Patent Application
20210087899
The present disclosure relates generally to subsea equipment systems and, more particularly, to alignment devices used to properly align a first subsea tubular member to a second subsea tubular member.
Conventional subsea wellhead systems include a wellhead housing mounted on the upper end of a subsurface casing string extending into the well bore. During a drilling procedure, a drilling riser and BOP are installed above a wellhead housing (casing head) to provide pressure control as casing is installed, with each casing string having a casing hanger on its upper end for landing on a shoulder within the wellhead housing. A tubing string is then installed through the well bore. A tubing hanger connectable to the upper end of the tubing string is supported within the wellhead housing above the casing hanger for suspending the tubing string within the casing string. Upon completion of this process, the BOP is replaced by a Christmas tree installed above the wellhead housing, with the tree having a valve to enable the oil or gas to be produced and directed into flow lines for transportation to a desired facility.
The tubing hanger contains numerous bores and couplings, which require precise alignment with corresponding portions of the tree. Conventionally, there are two ways to achieve orientation of a tree relative to a tubing hanger. The first uses a tubing spool assembly, which latches to the wellhead and provides landing and orientation features. The tubing spool is very expensive, however, and adds height to the overall stack-up. Additionally, the tubing spool is so heavy that few work class vessels can install it, and it frequently requires installation by expensive drilling vessels. Furthermore, the drilling riser must be removed to install the tubing spool.
The second method of orienting a tree relative to a tubing hanger involves the use of a blowout preventer (“BOP”) stack hydraulic pin and orientation adapter joint. This method requires detailed knowledge of the particular BOP stack in order to accurately install a hydraulically actuated pin, which protrudes into the BOP stack bore. An orientation helix is attached above the tubing hanger running tool, and, as the tubing hanger lands, the helix engages the hydraulic pin and orientates the tubing bores to a defined direction. This method requires accurate drawings of the BOP stack elevations and spacing between the main bore and the outlet flanges, which may require hours of surveying and multiple trips to make measurements. Room for error exists with this method, particularly in older rigs. Thus, this method requires significant upfront planning. Additionally, setting the lockdown sleeve in the wellhead generally requires a rig because the BOP must remain in place as a reference point for orientation of the tubing hanger and corresponding lockdown sleeve.
For a more complete understanding of the present disclosure and its features and advantages, reference is now made to the following description, taken in conjunction with the accompanying drawings, in which:
Illustrative embodiments of the present disclosure are described in detail herein. In the interest of clarity, not all features of an actual implementation are described in this specification. It will of course be appreciated that in the development of any such actual embodiment, numerous implementation specific decisions must be made to achieve developers' specific goals, such as compliance with system related and business related constraints, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of the present disclosure. Furthermore, in no way should the following examples be read to limit, or define, the scope of the disclosure.
Certain embodiments according to the present disclosure may be directed to an alignment apparatus for coupling subsea tubular members together. The apparatus may be used to properly orient and/or provide communication between a first subsea tubular member that is being landed on a second subsea tubular member. For example, the first subsea tubular member may include a tubular housing (e.g., a tree, spool, or flowline connection body) that is being landed on a wellhead relative to a tubing hanger that is set in the wellhead. The alignment apparatus disclosed herein may be used to align any desired combinations of subsea tubular members including, but not limited to, a horizontal tree, a vertical tree, a tubing head spool, a flowline connection body, a tubing hanger, a blowout preventer (BOP), a casing hanger, a running tool (e.g., tubing hanger running tool, casing hanger running tool, BOP running tool, tree running tool, etc.), a retrieving tool, a test tool, a subsea wellhead, a riser, a connector, a tubing string, a control pod, and other subsea equipment. While coupling the subsea tubular members to each other, the alignment apparatus may facilitate coupling of one or more fluid (e.g., hydraulic), electric, or fiber optic lines of the first subsea tubular member with one or more fluid, electric, or fiber optic lines of the second subsea tubular member regardless of a relative orientation of the first subsea tubular member to the second subsea tubular member.
In the following discussion, the term “tree” will be used to refer to any type of component that is landed on a wellhead, has one or more flowlines extending therethrough, and has one or more communication flow paths (e.g., electric, fiber optic, or fluidic) for communicating with communication flow paths in the associated tubing hanger. The term “tree” will be used throughout this application to refer to a tubular housing, which may include any one of a tree body, a spool, or a flowline connection body. The term “tree” refers to a subsea tree and may be one of several different types of subsea tubular members that may be coupled with another subsea tubular member via the disclosed alignment apparatus.
