Patent Application
20250198251
Inflatable production packers (IPPs) are downhole tools used in oil and gas operations to seal off an area of the wellbore from the rest of the wellbore. IPPs work by using a one way “poppet” valve and spring that allows a user to increase pressure within the tool from the surface. The increased pressure compresses the spring and allows a pressure of a fluid within the tool to increase, which inflates a rubber element, thereby setting the tool. When inflation is complete, there is a trapped volume of high-pressure fluid inside the tool. Downhole environments are hotter than the tool that is run into the wellbore and the fluid that pumped into the downhole tool. This heat causes the pressure of the (already high-pressure) fluid to increase further, which can rupture the rubber element and cause the tool to fail. Therefore, there is a need for an IPP that may operate in a hot downhole environment.
A downhole tool is disclosed. The downhole tool includes an inner mandrel having an inner mandrel bore that extends axially-therethrough. The downhole tool also includes a first valve configured to move between a first position and a second position. The downhole tool also includes an inflatable element configured to inflate and expand radially-outward and into contact with a surrounding tubular in response to the first valve moving to the second position, which permits a fluid in the inner mandrel bore to flow into the inflatable element. The downhole tool also includes a second valve configured to vent some of the fluid within the inflatable element to an exterior of the downhole tool in response to the fluid reaching a second valve pressure threshold.
An inflatable production packer (IPP) is also disclosed. The IPP includes an inner mandrel having an inner mandrel bore that extends axially-therethrough. The inner mandrel defines an inflation port that provides a path of fluid communication between the inner mandrel bore and an annulus within the downhole tool. The annulus is positioned radially-outward from the inner mandrel bore. The IPP also includes a first valve positioned within the annulus. The first valve is configured to move between a first position and a second position. In the first position, the first valve prevents fluid communication between the inner mandrel bore and the annulus. In the second position, the first valve permits fluid communication between the inner mandrel bore and the annulus. The IPP also includes an inflatable element in fluid communication with the annulus. The inflatable element inflates and expands radially-outward and into contact with a surrounding tubular in response to the first valve moving to the second position, which permits a fluid in the inner mandrel bore to flow through the inflation port and the annulus and into the inflatable element. The IPP also includes a crossover positioned below the inflatable element. The crossover defines a crossover bore that provides a path of fluid communication between the inflatable element and an exterior of the IPP. The IPP also includes a second valve positioned within the crossover bore. The second valve includes a pressure relief valve that is configured to vent some of the fluid within the inflatable element to the exterior of the IPP in response to the fluid reaching a second valve pressure threshold.
A method for operating an inflatable production packer (IPP) in a wellbore is also disclosed. The method includes running the IPP into the wellbore in a run-in position. The method also includes actuating the IPP from the run-in position to an inflation position by increasing a pressure of a fluid in a bore of the IPP, which actuates a first valve in the IPP from a first position to a second position and causes an inflatable element of the IPP to inflate and expand radially-outward and into contact with a surrounding tubular. The method also includes actuating the IPP from the inflation position to a set position by decreasing the pressure in the bore of the IPP, which actuates the first valve from the second position to the first position and traps a portion of the fluid in the inflatable element. The IPP includes a second valve that is configured vent some of the trapped portion of the fluid to an exterior of the IPP in response to the fluid reaching a second valve pressure threshold.
A method for operating an inflatable packer in a wellbore is also disclosed. The method includes running the inflatable packer into the wellbore. The method also includes actuating the inflatable packer, which causes an inflatable element of the inflatable packer to inflate and expand radially-outward upon application of a first pressure. The method also includes setting the inflatable packer when the first pressure reaches a second pressure. The method also includes reducing a portion of the second pressure when the second pressure reaches a third pressure. The third pressure is greater than the second pressure.
