ONE TRIP SLIM WELLHEAD SYSTEMS AND METHODS

Abstract

A wellhead system includes a first casing hanger configured to support a first casing. The wellhead system also includes a second casing hanger configured to support a second casing within the first casing. The wellhead system further includes a seal assembly configured to provide an annular seal between the first casing hanger and the second casing hanger. The seal assembly is configured to move between a first position in which the seal assembly enables a flow of fluid across the second casing hanger and a second position in which the seal assembly blocks the flow of fluid across the second casing hanger.

Description

CROSS-REFERENCE TO RELATED APPLICATION

This application claims priority to and the benefit of U.S. Provisional Application Serial No. 63/476243, entitled “ONE TRIP SLIM WELLHEAD SYSTEMS AND METHODS” and filed Dec. 20, 2022, the disclosure of which is incorporated herein by reference in its entirety for all purposes.

BACKGROUND

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.

Natural resources, such as oil and gas, are used as fuel to power vehicles, heat homes, and generate electricity. Once a desired natural resource is discovered below a surface of the earth, mineral extraction systems are often employed to access and extract the desired natural resource. The mineral extraction systems may be located onshore or offshore depending on the location of the desired natural resource. The mineral extraction systems generally include a wellhead through which the desired natural resource is extracted. The wellhead may include or be coupled to a wide variety of components, such as a tubing hanger that supports a tubing, a casing hanger that supports a casing, valves, fluid conduits, and the like.

SUMMARY

A summary of certain embodiments disclosed herein is set forth below. It should be understood that these aspects are presented merely to provide the reader with a brief summary of these certain embodiments and that these aspects are not intended to limit the scope of this disclosure. Indeed, this disclosure may encompass a variety of aspects that may not be set forth below.

In certain embodiments, a wellhead system includes a first casing hanger configured to support a first casing. The wellhead system also includes a second casing hanger configured to support a second casing within the first casing. The wellhead system further includes a seal assembly configured to provide an annular seal between the first casing hanger and the second casing hanger. The seal assembly is configured to move between a first position in which the seal assembly enables a flow of fluid across the second casing hanger and a second position in which the seal assembly blocks the flow of fluid across the second casing hanger.

In certain embodiments, a wellhead system includes a casing hanger comprising a flow path and configured to support a casing. The wellhead system also includes a seal assembly configured to provide an annular seal between the casing hanger and an additional annular structure. The seal assembly is configured to move between a first position in which the seal assembly enables a flow of fluid across the casing hanger via the flow path and a second position in which the seal assembly blocks the flow of fluid across the casing hanger via the flow path.

In certain embodiments, a method of operating a wellhead system includes running a hanger and a seal assembly within an additional hanger. The method also includes performing cementing operations while the seal assembly is in a first axial position to enable a flow of fluid across the seal assembly via a passage formed through the hanger. The method further includes, after the cementing operations, moving the seal assembly to a second axial position to block the flow of fluid across the seal assembly and to seal an annular space between the hanger and the additional hanger with the seal assembly.

BRIEF DESCRIPTION OF THE DRAWINGS

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:

FIG. 1 is a block diagram of a mineral extraction system, in accordance with an embodiment of the present disclosure;

FIG. 2 is a cross-sectional side view of an embodiment of a diverter assembly that may be utilized to facilitate installation of components of a wellhead;

FIG. 3 is a cross-sectional side view of an embodiment of the diverter assembly engaged with a conductor during installation of a first casing hanger of the wellhead;

FIG. 4 is cross-sectional side view of an embodiment of the diverter assembly being disengaged from the conductor;

FIG. 5 is a cross-sectional side view of an embodiment a blowout preventer (BOP) adapter and a BOP stack coupled to the first casing hanger;

FIG. 6 is a cross-sectional side view of an embodiment of a wear sleeve positioned within the BOP adapter and a portion of the first casing hanger;