The alignment apparatus may be used properly couple or orient certain features of a first subsea tubular member with corresponding features on a second subsea tubular member. As an example, in subsea wellhead systems, a tree (e.g., a tree body, spool, or flowline connection body) that is positioned on the wellhead must be properly oriented with respect to the tubing hanger that is set in the wellhead. This is because there are a number of couplings or stabs that have to be made up between the tubing string and the tree so as to allow electric, hydraulic, and/or fiber optic signals or power to be communicated from the tree to the tubing hanger and various downhole components. Existing methods for orienting a tree relative to a tubing hanger in the wellhead involve the use of either an expensive tubing spool or a BOP stack hydraulic pin and orientation adapter joint, which can be difficult to properly place on the wellhead and expensive to adjust if improperly placed.
The present disclosure is directed to systems and methods for functionally coupling a first subsea tubular member to a second subsea tubular member without regard to the orientation of the subsea tubular members with respect to each other. An apparatus for coupling subsea tubular members may include an alignment sub and a corresponding alignment member. The alignment sub includes: a generally cylindrical body having one or more fluid, electric, or fiber optic lines extending therethrough, one or more couplings coupled to at least one end of the alignment sub, and an orientation profile disposed on a surface of the alignment sub. The alignment member has a profile designed to interface with the orientation profile of the alignment sub. One of the alignment sub and the alignment member remains stationary while the other rotates relative to the stationary structure. The present disclosure describes other types of alignment apparatuses as well.
The alignment apparatus may include any subsea tubular alignment device used for landing and communicatively coupling one subsea tubular member with respect to another subsea tubular member regardless of the orientation of the one subsea tubular member.
As an example, the subsea tubular alignment device may be used for landing a tubing hanger in a wellhead without regard to its orientation and landing a tree at any orientation desired by the operator. The tree can land at any orientation and the systems and methods according to the present invention can be used to orientate the various couplings (e.g., the electric, fluidic, and/or fiber optic couplings) relative to the tubing hanger while landing the tree on the wellhead. This is accomplished without the use of either a separate tubing spool or a BOP stack with an orientation pin. This can save the operator a large amount of money (on the order of millions of dollars) since no additional tubing spool is necessary to perform the orientation. In addition, the disclosed systems and methods will save the operator money because they avoid the possibility of costly remediation associated with an improperly positioned BOP. The alignment device is able to align the tree to the tubing hanger independent of the original tree orientation at the beginning of the landing process. Essentially, the disclosed alignment devices enable the tree to function as a “self-aligning tree” or “self-orienting tree.” The tree can be landed in any orientation desired by the operator. The present invention thus provides a self-alignment and orientation of couplings or stabs that have to be made up between the tubing string and the tree so as to allow electric, fluidic (e.g., hydraulic), and/or fiber optic signals to be communicated from the tree to the tubing hanger and various downhole components. The self-aligning subsea tubular alignment device may reduce the number of trips into a subsea well between drilling and completion of the subsea well. For example, the self-aligning subsea tubular alignment device may eliminate three to six additional trips that might otherwise be needed between drilling and completion of a subsea well using existing tree landing systems. Using the self-orienting subsea tubular alignment device, a system (e.g., tubular housing and alignment device) may be landed in a subsea component (e.g., wellhead), picked up, rotated, and re-stabbed/set back down into the wellhead multiple times, thus enabling easy connection and reconnection of subsea components at different times throughout the life of a subsea well.
Turning now to the drawings,
In the illustrated embodiment, the first subsea tubular member 14 may be a tubing hanger, and the second subsea tubular member 18 may be a tree (which may include a horizontal or vertical tree body, a spool, or a flowline connection body). However, as mentioned above, it should be understood that the disclosed alignment device 16 may be used to couple other types of subsea tubular members including, but not limited to, a blowout preventer (BOP), a casing hanger, a running tool, a retrieving tool, a test tool, a subsea wellhead, a riser, a connector, a tubing string, a control pod, and other subsea equipment.
The system 10 depicted in
As shown, the alignment device 16 may connect the second subsea tubular member (e.g., tree) 18 to the first subsea tubular member (e.g., tubing hanger) 14. In other embodiments, a tubing hanger alignment device may include a plug that is removably placed within the tubing hanger at one or more times throughout a completion process, as described below. In such cases, the tubing hanger may be connected to and sealed against the tree via an isolation sleeve that is integral with the tree.
