Patent Application
20180252061
This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the presently described embodiments. This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the described embodiments. Accordingly, it should be understood that these statements are to be read in this light and not as admissions of prior art.
In a hydrocarbon production well, it is many times beneficial to be able to regulate flow of fluids from an earth formation into a wellbore, from the wellbore into the formation, and within the wellbore. A variety of purposes may be served by such regulation, including prevention of water or gas coning, minimizing sand production, minimizing water and/or gas production, maximizing oil production, balancing production among zones, transmitting signals, etc.
For example, it is common to deploy hydraulic control lines in subterranean wellbores, such as oil wells, in order to control downhole equipment. Packers, valves, and perforating guns are some of the downhole tool types that can be controlled by changes in pressure in the fluid contained in the hydraulic control lines or contained in production or drill pipes. In some prior art systems, multiple control lines are deployed in the wellbore to control multiple downhole tools. Typically the top end of each control line extends to the surface (land or sea floor) and is connected to a hydraulic pump that can control the pressure of the fluid inside the line.
A control line must be passed through a feedthrough of a packer in order to extend the control line from the top to the bottom of the packer (or across the packer). Among others, a function of a packer is to seal the wellbore annulus across the packer. However, each time a control line is extended through a feedthrough, a potential leak path is created in the packer potentially allowing the seal created by the packer to fail. Therefore, the prior art would benefit from a system that decreases the number of control lines necessary to control multiple downhole tools.
For a detailed description of the embodiments of the invention, reference will now be made to the accompanying drawings in which:
The illustrated figures are only exemplary and are not intended to assert or imply any limitation with regard to the environment, architecture, design, or process in which different embodiments may be implemented.
Turning now to the present figures,
As depicted in
A change in pressure or a pressure cycle in the tubing 16, such as induced by a pressure source, may be used to control or actuate each indexing sleeve 20. An actuation in each indexing sleeve 20 may activate, deactivate, or change the setting of the corresponding flow control device 18, depending on the construction and configuration of the relevant indexing sleeve 20 and flow control device 18. In the present application, the indexing sleeves 20 are constructed and configured so as to function in concert or together so as to provide a different permutation of settings of the plurality of the flow control devices 18 for each pressure change or cycle induced in the tubing 16. A user can thereby control the valve systems 17 as a system to select his/her desired permutation of settings for each of the flow control devices 18.
Referring now to
The tool 100 also includes a pressure operating device 114, such as an indexing sleeve discussed above. The pressure operating device 114 may be in fluid communication with the annulus 112 and/or the bore 110 of the tool 100. For example, in this embodiment, the pressure operating device 114 is positioned within the annulus 112 of the tool 100. As the pressure operating device 114 is in fluid communication with the annulus 112 and the bore 110 of the tool 100, pressure (e.g., fluid pressure) introduced into the bore 110 of the tool 100 is communicated to and exerted upon the pressure operating device 114. A change in pressure or a pressure cycle in the bore 110 of the tool 100 may therefore be used to control or actuate the pressure operating device 114. Accordingly, the pressure operating device 114 is used to operate in response to a pressure above an operating pressure (e.g., 3,000 psi, 20,700 kPa). Therefore, when pressure is introduced into the bore 110 above the operating pressure, the pressure may be used to operate and activate the pressure operating device 114. When pressure is below the operating pressure, the pressure operating device 114 may remain inactive. For example, a pressure above the operating pressure, such as above about 3,000 psi, will cause an indexing sleeve to move a flow control device, such as to open or close the flow control device, to control fluid flow through the bore 110 of the tool 100.
Referring still to
Further, a backup piston 122 (e.g., lower piston, second piston) may be positioned within the annulus 112 between the inner housing 106 and the outer housing 108, thereby forming a backup cavity 124 within the annulus 112. In particular, the backup piston 122 may be positioned between the primary piston 116 and the pressure operating device 114. The backup piston 122 may then be positioned between and separate the primary cavity 118 from the second cavity 124, and the pressure operating device 114 may then be in fluid communication with the second cavity 124. The backup piston 122 includes one or more seals 126 to sealingly engage an outer surface of the inner housing 106 and/or an inner surface of the outer housing 108.
In this embodiment, the backup piston 122 may include a pressure inhibiting device 128, such as to prevent pressure that is below a predetermined amount from communicating across the backup piston 122. For example, the backup piston 122 may include a flow path 130 extending therethrough to enable pressure and/or fluid to flow along the flow path 130 and through the backup piston 122. The pressure inhibiting device 128, however, may prevent pressure that is below a predetermined amount from flowing along the flow path 130 and through the backup piston 122. An example of a pressure inhibiting device 128 may include a frangible element (e.g., burst disc) and/or a relief valve.
