Patent Publication Number: US-11021926-B2

Title: Apparatus, system, and method for isolating a tubing string

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application claims the benefit of U.S. Provisional Patent Application having Ser. No. 62/702,744 which was filed Jul. 24, 2018. The aforementioned patent application is hereby incorporated by reference in its entirety into the present application to the extent consistent with the present application. 
    
    
     BACKGROUND 
     Packers are often used in oil and gas wells to isolate an area of casing or tubing within a wellbore. Packers typically include slips with gripping teeth that engage an inner diameter of the casing or tubing when an axial load is applied to the packer, thereby actuating the packer. Hydraulic pressure is often used to produce the axial load to actuate the packer. When hydraulic pressure is used to actuate the packer, the casing or tubing below the packer must be closed. 
     A common way to isolate the casing or tubing below the packer or any tubing string needing isolation is to position a nipple in the casing or tubing below the packer or tubing string needing isolation and position a standing valve within the nipple. The standing valve may be a check valve that includes a trapped ball to open and close the standing valve. The trapped ball may prevent fluid and/or pressure from flowing through the standing valve to the casing or tubing below the standing valve thereby isolating the packer above the standing valve. However, the trapped ball may allow fluid and/or pressure to pass through and/or above the standing valve for pressure relief. Once the packer is set or there is no longer a need for isolation in the casing or tubing, the standing valve may be pulled out of the casing or tubing by wireline. However, the nipple positioned below the packer or the tubing string remains in the casing or tubing below, which results in a permanent restriction within the casing or tubing below the packer or the tubing string. 
     Therefore, there is a need for a device and method that may isolate a packer or tubing string without leaving a restriction in the casing or tubing below the packer or tubing string and be removed without well intervention. 
     SUMMARY 
     One embodiment of the invention may include a valve for isolating a portion of tubing string in a hydrocarbon well. The valve may include a valve body that includes a ball seat, an anchor that is positioned on the valve body, and a ball that is configured to seat on the ball seat of the valve body. The anchor may be configured to position the valve within a nipple that is positioned below the portion of tubing string. The valve body, the anchor, and the ball may be constructed from a dissolvable material. 
     Another embodiment of the invention may include a system for isolating a portion of tubing string in a hydrocarbon well. The system may include a nipple including an inner surface that defines a groove, a dissolvable valve including a valve body that includes a ball seat, an anchor that is positioned on the valve body and fits in the groove of the nipple, and a dissolvable ball configured to seat on the ball seat. 
     Another embodiment of the invention may include a method for isolating a portion of tubing string in a hydrocarbon well. The method may include positioning a dissolvable valve within a nipple. The dissolvable valve may include a ball seat. The method may further include positioning the nipple below the portion of tubing string in the hydrocarbon well and seating a dissolvable ball on the ball seat. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The present disclosure is best understood from the following detailed description when read with the accompanying Figures. It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion. 
         FIG. 1  is a cross-sectional view of an apparatus for isolating a portion of tubing string prior to assembly, according to one or more embodiments disclosed herein. 
         FIG. 2  is a cross-sectional view of another apparatus for isolating a apportion of tubing string, according to one or more embodiments disclosed herein. 
         FIG. 3  is a cross-sectional view of the apparatus of  FIG. 1  when the apparatus is locked into a nipple and prior to the device being actuated, according to one or more embodiments disclosed herein. 
         FIG. 4  is a cross-sectional view of an apparatus and system for isolating a portion of tubing string after actuation, according to one or more embodiments disclosed herein. 
         FIG. 5  is a flowchart depicting a method for isolating a portion of tubing string, according to one or more embodiments disclosed herein. 
     
    
    
