Patent Grant
10550657
This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present disclosure, which are described and/or claimed below. 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 present disclosure. Accordingly, it should be understood that these statements are to be read in this light, and not as admissions of prior art.
Oil and natural gas have a profound effect on modern economies and societies. In order to meet the demand for such natural resources, numerous companies invest significant amounts of time and money in searching for, accessing, and extracting oil, natural gas, and other subterranean resources. Particularly, once a desired resource is discovered below the surface of the earth, drilling and production systems are often employed to access and extract the resource. These systems can be located onshore or offshore depending on the location of a desired resource. Such systems generally include a wellhead assembly through which the resource is extracted. These wellhead assemblies generally include a wide variety of components and/or conduits, such as blowout preventers (BOPs), as well as various control lines, casings, valves, and the like, that control drilling and/or extraction operations.
Hangers (e.g., tubing hangers or casing hangers) may be used to support sections or strings of casing or tubing within a wellhead assembly. In addition, hangers may regulate pressures and provide a path for hydraulic control fluid, chemical injections, or the like to be passed through the wellhead and into the well bore. In such a system, various seals (e.g., annular seals) are often disposed between various components of the wellhead system, such as the tubing spool, casing spool, casing hanger, tubing hanger, pack off assembly, and so forth, to regulate and isolate pressure between such components. Unfortunately, installation of such seals may be time consuming, costly, and/or complex.
Various features, aspects, and advantages of the present disclosure will become better understood when the following detailed description is read with reference to the accompanying figures in which like characters represent like parts throughout the figures, wherein:
One or more specific embodiments of the present disclosure will be described below. These described embodiments are only exemplary of the present disclosure. Additionally, in an effort to provide a concise description of these exemplary embodiments, all features of an actual implementation may not be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.
When introducing elements of various embodiments of the present disclosure, the articles “a,” “an,” “the,” and “said” are intended to mean that there are one or more of the elements. The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements. Moreover, 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.
The presently disclosed embodiments include a hydraulically actuated running tool (e.g., seal assembly running tool) capable of installing a seal assembly within a wellhead in less time than typical running tools. Specifically, the hydraulically actuated running tool may utilize axial force as well as a partial rotation (e.g., less than one revolution) to install the seal assembly. Installing the seal assembly using both axial force and hydraulics may reduce the time and cost associated with setting up and operating a mineral extraction system. Specifically, in the disclosed embodiments, a plurality of pistons are sequentially actuated via a pressurized fluid to actuate components of the running tool to engage and secure the seal assembly in the wellbore. Subsequently, the running tool may be released from the seal assembly by partial rotation (e.g., less than one revolution), or in some embodiments, no rotation. The running tool may then be retrieved from the wellhead assembly.
Reducing an amount of rotation that the running tool incurs to install the seal assembly may reduce a number of parts that may be included in the running tool. Accordingly, a height and/or overall size of the running tool may be reduced as a result of fewer components that are included in the running tool. Additionally, a hydraulic fluid system that may be utilized to actuate and/or drive components of the running tool may be less complex because such hydraulic system may not be utilized to cause the running tool to rotate.
The illustrated wellhead hub 20, which may be a large diameter hub, acts as an early junction between the well 16 and the equipment located above the well. The wellhead hub 20 may include a complementary connector, such as a collet connector, to facilitate connections with the surface equipment. The wellhead hub 20 may be configured to support various strings of casing or tubing that extend into the wellbore 18, and in some cases extending down to the mineral deposit 12.
The wellhead 14 generally includes a series of devices and components that control and regulate activities and conditions associated with the well 16. For example, the wellhead 14 may provide for routing the flow of produced minerals from the mineral deposit 12 and the well bore 18, provide for regulating pressure in the well 16, and provide for the injection of chemicals into the well bore 18 (down-hole). In the illustrated embodiment, the wellhead 14 includes a casing spool 22 (e.g., tubular), a tubing spool 24 (e.g., tubular), a seal assembly 26 (e.g., to provide a seal between a hanger and/or another component and the casing spool 22), and a blowout preventer (BOP) 28.
In operation, the wellhead 14 enables completion and workover procedures, such as tool insertion into the well 16 for installation and removal of various components (e.g., hangers, shoulders, packoffs, etc.). Further, minerals extracted from the well 16 (e.g., oil and natural gas) may be regulated and routed via the wellhead 14. For example, the blowout preventer (BOP) 28 may include a variety of valves, fittings, and controls to prevent oil, gas, or other fluid from exiting the well 16 in the event of an unintentional release of pressure or an overpressure condition.
As illustrated, the casing spool 22 defines a bore 30 that enables fluid communication between the wellhead 14 and the well 16. Thus, the casing spool bore 30 may provide access to the well bore 18 for various completion and workover procedures, such as emplacing tools or components within the casing spool 22. To emplace the components, a shoulder 32 provides a temporary or permanent landing surface that can support pieces of equipment (e.g., hangers, seal assemblies, packoffs, among others). For example, the illustrated embodiment of the extraction system 10 includes a tool 34 suspended from a drill string 36. In certain embodiments, the tool 34 may include running tools (e.g., seal assembly running tools, hanger running tools, shoulder running tools, slip tools, etc.) that are lowered (e.g., run) to the well 16, the wellhead 14, and the like. The seal assembly 26 may be installed on the shoulder 32 and used to seal components that may be utilized to support sections of casing or tubing within the wellhead assembly 14.
