This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present invention, 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 invention. Accordingly, it should be understood that these statements are to be read in this light, and not as admissions of prior art.
Fluid systems, such as mineral extraction systems (e.g., oil and gas), typically include multiple segments of tubing, valves, and connectors that are sealed together by various seals. These seals are often subjected to harsh environmental conditions, such as corrosive fluids, extreme pressures, and extreme temperatures. Moreover, these seals are often disposed in remote equipment, such as a marine (e.g., sub-sea) wellhead, which can make access and repair difficult and expensive. Over time, these seals tend to lose their memory or shape. When this type of damage occurs, the seals begin to hold pressure less effectively, particularly at high pressures and sub-ambient temperatures. As such, it may be important to ensure that these seals are installed in a manner which minimizes damage (e.g., extrusion) during installation.
Various features, aspects, and advantages of the present invention 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 invention will be described below. These described embodiments are only exemplary of the present invention. 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.
Certain exemplary embodiments of the present invention include systems and methods for using an annular seal configured to expand radially when subjected to an axial force. More specifically, the annular seal may include a top seal section, a bottom seal section, and a core seal section. The core seal section may include non-orthogonal top and bottom faces when in a non-deformed shape. In addition, when in the non-deformed shape, the annular seal may be capable of being run into a wellhead while leaving a gap between the annular seal and inner and outer bodies through which the annular seal is run. This gap may reduce the likelihood of damage, such as extrusion.
When the axial force is exerted on the annular seal, the core seal section may expand radially, causing the annular seal to form a seal between the inner and outer bodies. In addition, the axial force may also cause the top and bottom faces of the core seal section to be deformed into an orthogonal alignment, causing the annular seal to form a seal between upper and lower bodies above and below the annular seal, respectively. In certain embodiments, the top and bottom seal sections may be configured to urge the top and bottom faces of the core seal section into the orthogonal alignment. For example, the top and bottom seal sections may be formed of harder materials pre-loaded in a manner biased toward orthogonal alignment of the top and bottom faces of the core seal section.
As will be appreciated, in the present context described herein, when the top and bottom faces of the core seal section are described as non-orthogonal when in a non-deformed shape, this means that the top and bottom faces of the core seal section do not form perpendicular surfaces relative to radially inner and outer faces of the core seal section. In other words, the top and bottom faces are not flat or parallel to a radial axis of the core seal section. Conversely, when the top and bottom faces of the core seal section are described as being brought into an orthogonal alignment when in a deformed shape due at least in part to the axial force, this means that the top and bottom faces of the core seal section are deformed in such a way that the top and bottom faces form substantially perpendicular surfaces relative to the radially inner and outer faces of the core seal section. In other words, the top and bottom faces become substantially flat and parallel to the radial axis of the core seal section.
The wellhead 12 may include multiple components that control and regulate activities and conditions associated with the well 16. For example, the wellhead 12 generally includes bodies, valves, and seals that route produced minerals from the mineral deposit 14, regulate pressure in the well 16, and inject chemicals down-hole into the well bore 20. In the illustrated embodiment, the wellhead 12 includes what is colloquially referred to as a Christmas tree 22 (hereinafter, a “tree”), a tubing spool 24, a casing spool 26, and a hanger 28 (e.g., a tubing hanger and/or a casing hanger). The system 10 may include other devices that are coupled to the wellhead 12, and devices that are used to assemble and control various components of the wellhead 12. For example, in the illustrated embodiment, the system 10 includes a running tool 30 suspended from a drill string 32. In certain embodiments, the running tool 30 is lowered (e.g., run) from an offshore vessel to the well 16 and/or the wellhead 12. In other embodiments, such as surface systems, the running tool 30 may include a device suspended over and/or lowered into the wellhead 12 via a crane or other supporting device.
The tree 22 generally includes a variety of flow paths (e.g., bores), valves, fittings, and controls for operating the well 16. For instance, the tree 22 may include a frame that is disposed about a tree body, a flow-loop, actuators, and valves. Further, the tree 22 may provide fluid communication with the well 16. For example, the tree 22 includes a tree bore 34. The tree bore 34 provides for completion and workover procedures, such as the insertion of tools into the well 16, the injection of various chemicals into the well 16, and so forth. Further, minerals extracted from the well 16 (e.g., oil and natural gas) may be regulated and routed via the tree 22. For instance, the tree 22 may be coupled to a jumper or a flowline that is tied back to other components, such as a manifold. Accordingly, produced minerals may flow from the well 16 to the manifold via the wellhead 12 and/or the tree 22 before being routed to shipping or storage facilities. A blowout preventer (BOP) 36 may also be included, either as a part of the tree 22 or as a separate device. The BOP may consist of a variety of valves, fittings, and controls to prevent oil, gas, or other fluid from exiting the well in the event of an unintentional release of pressure or an overpressure condition.