The tubing hanger (14) may be landed in and sealed against a bore 22 of the wellhead 12, as shown. The tubing hanger (14) may suspend a tubing string 24 into and through the wellhead 12. Likewise, one or more casing hangers (e.g., inner casing hanger 26A and outer casing hanger 26B) may be held within and sealed against the bore 22 of the wellhead 12 and used to suspend corresponding casing strings (e.g., inner casing string 28A and outer casing string 28B) through the wellhead 12.
In the illustrated embodiment, the alignment device 16 may include one or more communication lines (e.g., fluid lines, electrical lines, and/or fiber optic cables) 30 disposed therethrough and used to communicatively couple the second subsea tubular member (e.g., tree) 18 to the first subsea tubular member (e.g., tubing hanger) 14. The first subsea tubular member (e.g., tubing hanger) 14 may include couplings or stabs 32 located at an end (e.g., the top) of the first subsea tubular member (e.g., tubing hanger) 14 in a specific orientation with respect to a longitudinal axis 34. The alignment device 16 is configured to facilitate a mating connection that communicatively couples the second subsea tubular member (e.g., tree) 18 to the couplings/stabs 32 on the first subsea tubular member (e.g., tubing hanger) 14 as the second subsea tubular member (e.g., tree) 18 is landed onto the wellhead 12, regardless of the orientation in which the second subsea tubular member (e.g., tree) 18 is initially positioned during the landing process.
Different arrangements of an alignment device 16 will now be disclosed in the following sections of this description. The alignment device may utilize one or more of a rotatable profile alignment mechanism, a coiled conduit alignment mechanism, a multi-start alignment thread mechanism, a helical slot alignment mechanism, a torsional spring alignment mechanism, or a plug-based alignment mechanism.
Rotatable Profile Alignment Mechanism
An alignment device 16 having a rotatable profile alignment mechanism will be described with reference to
The alignment device 16 of
The alignment sub 54 may include a generally cylindrical body 58 having one or more fluid, electric, or fiber optic lines 30 extending therethrough, and one or more couplings 118 coupled to at least one end of the alignment sub 54. For example, the alignment sub 54 may include couplings 118 at both a lower end 60 and an upper end 62 thereof, as shown. In other embodiments (e.g., as shown in
The alignment member 56 has a profile 66 designed to interface with the orientation profile 64 of the alignment sub 54. The profile 66 may be complementary to the orientation profile 64. The profile 66 is illustrated schematically in
The alignment sub 54 and corresponding alignment member 56 are designed such that one of the two components remains stationary while the other rotates relative to the stationary structure. For example, as shown by an arrow 68 in
One or more components of the alignment device 16 may be coupled to the first subsea tubular member 14 or the second subsea tubular member 18 throughout operation of the alignment device 16. For example, the alignment sub 54 may be coupled to the second subsea tubular member 18 while the corresponding alignment member 56 may be coupled to the first subsea tubular member 14 throughout the alignment operation. In other embodiments, this arrangement may be reversed such that the alignment sub 54 is coupled to the first subsea tubular member 14 while the corresponding alignment member 56 is coupled to the second subsea tubular member 18. In some embodiments, the alignment sub 54 and the corresponding alignment member 56 may each comprise components that are mounted (directly or indirectly) to the subsea tubular members 14, 18.
In other embodiments, one or both of the alignment sub 54 and the corresponding alignment member 56 may comprise at least one component that is integral with one of the subsea tubular members 14, 18. For example, the alignment sub 54 may include a rotating sub rotatably coupled directly to a portion of one of the subsea tubular members (e.g., second subsea tubular member 18), and the alignment member 56 may remain stationary. In this instance, the subsea tubular member 18 may include a body and a generally cylindrical stab portion coupled to the body, wherein the rotating alignment sub 54 is disposed around and rotatably coupled to the stab portion of the subsea tubular member 18. The corresponding alignment member 56 may be an orientation sub that is mounted to or integral with the other subsea tubular member (e.g., 14).
As another example, the alignment member 56 may be integral with one of the subsea tubular members (e.g., first subsea tubular member 14), such that the profile 66 is formed on a surface of the subsea tubular member. The alignment member 56 may be stationary while the alignment sub 54 is a rotating sub having the orientation profile 64 that rotates relative to the alignment member 56. The alignment sub 54 may be rotatably coupled to a production stab sub mounted to the other subsea tubular member (e.g., 18), rotatably coupled to a generally cylindrical body integral with a body of the subsea tubular member 18, and/or rotatably coupled to a generally cylindrical body extending from a body of the subsea tubular member 18.