FIG. 7 is a cross-sectional side view of an embodiment of a second casing hanger and a second casing hanger running tool;

FIG. 8 is a cross-sectional side view of an embodiment of the second casing hanger and the second casing hanger running tool engaged with one another;

FIG. 9 is a cross-sectional side view of an embodiment of the second casing hanger and the second casing hanger running tool within the BOP adapter and landed on the first casing hanger;

FIG. 10 is a cross-sectional side view of an embodiment a portion of the wellhead with a seal assembly in a first position between the first casing hanger and the second casing hanger;

FIG. 11 is a cross-sectional side view of an embodiment of a portion of the wellhead with the seal assembly in a second position between the first casing hanger and the second casing hanger;

FIG. 12 is a cross-sectional side view of an embodiment of a portion of the wellhead with the second casing running tool separated from the second casing hanger;

FIG. 13 is cross-sectional side view of an embodiment of a tubing hanger, a tubing hanger seal assembly, and a tubing hanger running tool;

FIG. 14 is a cross-sectional side view of an embodiment of the tubing hanger, the tubing hanger seal assembly, the tubing hanger running tool, and a control line bushing assembled together;

FIG. 15 is a cross-sectional side view of an embodiment of the tubing hanger, the tubing hanger seal assembly, the tubing hanger running tool, and the control line bushing landed on the second casing hanger;

FIG. 16 is a cross-sectional side view of an embodiment of a portion of the wellhead with a control line port coupled to the second casing hanger, wherein the control line port is shown in an exploded view;

FIG. 17 is a cross-sectional side view of an embodiment of a portion of the wellhead with the control line port coupled to the second casing hanger, wherein the control line port is shown in an assembled view; and

FIG. 18 is a cross-sectional side view of an embodiment of the wellhead with the first casing hanger, the second casing hanger, the tubing hanger, the control line port, and other components assembled together to form the wellhead.

DETAILED DESCRIPTION OF SPECIFIC EMBODIMENTS

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 used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to.” Also, any use of any form of the terms “connect,” “engage,” “couple,” “attach,” or any other term describing an interaction between elements is intended to mean either an indirect or a direct interaction between the elements described. In addition, as used herein, 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. For instance, an axial distance refers to a distance measured along or parallel to the central axis, and a radial distance means a distance measured 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. The term “fluid” encompasses liquids, gases, vapors, and combinations thereof.

Certain embodiments of the present disclosure generally relate to a one trip slim wellhead systems and methods. For example, certain embodiments of the present disclosure related to components that facilitate landing, locking, and setting a seal assembly for a casing hanger in a wellhead. Various additional features and advantages of the one trip slim wellhead systems and methods are described herein.

FIG. 1 is a block diagram of an embodiment of a mineral extraction system 10. The mineral extraction system 10 may be utilized to access and/or extract various natural resources (e.g., hydrocarbons, such as oil and/or natural gas) from the earth. As illustrated, the mineral extraction system 10 includes a wellhead 12 (e.g., annular wellhead) coupled to a mineral deposit 14 via a well 16. The well 16 may include a wellhead hub 18 (e.g., annular wellhead hub) and a wellbore 20. The wellhead hub 18 generally includes a large diameter hub disposed at an end of the wellbore 20 and is configured to connect the wellhead 12 to the wellbore 20. As will be appreciated, the wellbore 20 may contain elevated pressures. For example, the wellbore 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.

In the illustrated embodiment, the mineral extraction system 10 includes a tree 22, a tubing spool 24, a casing spool 26, and a blowout preventer (BOP) 38. The tree 22 generally includes a variety of flow paths (e.g., bores), valves, fittings, and controls for operating the well 16. Further, the tree 22 may provide fluid communication with the well 16. For example, the tree 22 includes a tree bore 28 that 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, the natural resources extracted from the well 16 may be regulated and routed via the tree 22. For example, the tree 22 may be coupled to a flowline that is tied back to other components, such as a manifold.