The tubing spool 24 provides a base for the tree 22. Typically, the tubing spool 24 is one of many components in a modular sub-sea or surface mineral extraction system 10 that is run from an offshore vessel or surface system. The tubing spool 24 includes a tubing spool bore 38. The tubing spool bore 38 connects (e.g., enables fluid communication between) the tree bore 34 and the well 16. Thus, the tubing spool bore 38 may provide access to the well bore 20 for various completion and workover procedures. For example, components can be run down to the wellhead 12 and disposed in the tubing spool bore 38 to seal off the well bore 20, to inject chemicals down-hole, to suspend tools down-hole, to retrieve tools down-hole, and so forth.
The well bore 20 may contain elevated pressures. For example, the well bore 20 may include pressures that exceed 10,000, 15,000, or even 20,000 pounds per square inch (psi). Accordingly, the mineral extraction system 10 may employ various mechanisms, such as seals, plugs, and valves, to control and regulate the well 16. For example, plugs and valves are employed to regulate the flow and pressures of fluids in various bores and channels throughout the mineral extraction system 10. For instance, the illustrated hanger 28 (e.g., tubing hanger or casing hanger) is typically disposed within the wellhead 12 to secure tubing and casing suspended in the well bore 20, and to provide a path for hydraulic control fluid, chemical injections, and so forth. The hanger 28 includes a hanger bore 40 that extends through the center of the hanger 28, and that is in fluid communication with the tubing spool bore 38 and the well bore 20. One or more seals may be disposed between the hanger 28 and the tubing spool 24 and/or the casing spool 26.
In certain embodiments, the landing assembly 44 may include a bottom landing ring 46, a hanger lockdown ring 48, a lockdown actuation ring 50, and a top landing ring 52. The bottom landing ring 46 may be threaded to the hanger 28. The landing assembly 44 may locate the hanger 28 in place and may be locked into position via the hanger lockdown ring 48 by radially engaging recesses 54 of the wellhead 12 (e.g., the casing spool 26). Once the landing assembly 44 is locked into place, the landing assembly 44 (and the hanger 28) may be locked by actuation of the lockdown actuation ring 50 such that the hanger lockdown ring 48 is locked radially into the recesses 54 of the wellhead 12. The hanger 28 may be adjusted by rotating the hanger 28 via the threads such that the hanger 28 moves along the bottom landing ring 46.
The top landing ring 52 may also be threaded to the hanger 28. In certain embodiments, the top landing ring 52 and bottom landing ring 46 may both couple to the hanger 28 via the same outer diameter threads. The top landing ring 52 may also be coupled to the bottom landing ring 46 via a protrusion 56 (e.g., a tongue) that engages a recess 58 of the bottom landing ring 46. As such, the top landing ring 52 may rotate in sync with the bottom landing ring 46 but may not allow load transfer between the top landing ring 52 and the bottom landing ring 46. In other embodiments, the top landing ring 52 may be coupled to the bottom landing ring 46 via a key and keyway, a castellation feature, or any other suitable mechanism. The protrusion 56 may provide a gap 60 between the bottom landing ring 46 and the top landing ring 52. As a result of the engagement between the top landing ring 52 and the bottom landing ring 46, the top landing ring 52 may isolate any vertical movement of the hanger 28 as a result of pressure either below or above the hanger 28 from the bottom landing ring 46. The top landing ring 52 “rides along” with any movement of the hanger 28 without transferring or off-loading any load, thus preventing damage to the hanger lockdown ring 48 and maintaining integrity of the hanger lockdown ring 48.
In certain embodiments, the seal assembly 42 may include a lower seal body 62, a lower test seal 64, an inner metal seal assembly 66, a middle seal body 68, an outer metal seal assembly 70, an upper seal body 72, an upper test seal 74, an upper seal actuation ring 76, and a carrier nut 78. The lower seal body 62 may abut the top landing ring 52 when the hanger 28 is installed, landed, and sealed in the wellhead 12. The middle seal body 68 may be connected to the lower seal body 62 at seal 80, such that both the lower test seal 64 and the inner metal seal assembly 66 fit between the middle seal body 68 and the lower seal body 62. In certain embodiments, the inner metal seal assembly 66 may include a pair of Canh seals, such as R-Canh or MRD-Canh seals. The upper seal body 72 may be connected to the middle seal body 68 at seal 82, such that the outer metal seal assembly 70 fits between the upper seal body 72 and the middle seal body 68. Again, in certain embodiments, the outer metal seal assembly 70 may include a pair of Canh seals, such as R-Canh or MRD-Canh seals. In addition, the upper seal body 72 may be connected to the upper seal actuation ring 76 at seal 84, such that the upper test seal 74 fits between the upper seal body 72 and the upper seal actuation ring 76.