In some embodiments, the helical profile 78 may be a helical groove that is bounded on both the upper and lower sides thereof along the entire length of the groove or most of the length of the groove, as shown in
In some embodiments, the alignment device 16 may include multiple helical grooves 78 (also referred to as “multi-start alignment threads”) in the alignment sub 54. These multiple helical grooves 78 may be separated from each other about the circumference of the alignment sub 54 along their entire lengths. In such embodiments, the corresponding alignment member 56 may include multiple keys 80 to be received in the corresponding helical grooves 78. An example of an alignment sub 54 having multiple helical grooves 78 formed therein is provided in the embodiment of
In other embodiments, the helical profile 78 may be a helical recess bounded only on one side (e.g., upper side in the illustrated configuration). An example of this is shown in
In some embodiments, the helical profile 78 may extend axially along the length of the alignment sub 54 as it rotates in one direction about the axis of the alignment sub 54, as shown in
As illustrated, the helical profiles 78 of
As discussed at length above with reference to
In other embodiments, the helical profile 78 may be bounded only on one side (e.g., lower side in the illustrated configuration). In this embodiment, the helical profile 78 can interact directly with a stationary key 80 (not spring-loaded) without requiring any rotation of the alignment sub 54/alignment member 56 with respect to each other until the key 80 contacts the helical profile 78. In such embodiments, the helical profile 78 may be limited to one full rotation about the axis of the alignment member 56.
In some embodiments, the helical profile 78 may extend axially along the length of the alignment member 56 as it rotates in one direction about the axis of the alignment member 56, as shown in
As illustrated, the helical profiles 78 of
In the alignment devices 16 of
As shown in
In some embodiments, the alignment device 16 may include multiple helical protrusions 96 and grooves 97 in the alignment sub 54/alignment member 56. The multiple helical protrusions 96 may be separated from each other about the circumference of the alignment sub 54 or alignment member 56 along their entire lengths. The corresponding helical grooves 97 may be separated from each other about the circumference of the alignment sub 54 or alignment member 56 along their entire lengths.
The helical groove 97 may be bounded on both the upper and lower sides thereof along the entire length of the groove or most of the length of the groove, as shown in
In other embodiments, the helical groove 97 may be bounded on just one side thereof (e.g., lower side in
As shown in
More detailed embodiments of the disclosed alignment device 16 will now be provided. These embodiments may include similar features to those described above with reference to
Coiled Conduit Alignment Mechanism
An alignment device 16 having a coiled conduit mechanism in shown in
The tubing hanger alignment device 16 of
The mule shoe sub 110 is able to rotate relative to the tree body 18 and the production stab sub 114. A mule shoe profile drives the mule shoe sub 110 to rotate as it is lowered through the wellhead 112. The mule shoe profile 122 is illustrated in
As shown in
The production stab sub 114 may be mounted to the tree body 18. The mule shoe sub 110 is disposed around an outer circumference of the production stab sub 114. The production stab sub 114 may retain the mule shoe sub 110 thereon while allowing the mule shoe sub 110 rotational freedom about the production stab sub 114. As such, the production stab sub 114 rotationally couples the mule shoe sub 110 to the tree 18. The mule shoe sub 110 is able to rotate relative to the production stab sub 114 and the tree 18 as the tree 18 is being lowered into the wellhead 12.
The coiled fluid tubing (i.e., conduit) (116) provides a communication path for fluid (e.g., hydraulic fluid) being communicated from fluid ports in the tree 18 to corresponding fluid ports in the mule shoe sub 110 and ultimately the tubing hanger 14. The coiled arrangement of the fluid tubing (116) allows the conduit to flex as the mule shoe sub 110 rotates in either direction to align the couplings 118 with those of the tubing hanger 14 while the tree 18 is being lowered.
The electrical conduits (116) provide a communication path for electrical and/or fiber optic signals being communicated from cables in the tree 18 to corresponding cables in the mule shoe sub 110 and ultimately the tubing hanger 14. The coiled arrangement of the electrical conduits (116) allows the conduit to flex as the mule shoe sub 110 rotates in either direction to align the couplings 118 with those of the tubing hanger 14 while the tree 18 is being lowered.