As shown, the tubing spool 24 may provide a base for the tree 22 and includes a tubing spool bore 30 that connects (e.g., enables fluid communication between) the tree bore 28 and the well 16. As shown, the casing spool 26 may be positioned between the tubing spool 24 and the wellhead hub 18 and includes a casing spool bore 32 that connects (e.g., enables fluid communication between) the tree bore 28 and the well 16. Thus, the tubing spool bore 30 and the casing spool bore 32 may provide access to the wellbore 20 for various completion and workover procedures. The BOP 38 may consist of a variety of valves, fittings, and controls to block oil, gas, or other fluid from exiting the well 16 in the event of an unintentional release of pressure or an overpressure condition.

As shown, a tubing hanger 34 is positioned within the tubing spool 24. The tubing hanger 34 may be configured to support tubing (e.g., a tubing string) that is suspended in the wellbore 20 and/or to provide a path for control lines, hydraulic control fluid, chemical injections, and so forth. Additionally, as shown, a casing hanger 36 is positioned within the casing spool 26. The casing hanger 36 may be configured to support casing (e.g., a casing string) that is suspended in the wellbore 20. It should be appreciated that the wellhead 12 may include multiple stages or levels of casing hangers that support multiple stages or levels of casing. A tool 40 (e.g., hydraulic tool) may be utilized to lower the tubing hanger 34 into the tubing spool 24 and/or the casing hanger 36 into the casing spool 26. To facilitate discussion, the mineral extraction system 10, and the components therein, may be described with reference to an axial axis or direction 44, a radial axis or direction 46, and a circumferential axis or direction 48.

FIG. 2 is a cross-sectional side view of an embodiment of a portion of the wellhead 12. As shown, a conductor 50 with a landing ring 52 supports a diverter assembly 54. The diverter assembly 54 may include a diverter body 56, one or more slip segments 58 (e.g., multiple separate slip segments or a c-ring), one or more retaining screws 60 (e.g., set screws), and one or more retracting screws 62 (e.g., set screws). In operation, the conductor 50 may be run into the wellbore, then the landing ring 52 may be run to engage the conductor 50, and then, the diverter assembly 54 may be run to circumferentially surround the conductor 50 and the landing ring 52.

To facilitate discussion, FIG. 3 illustrates the diverter assembly 54 in a first configuration 64 (e.g., open or expanded configuration) and in a second configuration 66 (e.g., closed or compressed configuration). In particular, in FIG. 3, a left side of a center axis 68 represents the diverter assembly 54 in the first configuration 64, and a right side of the center axis 68 represents the diverter assembly in the second configuration 66. As discussed herein, the diverter assembly 54 may be in the first configuration 64 while the diverter assembly 54 is run to circumferentially surround the conductor 50 and the landing ring 52. Then, the one or more retaining screws 60 may be moved toward the one or more slip segments 58 (e.g., rotated within a threaded bore of the diverter body 56 to move axially downwardly and/or radially inwardly toward the one or more slip segments 58). In this way, the one or more retaining screws 60 may contact and drive the one or more slip segments 58 against the conductor 50 (e.g., to contact and engage a radially outer wall of the conductor 50) to transition the diverter assembly 54 into the second configuration 66.

As shown in FIG. 3, while the diverter assembly 54 is in the second configuration 66, a first casing hanger running tool 80 may run a first casing hanger 82 (e.g., one stage of the casing hanger 36 of FIG. 1) that supports a first casing 84. Further, while the diverter assembly 54 is in the second configuration 66, cementing operations to cement the first casing 84 within the wellbore may be completed. In particular, the first casing hanger running tool 80 may run the first casing hanger 82 with the first casing 84 until the first casing hanger 82 lands on the landing ring 52. The first casing hanger 82 provides a flow path 86 that enables a flow of fluid to flow axially across the first casing hanger 82 as shown by arrows 88 (e.g., from an annular space defined between the first casing 84 and the conductor 50 at a first location axially below the first casing hanger 82 to an additional annular space or bore within an annular wall 90 of the diverter assembly 54 at a second location axially above the first casing hanger 82). For example, during the cementing operations to cement the first casing 84 within the wellbore, returns may flow through the flow path 86.