The present disclosure may best be understood by referring to the following description and accompanying drawings that are used to illustrate embodiments of the invention. In the drawings:
The following disclosure describes several embodiments for implementing different features, structures, or functions of the invention. Embodiments of components, arrangements, and configurations are described below to simplify the present disclosure; however, these embodiments are provided merely as examples and are not intended to limit the scope of the invention. Additionally, the present disclosure may repeat reference characters (e.g., numerals) and/or letters in the various embodiments and across the Figures provided herein. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed in the Figures. Moreover, the formation of a first feature over or on a second feature in the description that follows may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact. Finally, the embodiments presented below may be combined in any combination of ways, e.g., any element from one exemplary embodiment may be used in any other exemplary embodiment, without departing from the scope of the disclosure.
Additionally, certain terms are used throughout the following description and claims to refer to particular components. As one skilled in the art will appreciate, various entities may refer to the same component by different names, and as such, the naming convention for the elements described herein is not intended to limit the scope of the invention, unless otherwise specifically defined herein. Further, the naming convention used herein is not intended to distinguish between components that differ in name but not function. Additionally, in the following 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.” All numerical values in this disclosure may be exact or approximate values unless otherwise specifically stated. Accordingly, various embodiments of the disclosure may deviate from the numbers, values, and ranges disclosed herein without departing from the intended scope. In addition, unless otherwise provided herein, “or” statements are intended to be non-exclusive; for example, the statement “A or B” should be considered to mean “A, B, or both A and B.”
The downhole tool 100 may also include a valve 120 that is positioned within the annulus 116. The valve 120 may be or include a poppet valve, a check valve, and/or an inflation control valve. The valve 120 is shown in a first position in
The downhole tool 100 may also include an inflatable (e.g., rubber) element 140. The inflatable element 140 may be positioned radially-outward from the inner mandrel 110. The inflatable element 140 may be positioned below the valve 120 and/or the spring 130. The inflatable element 140 may be in fluid communication with the annulus 116.
The downhole tool 100 may also include a crossover 150. The crossover 150 may be positioned radially-outward from the inner mandrel 110. The crossover 150 may be positioned below the valve 120, the spring 130, the inflatable element 140, or a combination thereof. The crossover 150 may be in fluid communication with the annulus 116 and/or the inflatable element 140. As described in greater detail below, the crossover 150 may include a valve 160 (e.g., a pressure relief valve).
In the embodiment shown, a central longitudinal axis through a first portion of the bore 152 may be substantially parallel with a central longitudinal axis through the downhole tool 100, and a central longitudinal axis through a second portion of the bore 152 may be oriented at an angle with respect to the central longitudinal axis through the downhole tool 100. The angle may be from about 1 degree to about 90 degrees or from about 30 degrees to about 60 degrees. In another embodiment, the bore 152 may include a single portion that is oriented radially (e.g., perpendicular) with respect to the central longitudinal axis through the downhole tool 100. This latter embodiment may be used for larger crossovers that are thick enough to contain the valve 160 therein without protrusion from the crossover.
The valve 160 may be positioned at least partially within the bore 152 (e.g., the first portion of the bore 152). The valve 160 may be configured to prevent fluid flow therethrough when the pressure within the annulus 116, inflatable element 140, and/or bore 152 is less than a predetermined pressure threshold. However, the valve 160 may allow at least a portion of the fluid to flow therethrough to an exterior of the tool 100 (e.g., to the annulus between the downhole tool 100 and the surrounding tubular) when the pressure of the fluid is greater than the predetermined pressure threshold. This may help to prevent the pressure within the downhole tool 100 (e.g., the annulus 116, inflatable element 140, and/or bore 152) from exceeding the predetermined pressure threshold, which could rupture the inflatable element 140.
In one embodiment, the temperature of the downhole environment may cause the pressure within the downhole tool 100 to reach the predetermined pressure threshold. The number of bores 152 may be selected based upon the downhole temperature (e.g., the higher the downhole temperature, the greater the number of circumferentially-offset bores). The type, number, and/or size of valve(s) 160 may also be selected based upon the downhole temperature.