A general description of a method for operating the tubing hanger alignment device 16 of
The method may also include installing the mule shoe sub 110 onto the production stab sub 114. The mule shoe sub 110 may be disposed around the outside circumference of the generally cylindrical production stab sub 114, and the mule shoe sub 110 may be rotatably coupled to the production stab sub 114. The mule shoe sub 110, for example, may be connected to the outside of the production stab sub 114 via a bearing interface that enables free rotation of the mule shoe sub 110 around the production stab sub 114 while these components are lowered through the wellhead 12.
The one or more lengths of fluid tubing and/or electrical conduits 116 may be connected between the bottom of the tree body 18 and the top of the mule shoe sub 110. The electrical conduits and/or fluid tubing 116 may be coiled around the outer diameter of the production stab sub 114 in a space located longitudinally between the tree 18 and the mule shoe sub 110. In some embodiments, the conduits 116 may be extended upward from the connected cables and/or ports 120 in the mule shoe sub 110, coiled one or more times each around the production stab sub 114, and connected to contacts 132 at a lower end of the tree body 18. In other embodiments, the conduits 116 may be extended from an interface at the lower end of the tree body 18, coiled one or more times each around the production stab sub 114, and connected to cables and/or ports 120 in the mule shoe sub 110 via contacts on the mule shoe sub 110. In some embodiments, the contacts may be located at an upper end of the mule shoe sub 110, as shown. However, other locations may be possible in other embodiments.
During assembly of the tubing hanger assembly, the alignment key 112 may be installed along an inner diameter of the tubing hanger 14. The alignment key 112 may be installed securely within a recess formed in the tubing hanger 14 along the inner diameter. As shown, the alignment key 112 is disposed in a particular position along the circumference of the inner surface of the tubing hanger 14. The alignment key 112 does not extend about the entire circumference of the inner surface of the tubing hanger 14. The alignment key 112 may be installed via a fastener such as a bolt or screw into the recess of the tubing hanger 14. The alignment key 112 may have a width that is sized to be received into the vertical slot 130 of the mule shoe profile 122 associated with the mule shoe sub 110. In other embodiments, the alignment key 112 may be formed entirely integral with the tubing hanger 14, such that the tubing hanger 14 is initially manufactured with the alignment key 112 as part of the inner diameter of the tubing hanger 14.
Upon assembly of the above components, the tubing hanger 14 may be run into the wellhead 12 in any orientation, locked into place, and sealed within the wellhead 12. The tree assembly having the tree body 18 and the tubing hanger alignment device 16 (i.e., production stab sub 114, mule shoe sub 110, and coiled conduits 116) is then run and oriented into a desired location in the wellhead 12 prior to landing within the wellhead 12.
While the tree 18 is landed from an initial position in the wellhead 12 to its final connected position, the mule shoe sub 110 may engage the alignment key 112 so as to orientate the couplings 32 and 118 associated with the tubing hanger 14 and the mule shoe sub 110, respectively. The mule shoe profile 122 on the outer edge of the mule shoe sub 110 may directly engage the alignment key 112 on the tubing hanger 14. Lowering the tree 18 further causes the mule shoe sub 110 to rotate about the production stab sub 114 and align with the tubing hanger 14. That is, the stationary alignment key 112 forces the mule shoe sub 110 to rotate in one direction or the other (depending on the direction of the slope of the mule shoe profile 122 at the point of initial contact with the alignment key 112) as the tree 18 is lowered until the alignment key 112 is received into the alignment slot 130 of the mule shoe profile 122. At this point, the mule shoe sub 110 will be in a proper alignment with the tubing hanger 14.
The tree 18 may then be landed and locked to the wellhead 12. All couplings between the mule shoe sub 110 and the tubing hanger 14 will be engaged at this point. The fluidic, electric, and/or fiber optic couplings between the tree 18 and the tubing hanger 14 will then be tested to ensure a proper connection has been made.
The tubing hanger alignment device 16 of
As shown in
The rotating sub 134 is able to rotate relative to the tree body 18 and the production stab sub 114. The mule shoe profile 122A may drive the rotating sub 134 with the alignment key 112A to rotate against the mule shoe sub 110A until the alignment key 112A is set into the alignment slot 130A. At this point, the rotating sub 134 will be properly oriented relative to the tubing hanger 14 so as to make the desired mating connections at the interface of couplings 118 and 32. As such, rotation of the rotating sub 134 stops when the couplings 118 of the rotating sub 134 are aligned to the couplings 32 on the tubing hanger 14.