While the present discussion focuses on the running tool 100 coupled to the seal assembly 26 using the breech connection 101, it should be understood that other coupling techniques may be utilized. For example, the running tool 100 may be coupled to the seal assembly 26 by one or more shear pins (see, e.g.,
For reference, a coordinate system is shown comprising an axial direction or axis 50, a radial direction or axis 52, and a circumferential direction or axis 54 relative to a central axis 55. It should be noted that
The seal assembly 26 includes a generally annular body 102, which defines a bore 104 and a mounting interface 106 (e.g., the breech connection 101), which may be used to couple to the running tool 100. The body 102 of the seal assembly 26 may include one or more movable members 108 (e.g., axial and/or radial moving members) that may be configured to be engaged by the running tool 100. For example, the seal assembly 26 may include a sealing member 110 (e.g., a sealing ring or another suitable sealing device), an additional sealing member 111 (e.g., a sealing ring, a split ring, a c-ring, or another suitable sealing device, as well as a lock member 112 (e.g., a lock ring or one or more radial locking dogs). The sealing member 110 may be configured to form a seal between the seal assembly 26 and a tubular (e.g., the casing spool 22) of the wellhead assembly 14 and the additional sealing member 111 may form a seal between the seal assembly 26 and a hanger, for example.
In some embodiments, a first push member 114 (e.g., a first push ring) may be configured to direct the sealing member 110 and/or the additional sealing member 111 along the radial axis 52. For example, the first push member 114 may direct the sealing member 110 radially away from the seal assembly 26 and toward the tubular of the wellhead assembly 14 (e.g., in a first radial direction). Additionally, the first push member 114 may direct the additional member 111 radially inward from the seal assembly 26 and toward the hanger (e.g., in a second radial direction). The lock member 112 may be configured to secure the seal assembly 26 to a tubular (e.g., the drill string 36) disposed in the bore 104 of the seal assembly 26. Accordingly, a second push member 116 (e.g., a second push ring) may be included in the seal assembly 26 to direct the lock member 112 along the radial axis 52, such that the lock member 112 may move radially inward toward a tubular (or another component) disposed in the bore 104 of the seal assembly 26. Accordingly, the seal assembly 26 may provide a seal between the tubular of the wellhead assembly 14 and the tubular within the bore 104 of the seal assembly 26. While the illustrated embodiment of
The running tool 100 includes an annular body 150, which defines a bore 152. The body 150 also defines first and second fluid passages 154, 156, which may be pressurized by a pressurized fluid (e.g., hydraulically, pneumatically, etc.) in order to actuate various components of the hanger running tool 100, which may engage components (e.g., the first push member 114 and/or the second push member 116) of the seal assembly 26. The first and second fluid passages 154, 156 may be in fluid communication with first and second pressure ports 158, 160, disposed at a first axial end 161 of the hanger running tool 100. Fluid (e.g., air, hydraulic fluid, oil, water, etc.) in the passages 154, 156 may be pressurized from one or more pressurized fluid sources (e.g., fluid pumps, tanks, accumulators, etc.) through applying pressure via the first and second pressure ports 158, 160.