With reference to FIG. 4, after the cementing operations or at another suitable time, the first casing hanger running tool 80 may be withdrawn and the diverter assembly 54 may be adjusted from the second configuration 66 of FIG. 3 to the first configuration 64. As discussed herein, the diverter assembly 54 may be in the second configuration 66 during the cementing operations. Then, the one or more retaining screws 60 may be moved away from the one or more slip segments 58 (e.g., rotated within the threaded bore of the diverter body 56 to move axially upwardly and/or radially outwardly away the one or more slip segments 58). In this way, the one or more retaining screws 60 may enable the one or more slip segments 58 to separate or release from the conductor 50 (e.g., from the radially outer wall of the conductor 50) to transition the diverter assembly 54 into the first configuration 64. In some embodiments, the diverter assembly 54 may include the one or more retracting screws 62 to facilitate or to cause the diverter assembly 54 to transition from the second configuration 66 to the first configuration 64. For example, the one or more retracting screws 62 may be moved toward the one or more slip segments 58 (e.g., rotated within a threaded bore of the diverter body 56 to move axially upwardly and/or radially inwardly toward the one or more slip segments 58). In this way, the one or more retracting screws 62 may facilitate or cause the one or more slip segments 58 to separate or release from the conductor 50 (e.g., from the radially outer wall of the conductor 50) to transition the diverter assembly 54 into the first configuration 64. Then, the diverter assembly 54 may be withdrawn. As shown, the one or more retaining screws 60 and the one or more retracting screws 62 are oriented at angles relative to the axial axis 44 and the radial axis 46 (e.g., extend axially and radially) and also engage respective tapered surfaces (e.g., oppositely tapered surfaces) of the one or more slip segments 58 to drive the one or more slip segments 58 as disclosed herein.

FIG. 5 is a cross-sectional side view of an embodiment of a portion of the wellhead 12 with a BOP adapter 100 and a BOP stack 102. In operation, after the diverter assembly 54 is withdrawn, the BOP adapter 100 may be run until the BOP adapter 100 is landed on the first casing hanger 82. Further, the BOP adapter 100 and the BOP stack 102 may be coupled together via one or more fasteners 104 (e.g., threaded fasteners, such as bolts). As shown, the BOP adapter 100 may include multiple ports, such as pressure ports 106 and continuous control line ports 108. Once the BOP adapter 100 and the BOP stack 102 are positioned as shown in FIG. 5, a BOP test component may be inserted into the BOP adapter 100 to enable pressure testing of the BOP stack 102 (e.g., seal the bore axially below the BOP stack 102 to enable the pressure testing of the BOP stack 102). Additionally or alternatively, as shown in FIG. 6, a wear sleeve 110 (e.g., bushing) may be inserted into the BOP adapter 100 using a wear sleeve running tool 112. The wear sleeve 110 may protect a radially inner surface of the BOP adapter 100, as well as other components (e.g., the first casing hanger 82, annular seals between the first casing hanger 82 and the BOP adapter 100), during operations to drill out the wellbore to place additional casing.

FIG. 7 is a cross-sectional side view of an embodiment of a second casing running tool 120 and a second casing hanger 122 (e.g., one stage of the casing hanger 36 of FIG. 1) that supports a second casing 124, and FIG. 8 is a cross-sectional side view of an embodiment of the second casing running tool 120 engaged with the second casing hanger 122 that supports the second casing 124. As shown in FIGS. 7 and 8, the second casing running tool 120 includes a main tool body 126 and an outer sleeve 128 that extends from the main tool body 126. The second casing running tool 120 is positioned relative to the second casing hanger 122 to place a portion of the main tool body 126 within the second casing hanger 122 and to place a portion of the outer sleeve 128 to circumferentially surround the second casing hanger 122. Thus, a portion of the second casing hanger 122 may also be positioned within an annular space defined between the main tool body 126 and the outer sleeve 128. The second casing running tool 120 and the second casing hanger 122 may be brought together such that the outer sleeve 128 is landed on a push ring 130 of the second casing hanger 122.