     DETAILED DESCRIPTION 
     It is to be understood that the following disclosure describes several exemplary embodiments for implementing different features, structures, or functions of the invention. Exemplary embodiments of components, arrangements, and configurations are described below to simplify the present disclosure; however, these exemplary embodiments are provided merely as examples and are not intended to limit the scope of the invention. Additionally, the present disclosure may repeat reference numerals and/or letters in the various exemplary 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 exemplary embodiments and/or configurations discussed in the various 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 exemplary embodiments presented below may be combined in any combination of ways, i.e., 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. Furthermore, as it is used in the claims or specification, the term “or” is intended to encompass both exclusive and inclusive cases, i.e., “A or B” is intended to be synonymous with “at least one of A and B,” unless otherwise expressly specified herein. 
     Embodiments of the invention could be used in a variety of oil and gas applications, which could include both vertical and directional wells. Accordingly, position terminology such as “above” and “below” should be interpreted relative to the tubing string opening at the surface of the earth, where “above” is in a position closer to the opening at the surface of the earth, and “below” is in a position further from the opening at the surface of the earth. The terms “upstream” and “downstream” are to be interpreted relative to the direction of flow. Upstream is against the flow and downstream is with the flow. Accordingly, if component A is upstream of component B, component A is closer to the toe or end of the well than component B. The most upstream portion of the well is the end of farthest portion of the tubing string away from the surface. 
     Embodiments of the disclosure generally provide an apparatus, system, and method for isolating a tubing string in a hydrocarbon well. The apparatus, which may be a dissolvable valve, may be pre-installed in a nipple that is positioned below the portion of tubing string. The dissolvable valve may be constructed of a dissolvable material and may include a ball seat. The dissolvable valve may be actuated by dropping a dissolvable ball down the tubing string to seat on the ball seat. Upon actuation, the dissolvable valve may prevent fluid from flowing past the ball seat in a downhole direction. As wellbore and production fluids come in contact with the dissolvable valve and the dissolvable ball, the dissolvable valve and the dissolvable ball may dissolve completely leaving no restriction within the nipple positioned below the portion of tubing string. 
       FIG. 1  is a cross-sectional view of a device for isolating a portion of tubing string, according to one embodiment disclosed herein. The device may include a dissolvable valve  100  that may be positioned within a nipple  10 . In one embodiment, the dissolvable valve  100  may be pre-installed in the nipple  10  before it is run in a wellbore on a tubing string. The nipple  10  may be substantially cylindrical and may include an outer surface  15  with an outer diameter  18  and an inner surface  20  with an inner diameter  22 . The inner surface  20  of the nipple  10  may further define a groove  25  that is configured to receive an anchor  150  of the dissolvable valve  100  when the dissolvable valve  100  is positioned within the nipple  10 . 
     The dissolvable valve  100  may include a valve body  105  and the anchor  150  for positioning within the nipple  10 . Both the valve body  105  and the anchor  150  may be constructed from a dissolvable material. The dissolvable material may be a dissolvable plastic like polyglycolic acid (“PGA”), a dissolvable metal such as magnesium aluminum alloy or aluminum alloy, a combination of dissolvable plastic and dissolvable metal, or any other dissolvable material suitable for a hydrocarbon well. 
     The valve body  105  may include a valve outer surface  106  and a valve inner surface  108 . The valve body  105  may further include an upper portion  110  and a lower portion  115 . The valve outer surface  106  may include an upper outer diameter  112 , and the upper outer diameter  112  may be substantially the same (within +/−10%) as the inner diameter  22  of the nipple  10 . The valve outer surface  106  at the upper portion  110  may define a valve groove  120  that is configured to receive a seal  122 . The seal  122  may provide a seal between the dissolvable valve  100  and the nipple  10 . In one embodiment, the seal  122  may consist of a dissolvable material. Alternatively, and as shown in  FIG. 2 , the valve outer surface  106  may include teeth  124  that may be used to provide a seal between the dissolvable valve  100  and the nipple  10 . 
     The inner surface  108  of the upper portion  110  of the valve body  105  may define a ball seat  125  that is configured to receive a ball  190  (shown in  FIG. 4 ). The valve outer surface  106  at the lower portion  115  may include a tapered outer surface  118  where the outer diameter decreases along a length of the valve body  105 . The lower portion  115  of the valve body  105  may include an inner diameter  130  that defines the valve inner surface  108 . 
