and subsequent, series of ported valves are actuated, and adjacent areas of subterranean formations are treated, by engagement of subsequent plugs on the plug seats of those series' initiator tools according to known methods.
The downhole tool may be placed in positions other than the toe of the tubing, provided that sufficient internal flowpath pressure can be applied at a desired point in time to create the necessary pressure differential on the shifting sleeve. In certain embodiments, the internal flowpath pressure must be sufficient to rupture the burst disk, shear the shear pin, or otherwise overcome a pressure sensitive control element. However, other control devices not responsive to pressure may be desirable for the present device when not installed in the toe.
The downhole tool as described may be adapted to activate tools associated with the tubing rather than to open a flow path from the interior to the exterior of the tubing. Such associated tools may include a mechanical or electrical device which signals or otherwise indicates that the burst disk or other flow control device has been breached. Such a device may be useful to indicate the pressures a tubing string experiences at a particular point or points along its length. In other embodiments, the device may, when activated, trigger release of one section of tubing from the adjacent section of tubing or tool. For example, the shifting element may be configured to mechanically release a latch holding two sections of tubing together. Any other tool may be used in conjunction with, or as part of, the tool of the present disclosure provided that the inner member selectively moves within the space in response to fluid flow, such as changes in fluid pressure, fluid volume, velocity, pressure cycles, or the like, through the interior flowpath. Numerous such alternate uses will be readily apparent to those who design and use tools for oil and gas wells.
The illustrative embodiments are described with the shifting sleeve's first position being “upwell” or closer to the wellhead in relation to the shifting sleeve's second position, the downhole tool could readily be rotated such that the shifting sleeve's first position is “downwell” or further from the wellhead in relation to the shifting sleeve's second position. In addition, the illustrative embodiments provide possible locations for the flow path, fluid control device, shear pin, inner member, and other structures, those or ordinary skill in the art will appreciate that the components of the embodiments, when present, may be placed at any operable location in the downhole tool.
The present disclosure includes preferred or illustrative embodiments in which specific tools are described. Alternative embodiments of such tools can be used in carrying out the invention as claimed and such alternative embodiments are limited only by the claims themselves. Other aspects and advantages of the present invention may be obtained from a study of this disclosure and the drawings, along with the appended claims.
This application is a Continuation in Part, and claims the benefit, of U.S. patent application Ser. No. 13/462,180, filed May 2, 2012 entitled “Downhole Tool,” which claims the benefit of U.S. Provisional Patent Application Ser. No. 61/481,483 filed on May 2, 2011; claims the benefit of U.S. Provisional Patent Application Ser. No. 61/801,937, entitled “Downhole Tools System and Method of Using” filed on Mar. 15, 2013; and claims the benefit of U.S. Provisional Patent Application Ser. No. 61/862,766, entitled “Downhole Tools System and Method of Using” filed on Aug. 16, 2013. Each of the foregoing references are incorporated herein in their entirety
Number | Date | Country | |
---|---|---|---|
61801937 | Mar 2013 | US | |
61862766 | Aug 2013 | US | |
61481483 | May 2011 | US |
Number | Date | Country | |
---|---|---|---|
Parent | 13462810 | May 2012 | US |
Child | 14211122 | US |