FIG. 9 is a cross-sectional side view of an embodiment of the second casing hanger 122 placed within the BOP adapter 100. In operation, the second casing running tool 120 runs the second casing hanger 122 that supports the second casing 124 until the second casing hanger 122 is landed on the first casing hanger 82. With the second casing running tool 120 coupled to the second casing hanger 122 and the second casing hanger 122 landed on the first casing hanger 82, a flow path 132 enables a flow of fluid to flow axially across the second casing hanger 122 as shown by arrows 134 (e.g., from an annular space defined between the second casing 124 and the first casing 84 at a first location axially below the second casing hanger 122 to an additional annular space or bore within the BOP adapter 100 at a second location axially above the second casing hanger 122). For example, during the cementing operations to cement the second casing 124 within the wellbore, returns may flow through the flow path 132. In particular, as shown in an inset 138 of a portion of the wellhead 12 of FIG. 9, the returns may flow from the annular space defined between the second casing 124 and the first casing 84 at the first location axially below the second casing hanger 122, into a first portion 140 of the flow path 132 in the second casing hanger 122, through a second portion 142 of the flow path 132 in a space defined radially between the second casing hanger 122 and the first casing hanger 82, through a third portion 144 of the flow path 132 in the first casing hanger 82, and through in a fourth portion 146 of the flow path 132 in a space defined radially between the outer sleeve 128 of the second casing running tool 120 and the BOP adapter 100. Then, the returns may flow through an opening 150 through the outer sleeve 128 of the second casing running tool 120 and through a fifth portion 152 of the flow path 132 in the main tool body 126 of the second casing running tool 120 to reach the additional annular space or bore within the BOP adapter 100 at the second location axially above the second casing hanger 122, such as an additional annular space 154 shown in FIG. 9. Further, as shown in FIGS. 7-9, the second casing hanger 122 is coupled to a seal assembly 160, and the second casing hanger 122 is run with the seal assembly 160. The second casing hanger 122 and the seal assembly 160 may be considered to form a hanger assembly.

FIGS. 10-12 illustrate additional details of an embodiment of the second casing hanger 122 and the seal assembly 160. In particular, FIG. 10 illustrates features shown in the inset 138 of FIG. 9 with certain reference numbers omitted for image clarity. Further, FIG. 10 illustrates that at least certain portions of the seal assembly 160 are isolated from the flow path 132. Thus, at least the certain portions of the seal assembly 160 are isolated and protected from the returns that flow through the flow path 132 during the cementing operations. Additionally, FIG. 10 illustrates that the seal assembly 160 may include or be coupled to the push ring 130, a lock ring 162, a push ring extension 164 (e.g., in contact with or integrally formed with the push ring 130), a shear pin 166, a fluid port 168, and one or more annular seals 170 (e.g., o-rings; elastomer or metal annular seals). Advantageously, at least the lock ring 162 and/or the one or more annular seals 170 are isolated and protected from the returns that flow through the flow path 132 during the cementing operations.