In one or more embodiments, the predetermined amount of pressure for the pressure inhibiting device 128 is lower than the operating pressure for the pressure operating device 114. For example, in an embodiment in which the operating pressure for the pressure operating device 114 is at or above 3,000 psi (20,700 kPa), the predetermined amount of pressure for the pressure inhibiting device may be at or lower than about 2,000 psi (13,800 kPa). This may enable fluid flow through the pressure inhibiting device 128 and the backup piston 122 such that the pressure may still be able to operate and activate the pressure operating device 114.
A tool or system in accordance with one or more embodiments of the present disclosure may be able to operate, even in the occurrence of one or more leaks within the tool. For example, with respect to
As mentioned above, a tool in accordance with the present disclosure may include two or more pistons positioned therein. Accordingly, in another embodiment, such as shown in
In addition to the embodiments described above, many examples of specific combinations are within the scope of the disclosure, some of which are detailed below:
A downhole tool, comprising:
The downhole tool of Example 1, wherein the pressure operating device is configured to operate in response to the pressure in the annulus being above an operating pressure.
The downhole tool of Example 2,wherein the operating pressure is at or above about 3,000 psi (20,700 kPa).
The downhole tool of Example 2, wherein the backup piston is positioned between the primary cavity and the second cavity and comprises a pressure inhibiting device configured to prevent pressure below a predetermined amount from communicating across the backup piston.
The downhole tool of Example 4,wherein the predetermined amount of pressure for the pressure inhibiting device is lower than the operating pressure for the pressure operating device.
The downhole tool of Example 4, wherein the predetermined amount for the pressure inhibiting device is at or lower than about 2,000 psi (13,800 kPa).
The downhole tool of Example 4, wherein the pressure inhibiting device comprises at least one of a frangible element and a relief valve, and wherein the frangible element comprises a burst disc.
The downhole tool of Example 4, further comprising another backup piston positioned within the annulus to form another backup cavity within the annulus positioned between the primary cavity and the other backup cavity.
The downhole tool of Example 8, wherein:
The downhole tool of Example 1, wherein the pressure operating device is positioned within the annulus and is in fluid communication with the second cavity.
The downhole tool of Example 1,wherein the pressure operating device comprises an indexing sleeve.
The downhole tool of Example 1, wherein a port is formed within inner housing to enable fluid communication between a bore of the inner housing and the annulus.
The downhole tool of Example 1,wherein at least one of the primary piston and the backup piston comprises a seal to sealingly engage the tool body.
A method to operate a pressure operating device in a downhole tool, the method comprising:
The method of Example 14,wherein the communicating the pressure across the backup piston comprises communicating the pressure through a pressure inhibiting device of the backup piston if a pressure differential develops across the backup piston above a predetermined amount.
The method of Example 15, wherein the pressure operating device operates in response to a pressure above an operating pressure, wherein the predetermined amount of pressure for the pressure inhibiting device is lower than the operating pressure for the pressure operating device.
The method of Example 15, wherein the pressure inhibiting device comprises at least one of a frangible element and a relief valve, and wherein the frangible element comprises a burst disc.
The method of Example 15, further comprising communicating the pressure across another backup piston positioned within the annulus, wherein the communicating the pressure across the other backup piston comprises communicating the pressure through a back pressure inhibiting device of the other backup piston if a pressure differential develops across the other backup piston above a second predetermined amount, and wherein the second predetermined amount for the backup pressure inhibiting device is higher than the first predetermined amount for the primary pressure inhibiting device.
The method of Example 14, wherein the pressure operating device comprises an indexing sleeve.
A downhole tool, comprising:
This discussion is directed to various embodiments of the invention. The drawing figures are not necessarily to scale. Certain features of the embodiments may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in the interest of clarity and conciseness. Although one or more of these embodiments may be preferred, the embodiments disclosed should not be interpreted, or otherwise used, as limiting the scope of the disclosure, including the claims. It is to be fully recognized that the different teachings of the embodiments discussed may be employed separately or in any suitable combination to produce desired results. In addition, one skilled in the art will understand that the description has broad application, and the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to intimate that the scope of the disclosure, including the claims, is limited to that embodiment.
Certain terms are used throughout the description and claims to refer to particular features or components. As one skilled in the art will appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name but not function, unless specifically stated. In the discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . .” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. In addition, the terms “axial” and “axially” generally mean along or parallel to a central axis (e.g., central axis of a body or a port), while the terms “radial” and “radially” generally mean perpendicular to the central axis. The use of “top,” “bottom,” “above,” “below,” and variations of these terms is made for convenience, but does not require any particular orientation of the components.
Reference throughout this specification to “one embodiment,” “an embodiment,” or similar language means that a particular feature, structure, or characteristic described in connection with the embodiment may be included in at least one embodiment of the present disclosure. Thus, appearances of the phrases “in one embodiment,” “in an embodiment,” and similar language throughout this specification may, but do not necessarily, all refer to the same embodiment.
Although the present invention has been described with respect to specific details, it is not intended that such details should be regarded as limitations on the scope of the invention, except to the extent that they are included in the accompanying claims.
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/US2015/053115 | 9/30/2015 | WO | 00 |