The pressure ports 158, 160 and corresponding fluid passages 154, 156 may supply a pressure force to one or more pistons of the running tool 100. For example, the running tool 100 may include a first piston 162 (e.g., an upper piston or an outer piston) and a second piston 164 (e.g., a lower piston or an inner piston). The first piston 162 may be generally annular in shape (e.g., annular piston) and disposed within a cavity 166 (e.g., an annular cavity) formed in the body 150. The first piston 162 includes an annular protrusion 168 that protrudes radially toward the body 150, such that the first piston 162 is secured within the cavity 166 of the body 150. The annular protrusion 168 of the first piston 162 may include one or more seals 170 (e.g., o-rings) disposed in recesses 171 that form a seal between the first piston 162 and the body 150. As shown in the illustrated embodiment of
The second piston 164 (e.g., annular piston) may be disposed within a second cavity 180 of the body 150. The second cavity 180 may form a second volume 182 (e.g., annular volume or piston-cylinder chamber), which is in fluid communication with the second pressure port 160. The second piston 164 moves back and forth in the axial direction 50 relative to the body 150, causing the second volume 182 to expand or contract. The second piston 164 may be coupled to a fourth push member 184, which may be configured to actuate the second push member 116 of the seal assembly 26. It should be noted that while the illustrated embodiment of
As shown in the illustrated embodiment of
In some embodiments, the first tapered surface 206 interfaces with the second tapered surface 208, such that the sealing member 110 moves radially outward (e.g., in a first radial direction) from an unsealed position toward a sealed position and/or the additional sealing member 111 moves radially inward (e.g., in a second radial direction) from an unsealed position toward a sealed position. Correspondingly, when the first piston 162 moves upward in the axial direction 50, the sealing member 110 expands radially inward (e.g., in the second radial direction) from the sealed position toward the unsealed position and/or the additional sealing member 111 moves radially outward (e.g., in the first radial direction) from the sealed position toward the unsealed position. As discussed above, the seal assembly 26 may include other configurations than those illustrated in
Additionally, a first axial end 209 of the fourth push member 184 may engage a first axial end 211 of the second push member 116. When the second piston 164 moves downward in the axial direction 50 (e.g., when a pressure force is applied to the second piston 164 via the first pressure port 158), the fourth push member 184 may direct the second push member 116 in the axial direction 50 as indicated by arrow 230. In some embodiments, the second push member 116 may include a third tapered surface 210 (e.g., an annular tapered surface, a conical surface, or another energizing surface) that may engage a fourth tapered surface 212 (e.g., an annular tapered surface, a conical surface, or another energizing surface) of the lock member 112. The third tapered surface 210 may engage the fourth tapered surface 212 to direct the lock member 112 in the inward radial direction 52 (e.g., in the second radial direction) toward the tubular disposed in the bore 104 of the seal assembly 26. The third tapered surface 210 interfaces with the fourth tapered surface 212, such that the lock member 112 moves radially inward from an unlocked position toward a locked position. Correspondingly, when the second piston 164 moves upward in the axial direction 50, the lock member 112 expands radially outward from the locked position toward the unlocked position.
In some embodiments, the sealing member 110 and/or the additional sealing member 111 may be engaged (e.g., actuated) before the lock member 112, such that the seal assembly 26 forms the seal before the seal assembly 26 is secured to (or within) the wellhead assembly 14. Accordingly, the lock ring 186 of the running tool 100 may secure both the running tool 100 and the seal assembly 26 within the wellhead assembly 14 as the seal, or seals, are formed. However, in other embodiments, the lock member 112 may be engaged before the sealing member 110 and/or the additional sealing member 111, or the lock member 112 and the sealing member 110 may be engaged (e.g., actuated) at substantially the same time (e.g., generally simultaneously).
When the first piston 162 moves downward in the axial direction 50, the third push member 178 may engage the first push member 114 of the sealing member 110. In other embodiments, the third push member 178 may engage the sealing member 110 (or the additional sealing member 111) directly and/or engage other components of the seal assembly 26 to set the sealing member 110.
Further, the second piston 164 may also be moved downward in the axial direction 50, as shown by the arrow 230. For example,
When the second piston 164 moves downward in the axial direction, the fourth push member 184 may engage the second push member 116. For example,
Once the seal assembly 26 has been coupled to the tubular 284, the running tool 100 may release the seal assembly 26. For example,
The breech connection 101 between the running tool 100 and the seal assembly 26 may then be removed, as shown in
At block 304, the running tool 100 and the seal assembly 26 may be disposed (e.g., run) into the wellhead assembly 14 and secured to the wellhead assembly 14. In some embodiments, the lock ring 186 of the running tool 100 may secure the running tool 100 and seal assembly 26 to the wellhead assembly 14, such that the seal may be formed. At block 306, the first piston 162 of the running tool 100 may be actuated (e.g., via pressure supplied through the first pressure port 158) to direct the third push member 178 to engage the first push member 114. The first push member 114 may then engage the additional sealing member 111, such that the sealing member 110 moves radially outward to form a seal between the seal assembly 26 and the tubular 256 of the wellhead assembly 14 and the additional sealing member 111 moves radially inward to form a seal between the seal assembly 26 and the hanger.
At block 308, the second piston 164 of the running tool 100 may be actuated (e.g., via pressure supplied through the second pressure port 160) to direct the fourth push member 184 to engage the second push member 116. Accordingly, the second push member 116 may engage the lock member 112, such that the lock member 112 moves radially inward to secure the seal assembly 26 to the tubular 284 disposed in the bore 104 of the seal assembly 26. As discussed above, blocks 306 and 308 may occur sequentially or simultaneously. In any case, once the seal assembly 26 is secured in the wellhead assembly 26, the running tool 100 may be unsecured (e.g., de-coupled) from the seal assembly 26 and removed from the wellhead assembly 14, as shown at block 310. For example, the lock ring 186 of the running tool 100 may be disengaged and the breech connection 101 between the running tool 100 and the seal assembly 26 may be removed (e.g., de-coupled by rotating the running tool 100 less than one full rotation). Accordingly, the running tool 100 may be moved in the axial direction 50 out of the wellhead assembly 14, while the seal assembly 26 remains in the wellhead assembly 14 to maintain a seal.
While the disclosed subject matter may be susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and have been described in detail herein. However, it should be understood that the disclosure is not intended to be limited to the particular forms disclosed. Rather, the disclosure is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the disclosure as defined by the following appended claims.
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