In some embodiments, the alignment key 112A may be specially shaped to interact with the mule shoe sub 110A. For example, as shown in
The production stab sub 114 may be mounted to the tree body 18. The rotating sub 134 is disposed around an outer circumference of the production stab sub 114. The production stab sub 114 may retain the rotating sub 134 thereon while allowing the rotating sub 134 rotational freedom about the production stab sub 114. As such, the production stab sub 114 rotationally couples the rotating sub 134 and alignment key 112A to the tree 18. The rotating sub 134 is able to rotate relative to the production stab sub 114 and the tree 18 as the tree 18 is being lowered into the wellhead 12.
The coiled fluid tubing (i.e., conduit) (116) provides a communication path for fluid (e.g., hydraulic fluid) being communicated from fluid ports in the tree 18 to corresponding fluid ports in the rotating sub 134 and ultimately the tubing hanger 14. The coiled arrangement of the fluid tubing (116) allows the conduit to flex as the rotating sub 134 rotates in either direction to align the couplings 118 with those of the tubing hanger 14 while the tree 18 is being lowered.
The coiled electrical conduits (116) provide a communication path for electrical and/or fiber optic signals being communicated from cables in the tree 18 to corresponding cables in the rotating sub 134 and ultimately the tubing hanger 14. The coiled arrangement of the electrical conduits (116) allows the conduit to flex as the rotating sub 134 rotates in either direction to align the couplings 118 with those of the tubing hanger 14 while the tree 18 is being lowered.
In some embodiments, the production system of
As shown, the interface between the production stab sub 114 and the tubing hanger 14 (upon landing of production stab sub 114) provides a sealed annular gallery 142. The annular gallery 142 may enable fluid to flow from the annulus flow path 138 of the tubing hanger 14 into the one or more flow paths 136 extending through the production stab sub 114, regardless of the orientation of the tree 18 (and attached production stab sub 114) with respect to the tubing hanger 14. The production stab sub 114 may include annular seals 142A and 142B that define the upper and lower bounds of the annular fluid gallery 142.
In some embodiments, the interface between the production stab sub 114 and the tree body 18 may include a sealed gallery 144 as well. This sealed gallery 144 may enable fluid to flow from the one or more flow paths 136 extending through the production stab sub 114 into the annulus flow path 140 of the tree 18, regardless of the orientation of the production stab sub 114 when it is initially attached to the tree 18. The production stab sub 114 may include annular seals 144A and 144B that define the upper and lower bounds of the annular fluid gallery 144. Such a sealed gallery 144 may be similarly implemented in the alignment device 16 described above with reference to
In embodiments where the one or more flow paths 136 through the production stab sub 114 are used to route annulus fluid therethrough, the annular seals 142A, 142B, 144A, and 144B for one or more flow paths 136 may act as a second barrier between the annulus fluid and the environment outside the subsea wellhead 12. Specifically, a gasket 143 between the connector of the subsea tree 18 and the wellhead 12 may form a primary barrier between the annulus fluid and the outside environment while the annular seals 142A, 142B, 144A, and 144B may form a secondary barrier between the annulus fluid and the outside environment.
This may be beneficial as regulations for dual-barrier arrangements of annulus flow paths through subsea wellheads become more common.
A general description of a method for operating the tubing hanger alignment device 16 of
In some embodiments, initial assembly of the rotating sub 134 may include installing the alignment key 112A along an outer diameter of the rotating sub 134. The alignment key 112A may be installed securely within a recess formed in the rotating sub 134 along the outer diameter. The alignment key 112A may extend outward from the outer edge of the rotating sub 134, though, for interfacing with the mule shoe sub 110A. As shown, the alignment key 112A is disposed in a particular position along the circumference of the outer surface of the rotating sub 134. The alignment key 112A does not extend about the entire circumference of the outer surface of the rotating sub 134. The alignment key 112A may be installed via a fastener such as a bolt or screw into the recess of the rotating sub 134. In other embodiments, the alignment key 112A may be formed entirely integral with the rotating sub 134 such that the alignment key 112A is part of the outside surface of the rotating sub 134. The alignment key 112A may have a width that is sized to be received into the vertical slot 130A of the mule shoe profile 122A associated with the mule shoe sub 110A.