After the cementing operations or at any other suitable time, the seal assembly 160 may be driven axially relative to the second casing hanger 122 (e.g., within the annular space defined between the second casing hanger 122 and the first casing hanger 82). With reference to FIGS. 10 and 11, after the cementing operations, the outer sleeve 128 of the second casing running tool 120 is driven axially as shown by arrow 180 (e.g., via hydraulic actuation; from its position in FIG. 10 to its position in FIG. 11). As a result, the outer sleeve 128 exerts a force on the push ring 130 and the push ring extension 164 that causes the shear pin 166 to shear (e.g., break). Then, the outer sleeve 128, the push ring 130, and the push ring extension 164 move axially as shown by the arrow 180 to drive the seal assembly 160 relative to the second casing hanger 122. The seal assembly 160 may move from a first position 182 shown in FIG. 10 in which the seal assembly 160 enables the returns to flow through the flow path 132 axially across the second casing hanger 122 to a second position 184 shown in FIG. 11 in which the seal assembly 160 blocks the returns from flowing through the flow path 132 (e.g., seals the annular space between the second casing hanger 122 and the first casing hanger 82; seals the flow path 132; isolates the annular space defined between the second casing hanger 122 and the first casing hanger 82 at the first axial location below the first casing hanger 82 from the annular space or the bore within the BOP adapter 100 at the second axial location above the first casing hanger 82). For example, as shown in FIG. 11, the annular seals 170 seal against a radially outer surface of the second casing hanger 122 and a radially inner surface of the first casing hanger 82 at a location below the third portion 144 of the flow path 132 in the first casing hanger 82 to block the returns from flowing through the flow path 132.

As shown, the lock ring 162 may move axially as shown by the arrow 180, and the lock ring 162 may be driven radially inwardly by a tapered surface (e.g., upper surface) of a protrusion 186 (e.g., annular protrusion) formed in the radially inner surface of the first casing hanger 82. Then, the lock ring 162 may expand below the protrusion 186 and engage an axially facing surface (e.g., lower surface) of the protrusion 186 to lock the seal assembly 160 relative to the first casing hanger 82 (and thus, relative to the BOP adapter 100 and other components of the wellhead 12; block axial movement of the seal assembly 160).

Once the seal assembly is in the second position 184 shown in FIG. 11, the second casing running tool 120 shown in FIG. 11 may be withdrawn. At some later time, a fastener 188 (e.g., a threaded fastener) may be utilized to engage the push ring extension 164 to drive the push ring extension 164 toward the lock ring 162. The push ring extension 164 may drive the lock ring 162 radially inwardly (e.g., collapse the lock ring 162) to enable the second casing hanger 122 and the seal assembly 160 to be withdrawn. Additionally, as shown, a fluid port 190 may relieve pressure from the flow path 132 during certain operations and/or provide fluid into the flow path 132 (e.g., to drive the seal assembly 160 upwardly relative to the second casing hanger 122 and to move the lock ring 162 axially above the protrusion 186 to facilitate withdrawal of the second casing hanger 122).

FIGS. 13-15 illustrate an embodiment of a tubing hanger 200 (e.g., the tubing hanger 34 of FIG. 1) that supports a tubing 202 in the wellhead 12. As shown in FIGS. 13 and 14, the tubing hanger 200 supports the tubing 202, and the tubing hanger 200 may also include or be coupled to a tubing hanger seal assembly 204. Additionally, the tubing hanger 200 may also include or be coupled to a control line bushing 206 (e.g., annular bushing). Together, the tubing hanger 200, the tubing hanger seal assembly 204, and/or the control line bushing 206 may be considered to form a tubing hanger assembly.

In operation, the tubing hanger seal assembly 204 may be positioned to circumferentially surround a portion of the tubing hanger 200, and the control line bushing 206 may be coupled to a portion of the tubing hanger 200 (e.g., a neck or an upper end portion of the tubing hanger 200). Then, a tubing hanger running tool 208 may engage the tubing hanger 200 with the tubing 202, the tubing hanger seal assembly 204, and the control line bushing 206 coupled thereto.