The upper test seal 74 and the lower test seal 64 may generally be retracted radially while the hanger 28 is run into the wellhead 12, and expanded radially once the hanger 28 is landed and sealed in the wellhead 12. For example,
The annular seal 86 may have a cross-sectional composition generally comprised of three sections, e.g., a core seal section 96, a top seal section 98, and a bottom seal section 100. As illustrated, the core seal section 96 is axially between the top and bottom seal sections 98 and 100. The core seal section 96 may be comprised of an elastomer or rubber material while the top seal section 98 and bottom seal section 100 may be comprised of harder materials, such as fabric and certain metals. In particular, the top seal section 98 and the bottom seal section 100 may be configured to urge top and bottom faces of the core seal section 96 into an orthogonal alignment, which may form a seal with the upper inner body 90 and the lower inner body 92. In other words, the top seal section 98 and the bottom seal section 100 may urge the top and bottom faces of the core seal section 96 into a substantially parallel alignment with respect to a radial axis of the core seal section 96 to close the gap of the bore. For instance, the top seal section 98 and the bottom seal section 100 may be pre-loaded in a manner which may tend to urge top and bottom faces of the core seal section 96 toward an alignment which is substantially perpendicular to radially inner and outer faces of the core seal section 96 across the entire surface of the top and bottom faces. In addition, in certain embodiments, the annular seal 86 may include one or more radially inner grooves 102 and one or more radially outer grooves 104 for increasing the sealing volume.
As described above, while the hanger 28 is being run into the wellhead 12, the annular seal 86 may be retracted radially. In other words, the annular seal 86 may be configured such that when in a non-deformed (“pre-loaded”) shape, the annular seal 86 has a cross-section with non-orthogonal top and bottom faces and the radial width of the cross-section of the annular seal 86 is approximately equal to the radial width WUIB between a radially inner face 106 and a radially outer face 108 of the upper inner body 90, leaving a gap Wgap between the annular seal 86 and the outer body 88. In other words, the total radial width Wtotal between the radially inner face 106 of the upper inner body 90 and the outer body 88 may be equal to the radial width WUIB between the radially inner face 106 and the radially outer face 108 of the upper inner body 90 plus the gap Wgap. Since there is a gap Wgap between the annular seal 86 and the outer body 88 while the hanger 28 is being run into the wellhead 12, the annular seal 86 may be less susceptible to extrusion while, for instance, running through the BOP 36. As such, the annular seal 86 may remain capable of creating tighter seals over the life of the annular seal 86 since damage from extrusion during installation is minimized.
Once the hanger 28 is landed and sealed in the wellhead 12, the annular seal 86 may expand radially as the annular seal 86 deforms into a deformed (“loaded”) shape having a cross-section with substantially orthogonal top and bottom faces. In other words, the top and bottom faces may be deformed into being substantially parallel to a radial axis of the annular seal 86. This is due at least in part to the force of the axial load Faxial that is distributed between the upper inner body 90 and the lower inner body 92 once the hanger 28 is landed in the wellhead 12. The axial force Faxial is created at least in part by the weight of the components above the annular seal 86. As the axial force Faxial is applied to the annular seal 86, the core seal section 96 of the annular seal 86 may deform (e.g., axial compression) such that the radial width of the annular seal 86 increases to the total radial width Wtotal between the radially inner face 106 of the upper inner body 90 and the outer body 88 (e.g., radial expansion). More specifically, portions of the core seal section 96 may deform from the top and bottom of the core seal section 96, decreasing the height (e.g., axial compression) of the core seal section 96 but increasing the radial width (e.g., radial expansion) of the core seal section 96. The degree of radial expansion of the core seal section 96 may vary based on the particular geometries used, materials used for the core seal section 96, the amount of the axial force Faxial, and so forth. However, in certain embodiments, the core seal section 96 may expand radially by 5-10% or more of the radial width of the annular seal 86. As the radial width of the annular seal 86 increases, the annular seal 86 may gradually apply a radial force Fradial between the radially inner face 106 of the upper inner body 90 and the outer body 88, creating a seal between the bodies. Also, as illustrated in
The particular cross-sectional profile of the core seal section 96 of the annular seal 86 may vary between embodiments.
Conversely,
Conversely,
Conversely,
Although
For instance,
Therefore, as illustrated in
While the invention 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 invention is not intended to be limited to the particular forms disclosed. Rather, the invention is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the invention as defined by the following appended claims.
This application claims priority to and benefit of PCT Patent Application No. PCT/US2010/024339, entitled “Full Bore Compression Sealing Method,” filed Feb. 16, 2010, which is herein incorporated by reference in its entirety, and which claims priority to and benefit of U.S. Provisional Patent Application No. 61/164,362, entitled “Full Bore Compression Sealing Method”, filed on Mar. 27, 2009, which is herein incorporated by reference in its entirety.
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