The method may include installing the rotating sub 134 with the alignment key 112A onto the production stab sub 114. The rotating sub 134 having the alignment key 112A may be disposed around the outside circumference of the generally cylindrical production stab sub 114, and the rotating sub 134 may be rotatably coupled to the production stab sub 114. The rotating sub 134, for example, may be connected to the outside of the production stab sub 114 via an interface 133 that enables free rotation of the rotating sub 134 around the production stab sub 114 while these components are lowered through the wellhead 12. In some embodiments, the interface 133 may include a bearing interface.
The one or more lengths of fluid and/or electrical conduits 116 may be connected between the bottom of the tree body 18 and the top of the rotating sub 134. The electrical conduits and/or fluid tubing (i.e., conduits) 116 may be coiled around the outer diameter of the production stab sub 114 in a space located longitudinally between the tree 18 and the rotating sub 134. In some embodiments, the conduits 116 may be extended upward from the connected cables and/or ports 120 in the rotating sub 134, coiled one or more times each around the production stab sub 114, and connected to contacts 132 at a lower end of the tree body 18. In other embodiments, the conduits 116 may be extended from an interface at the lower end of the tree body 18, coiled one or more times each around the production stab sub 114, and connected to cables and/or ports 120 in the rotating sub 134 via contacts at an upper end of the rotating sub 134. In some embodiments, the contacts may be located at an upper end of the rotating sub 134, as shown. However, other locations may be possible in other embodiments.
During assembly of the tubing hanger assembly, the mule shoe sub 110A having the mule shoe profile 122A is installed along an inner diameter of the tubing hanger 14. The mule shoe sub 110A may be installed via threads, a lock ring, or any other known method. The mule shoe sub 110A may be connected to the tubing hanger 14 in a manner that does not allow rotation of the mule shoe sub 110A relative to the tubing hanger 14. In other embodiments, the mule shoe sub 110A may be formed integral with the tubing hanger 14. The mule shoe sub 110A is coupled to (or integral with) the tubing hanger 14 in a particular orientation with respect to the couplings 32 associated with the tubing hanger 14.
Upon assembly of the above components, the tubing hanger 14 (with the mule shoe sub 110A) may be run into the wellhead 12 in any orientation, locked into place, and sealed within the wellhead 12. The tree assembly having the tree body 18 and the tubing hanger alignment device 16 (i.e., production stab sub 114, rotating sub 134, and coiled conduits 116) is then run and oriented into a desired location in the wellhead 12 prior to landing within the wellhead 12.
While the tree 18 is landed from an initial position in the wellhead 12 to its final connected position, the alignment key 112A on the rotating sub 134 may engage the mule shoe sub 110A so as to orientate the couplings 32 and 118 associated with the tubing hanger 14 and the rotating sub 134, respectively. The alignment key 112A on the outer edge of the rotating sub 134 may directly engage the mule shoe profile 122A on the mule shoe sub 110A attached to the tubing hanger 14. Lowering the tree 18 further causes the rotating sub 134 to rotate about the production stab sub 114 and align with the tubing hanger 14. That is, the stationary mule shoe sub 110A forces the alignment key 112A and rotating sub 134 to rotate in one direction or the other (depending on the direction of the slope of the mule shoe profile 122A at the point of initial contact with the alignment key 112A) as the tree 18 is lowered until the alignment key 112A is received into the alignment slot 130A of the mule shoe profile 122A. At this point, the rotating sub 134 will be in a proper alignment with the tubing hanger 14.
The tree 18 may then be landed and locked to the wellhead 12. All couplings between the rotating sub 134 and the tubing hanger 14 will be engaged at this point. The fluidic, electric, and/or fiber optic couplings between the tree 18 and the tubing hanger 14 will then be tested to ensure a proper connection has been made. At this point, the fluid flow path(s) 136 through the production stab sub 114 may also be sealingly connected between the annulus flow path 138 of the tubing hanger 14 and the annulus flow path 140 of the tree 18.
As mentioned above, landing and locking the tree 18 to the wellhead 12 may fully engage the couplings 118 and 32 between the rotating sub 134 and the tubing hanger 14. This may include connecting a large number of couplings 118/32 between these two members. For example, in some embodiments twelve hydraulic couplings, two electrical couplings, and one fiber optic coupling on the rotating sub 134 may be connected to the tubing hanger 14 simultaneously. At the same time, a lower end of the production stab sub 114 may also be fully connected to the tubing hanger 14. To connect the production stab sub 114 along with the many couplings 118 of the rotating sub 134 to the tubing hanger 14 at one time takes a large amount of downward force. As discussed above, the system may include an interface 133 coupled to the production stab sub 114 above the alignment device 134. In some embodiments, the interface 133 may include a C-shaped ring component that acts as a load ring during the final installation of the tree 18 onto the tubing hanger 14. When all the couplings 118 are being initially received into corresponding couplings or stabs 32, the production stab sub 114 may be lowered into a pocket in the tubing hanger 14. At that point, the alignment device 134 will not fully engage the couplings 118 with the corresponding couplings 32 until the load ring (interface 133) lands on the alignment device 134 and transfers the load of the tree 18 onto the couplings. This loading provided through the interface 133 allows the couplings 118 and 32 to fully mate at the same time the production stab sub is connected to the tubing hanger 14. The load ring (interface 133) may also pre-load the couplings 118 and 32 to prevent any movement between their connected communication paths as hydraulic pressure is applied.