Once assembled as shown in FIG. 14, the tubing hanger running tool 208 may run the tubing hanger 200, the tubing 202, the tubing hanger seal assembly 204, and the control line bushing 206 together into the BOP adapter 100, as shown in FIG. 15. For example, the tubing hanger running tool 208 may run these components until landed on the second casing hanger 122 or other structure. Then, a fluid is applied via a first pressure port 212 (of the pressure ports 106 shown in FIG. 5) to drive a tapered push ring 214 between a lock ring 216 (e.g., for the tubing hanger running tool 208) and a surface of the tubing hanger running tool 208. In turn, this causes the lock ring 216 to move radially outwardly to engage a corresponding recess 218 formed in the BOP adapter 100. To facilitate discussion, a left side of the center axis 68 shows the lock ring 216 withdrawn from the corresponding recess 218, and a right side of the center axis 68 shows the lock ring 216 engaged with the corresponding recess 218.

Additionally or alternatively, a fluid is applied via a second pressure port 222 (of the pressure ports 106 shown in FIG. 5) to drive an additional push ring 220 of the tubing hanger running tool 208 (and possibly intermediate components of the tubing hanger seal assembly 204 and/or the tubing hanger running tool 208) to thereby drive an additional lock ring 224 of the tubing hanger seal assembly 204 radially outwardly to engage the second casing hanger 122. To facilitate discussion, a left side of the center axis 68 shows the additional lock ring 224 withdrawn from the second casing hanger 122, and a right side of the center axis 68 shows the additional lock ring 224 engaged with the second casing hanger 122. As shown in FIGS. 14 and 15, when properly assembled together, the tubing hanger 200 and the control line bushing 206 support continuous control lines 210 (e.g., extend from the tubing hanger 200, through the control line bushing 206, and through the continuous control line ports 108 in the BOP adapter 100).

Further, at some later time, a fluid may be applied via a third pressure port 226 (of the pressure ports 106 of FIG. 5) to drive the tapered push ring 214 away from the lock ring 216, which causes the lock ring 216 to collapse and disengage from the corresponding recess 218. In this way, the tubing hanger running tool 208 may be disengaged from the BOP adapter 100. Then, the tubing hanger running tool 208 may be separated from the control line bushing 206 (e.g., via rotation; threaded interface) and may be lifted to be withdrawn.

As shown in FIGS. 16-18, the BOP adapter 100 and the BOP stack 102 (see FIG. 15) may be removed from the hangers 82, 122, and 200. Then, valves 230, control line ports 232 (e.g., to enable connection to the control lines 210), and a seal flange 234 may be coupled to the wellhead 12 (e.g., to the second casing hanger 122 of the wellhead 12).

While the disclosure 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 invention as defined by the following appended claims. For example, while the illustrated embodiments show a hanger and a housing of a wellhead, it should be understood that the systems and methods may be adapted to for use with any of a variety of other annular structures. Additionally, any features shown or described with reference to FIGS. 1-18 may be combined in any suitable manner. It should be appreciated that certain components of the wellhead are labeled throughout FIGS. 1-18 even if not described with respect to a particular figure in order to provide context and reference to other portions of the disclosure.

The techniques presented and claimed herein are referenced and applied to material objects and concrete examples of a practical nature that demonstrably improve the present technical field and, as such, are not abstract, intangible or purely theoretical. Further, if any claims appended to the end of this specification contain one or more elements designated as “means for [perform]ing [a function] . . . ” or “step for [perform]ing [a function] . . . ”, it is intended that such elements are to be interpreted under 35 U.S.C. 112(f). However, for any claims containing elements designated in any other manner, it is intended that such elements are not to be interpreted under 35 U.S.C. 112(f).

Claims

1. A wellhead system, comprising:

a first casing hanger configured to support a first casing;

a second casing hanger configured to support a second casing within the first casing; and

a seal assembly configured to provide an annular seal between the first casing hanger and the second casing hanger, wherein the seal assembly is configured to move between a first position in which the seal assembly enables a flow of fluid across the second casing hanger and a second position in which the seal assembly blocks the flow of fluid across the second casing hanger.