     The anchor  150  may include an anchor outer surface  155  and a tapered anchor inner surface  165 . The tapered inner surface  165  may include an inner diameter that decreases along a length of the anchor  150 . In one embodiment, the angle of the tapered inner surface  165  may correspond to and be substantially the same (within +/−10%) as the angle of the tapered outer surface  118  of the valve body  105 . The tapered anchor inner surface  165  may include an inner diameter  168  at an anchor upper portion  154  that may be greater than a diameter of the tapered outer surface  118  of the valve body  105  at its smallest outer diameter. Accordingly, when the anchor  150  and the valve body  105  are inserted into the nipple  10  from opposite ends and pushed together using opposing forces  170  and  175 , the anchor  150  may slide over the valve outer surface  106 . The valve body  105  and the anchor  150  may be pre-installed in the nipple  10  prior to being inserted within the tubing string and sent downhole. 
     In one embodiment, once the valve body  105  and the anchor  150  are inserted into the nipple  10 , a setting tool may apply opposing forces  170  and  175  on the valve body  105  and the anchor  150 , respectively, in order to push the valve body  105  and the anchor  150  together and set the dissolvable valve  100  in the nipple  10 . As the valve body  105  is pushed down and the anchor  150  is pushed up using the opposing forces  170  and  175 , respectively, the anchor  150  may be radially expanded as the tapered outer diameter  118  of the valve body  105  forces the tapered inner diameter  154  of the anchor  150  outward. The tapered inner surface  165  of the anchor  150  may follow the tapered outer surface  118  of the valve body  105  as the anchor  150  radially expands until the anchor outer surface  155  expands to fit within the groove  25  of the nipple  10 , as shown in  FIGS. 2 and 3 . In one embodiment, the anchor  150  may include a length  152  that may be received either entirely or in part by the groove  25  of the nipple  10 . The application of the opposing forces  170  and  175  to the valve body  105  and the anchor  150 , respectively, result in an interference fit between the valve body  105  and the anchor  150 , which allows the valve body  105  and the anchor  150  to be affixed to one another via a friction fit, and the dissolvable valve  10  may be affixed to the nipple  10 . In one embodiment, either or both the valve outer surface  106  and the anchor inner surface  165  may include teeth (not shown) to provide extra friction to hold the valve body  105  and the anchor  150  together. 
     After the dissolvable valve  100  is mounted within the nipple  10 , the nipple may be positioned in the tubing string below the portion of tubing string needing isolation in an oil and gas well. In one embodiment, the portion of tubing string needing isolating may include a packer. In one embodiment, fluid may freely flow through the dissolvable valve  100  before the dissolvable valve  100  has been actuated. 
       FIG. 4  is a cross-sectional view of a system  200  for isolating a portion of tubing string (not shown), according to one or more embodiments disclosed herein. As discussed the portion of tubing string needing isolation may include a packer. When the portion of tubing string needs to be isolated, or the packer needs to be hydraulically actuated, the dissolvable valve  100  may be actuated by dropping the ball  190  downhole in the tubing to seat on the ball seat  125  of the dissolvable valve  100 . In one embodiment, the system  200  may include the nipple  10 , the dissolvable valve  100  affixed to the nipple  10 , and the ball  190  seated on the ball seat  125  of the dissolvable valve  100 . In one embodiment, the ball  190  may be constructed from a dissolvable material. When the ball  190  is seated on the dissolvable valve  100 , fluid may be prevented from flowing past the dissolvable valve  100  to a second portion of tubing string downhole from the portion of tubing string or packer needing isolation. However, in the event pressure is greater below the dissolvable valve  100 , fluid may displace the ball  190  and relieve the pressure in the second portion of tubing string by allowing fluid to flow through the dissolvable valve  100 . 
     As wellbore fluids come in contact with the dissolvable valve  100  and the ball  190 , the dissolvable valve  100  and the ball  190  may completely dissolve. After the dissolvable valve  100  and the ball  190  are dissolved, the nipple  10  may be left without any restriction. In addition, no wireline is required to pull the dissolvable valve  100  from the nipple  10  which reduces operation time and costs, as well as avoids other potential issues associated with running wirelines. 
     In one embodiment of the invention, a method  300  for isolating a portion of tubing string in a hydrocarbon well is also contemplated and shown in  FIG. 5 . In step  302 , a dissolvable valve may be positioned within a nipple. The dissolvable valve may include a valve body and an anchor that are pushed together from opposite ends in step  304 . The dissolvable valve may be locked in a groove of the nipple in step  306 . In step  308 , a dissolvable ball may be seated on the dissolvable valve, which isolates a casing or a second portion of tubing below the dissolvable valve from the portion of tubing string. In step  310 , the dissolvable ball and the dissolvable valve may be dissolved by wellbore fluids. 
     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.