In another embodiment, the pressure within the downhole tool 100 may reach the predetermined pressure threshold in response to (e.g., inadvertently) increasing the pressure in the wellbore (and the downhole tool 100) too much (e.g., using a pump at the surface). Thus, the valve 160 may be an inflation control valve that is configured to control the inflation pressure of the inflatable element 140. In an example, the inflatable element 140 may have an inflation pressure of about 5,000 kPa, the pressure may (e.g., inadvertently) be raised to 10,000 kPa, and the valve 160 may be used to reduce (or relieve) the inflation pressure back down to about 5,000 kPa.
The method 300 may include running the downhole tool 100 into a wellbore, as at 310. The downhole tool 100 may be run in the first (e.g., run-in) position, as shown in
Once the downhole tool 100 reaches the desired location in the wellbore, the method 300 may also include actuating the downhole tool 100 into the second (e.g., inflation) position, as at 320.
Once the inflatable element 140 of the downhole tool 100 is (e.g., fully) inflated and/or in contact with the surrounding tubular, the method 300 may also include actuating the downhole tool 100 into the third (e.g., set) position, as at 330.
Once the valve 120 is back in the first position, the annulus 116 and the inflatable element 140 may be isolated from the bore 112 in the inner mandrel 110. At this point, the high-pressure fluid may be trapped within annulus 116 and the inflatable element 140 at a first (e.g., lower) pressure and a first (e.g., lower) temperature. In an example, the first (e.g., lower) pressure may be from about 3,500 kPa to about 10,350 kPa, and the first (e.g., lower) temperature from about 5° C. to about 20° C.
As mentioned above, in one embodiment, the temperature around the downhole tool 100 (e.g., in the annulus between the downhole tool 100 and the surrounding tubular, and/or the subsurface formation around the downhole tool 100) may be higher than the first temperature. In an example, the temperature around the downhole tool 100 may be at a second (e.g., higher) temperature that is from about 150° C. to about 175° C. This may cause the temperature of the fluid within inflatable element 140 to increase (e.g., up to the second temperature). In a conventional downhole tool (e.g., without the bore 152 and/or valve 160), the increasing temperature of the fluid would cause the pressure of the fluid to increase to a second (e.g., higher) pressure, which may cause the inflatable element 140 to rupture. The second (e.g., higher) pressure may be from about 17,500 kPa to about 20,000 kPa.
As mentioned above, in another embodiment, the pressure within the downhole tool 100 may exceed the first pressure and/or reach the second pressure in response to (e.g., inadvertently) increasing the pressure in the wellbore (and the downhole tool 100) too much (e.g., using a pump at the surface). In a conventional downhole tool (e.g., without the bore 152 and/or valve 160), this over-pressure may cause the inflatable element 140 to rupture.
However, the addition of the bore 152 and the valve 160 may prevent the pressure of the fluid from exceeding the predetermined pressure threshold of the valve 160. In other words, once the pressure of the fluid reaches the predetermined pressure threshold, at least a portion of the fluid may be vented out of the bore 152 and the valve 160 to the exterior of the downhole tool 100. The predetermined pressure threshold may be between the first (e.g., lower) pressure and the second (e.g., higher) pressure. In an example, predetermined pressure threshold may be from about 6,900 kPa to about 13,800 kPa.
As used herein, the terms “inner” and “outer”; “up” and “down”; “upper” and “lower”; “upward” and “downward”; “above” and “below”; “inward” and “outward”; “uphole” and “downhole”; and other like terms as used herein refer to relative positions to one another and are not intended to denote a particular direction or spatial orientation. The terms “couple,” “coupled,” “connect,” “connection,” “connected,” “in connection with,” and “connecting” refer to “in direct connection with” or “in connection with via one or more intermediate elements or members.”
The foregoing has outlined features of several embodiments so that those skilled in the art may better understand the present disclosure. Those skilled in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein. Those skilled in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure, and that they may make various changes, substitutions, and alterations herein without departing from the spirit and scope of the present disclosure.
This application claims priority to U.S. Provisional Patent Application No. 63/610,472, filed on Dec. 15, 2023, which is incorporated by reference.
| Number | Date | Country | |
|---|---|---|---|
| 63610472 | Dec 2023 | US |