2. The wellhead system of claim 1, wherein the second casing hanger and the seal assembly are coupled to one another and run together as a hanger assembly.

3. The wellhead system of claim 1, wherein the seal assembly is positioned between the first casing hanger and the second casing hanger during a cementing operation to cement the second casing in a wellbore.

4. The wellhead system of claim 3, comprising a blowout preventer adapter that is positioned to circumferentially surround the first casing hanger and the second casing hanger during the cementing operation.

5. The wellhead system of claim 1, comprising a running tool configured to drive a push ring that contacts the seal assembly to move the seal assembly between the first position and the second position.

6. The wellhead system of claim 1, wherein, in the first position, the seal assembly enables the flow of fluid across the second casing hanger via a flow path with portions in the first casing hanger, in the second casing hanger, between an outer sleeve of a running tool and a blowout preventer adapter, and in the running tool.

7. The wellhead system of claim 1, comprising a tubing hanger, a tubing hanger seal assembly, and a control line bushing that are configured to be coupled to one another and run together into the second casing hanger.

8. The wellhead system of claim 7, wherein the tubing hanger and the control line bushing are configured to support continuous control lines.

9. The wellhead system of claim 1, comprising a diverter assembly configured to couple to a conductor that surrounds the first casing and the second casing in a wellbore, wherein the diverter assembly comprises one or more segments, one or more retaining screws that are configured to drive the one or more segments to engage the conductor, and one or more retracting screws that are configured to drive the one or more segments to disengage from the conductor.

10. A wellhead system, comprising:

a casing hanger comprising a flow path and configured to support a casing; and

a seal assembly configured to provide an annular seal between the casing hanger and an additional annular structure, wherein the seal assembly is configured to move between a first position in which the seal assembly enables a flow of fluid across the casing hanger via the flow path and a second position in which the seal assembly blocks the flow of fluid across the casing hanger via the flow path.

11. The wellhead system of claim 10, wherein the additional annular structure comprises an additional casing hanger configured to support an additional casing.

12. The wellhead system of claim 10, wherein the casing hanger and the seal assembly are coupled to one another and run together as a hanger assembly.

13. The wellhead system of claim 10, wherein the seal assembly is positioned between the casing hanger and the additional annular structure during a cementing operation to cement the casing in a wellbore.

14. The wellhead system of claim 13, comprising a blowout preventer adapter that is positioned to circumferentially surround the casing hanger and the additional annular structure during the cementing operation.

15. The wellhead system of claim 10, comprising a running tool configured to drive a push ring that contacts the seal assembly to move the seal assembly between the first position and the second position.

16. The wellhead system of claim 10, wherein the additional annular structure comprises an additional flow path, wherein, in the first position, the seal assembly enables the flow of fluid across the casing hanger via the additional flow path, and wherein, in the second position, the seal assembly blocks the flow of fluid across the casing hanger via the additional flow path.

17. The wellhead system of claim 10, comprising a tubing hanger, a tubing hanger seal assembly, and a control line bushing that are configured to be coupled to one another and run together into the casing hanger.

18. The wellhead system of claim 17, wherein the tubing hanger and the control line bushing are configured to support continuous control lines.

19. The wellhead system of claim 10, comprising a diverter assembly configured to couple to a conductor that surrounds the casing in a wellbore, wherein the diverter assembly comprises one or more segments, one or more retaining screws that are configured to drive the one or more segments to engage the conductor, and one or more retracting screws that are configured to drive the one or more segments to disengage from the conductor.

20. A method of operating a wellhead system, the method comprising:

running a hanger and a seal assembly within an additional hanger;

performing cementing operations while the seal assembly is in a first axial position to enable a flow of fluid across the seal assembly via a passage formed through the hanger; and

after the cementing operations, moving the seal assembly to a second axial position to block the flow of fluid across the seal assembly and to seal an annular space between the hanger and the additional hanger with the seal assembly.