Certain details regarding the fluid/electric conduits 116 in the embodiments of
The coiled conduits 116 of
As the rotatable alignment sub rotates in one direction, the coils in the coiled conduit(s) 116 may expand or separate with respect to each other. As the rotatable alignment sub rotates in the opposite direction, the coils may tighten or compress with respect to each other. In embodiments where the rotatable alignment sub is “floating,” as the rotatable alignment sub moves vertically downward with respect to the production stab sub 114, the coils in the coiled conduit(s) 116 may expand or separate with respect to each other. Similarly, as the rotatable alignment sub moves vertically upward with respect to the production stab sub 114, the coils in the coiled conduit(s) 116 may tighten or compress with respect to each other. The coiled conduits 116 are coiled in a manner to prevent additional stress or loading on the connections to the corresponding subsea components (e.g., tree body 18 and tubing hanger 14). The number of wraps and the diameter of the coils for each coiled conduit 116 may be engineered, selected, and/or calculated based on the relative cross-sectional diameters and/or wall thicknesses of the conduits 116 as well as expected pressures, temperatures, and environments to which the conduits 116 will be exposed. The number of wraps and the diameter of the coils may be designed to minimize or prevent any additional stresses or loading on the connections between the coiled conduits 116 and the corresponding subsea components (e.g., tree body 18 and tubing hanger 14) during installation and rotation of the tubing hanger alignment device 16. The coiled conduits 116 may be protected from clashing, rubbing, or cycling movements due to pressure and temperature changes during production of the well. In some embodiments, coiled conduits 116 having a greater (“thicker”) cross-sectional diameter may be positioned radially inward from coiled conduits 116 having a smaller (“thinner”) cross-sectional diameter. In such instances, the “thicker” coiled conduits 116 may be wrapped more closely around the production stab sub 114 while the “thinner” coiled conduits 116 may be wrapped around the “thicker” coiled conduits 116. This may prevent the different sized coiled conduits 116 from rubbing against each other and causing undesired fatigue on the coiled conduits 116.
The coiled conduits 116 may be constructed from material(s) that are resistant to corrosion and harsh environments of the subsea production system. As shown in
The coiled conduit(s) 116 may include one or more fluid, power, and/or communication lines. The coiled conduit(s) 116 may allow for communication of hydraulic fluid(s), injection fluid(s), and/or annulus fluid(s) therethrough. The coiled conduit(s) 116 may allow for power and/or communication signals (both electrical and fiber optic) to be transferred from the tree body 18 through the coiled conduit(s) 116 and the tubing hanger alignment device 16 and to/through the tubing hanger 14.
The coiled conduit(s) 116 may help provide a bridge for communicating power, communication signals, and/or fluid through the hazardous environment and conditions in the well to the tree body 18. This bridge between the environment and the well condition is constructed entirely from material that meet or exceed the requirements needed to perform in extreme conditions as seen in wells. The bridge includes all metal-to-metal sealing technology throughout the entire system from the inlet to the final outlet (e.g., between the tree body 18 and the production stab sub 114, between the production stab sub 114 and the upper end of the coiled conduits 116, from the lower end of the coiled conduits 116 to the rotatable alignment sub, and from the couplings 118 on the rotatable alignment sub to the couplings or stabs 32 on the tubing hanger 14, and/or any other couplings in the system).
In some embodiments, the rotatable alignment sub (i.e., mule shoe sub 110 in
The coiled conduits 116 may each be configured to flex in response to rotation of the rotatable alignment sub about the production stab sub 114 in either direction (clockwise or counterclockwise) for up to 180 degrees. In other embodiments, the coiled conduits 116 may each be configured to flex in response to rotation of the rotatable alignment sub about the production stab sub 114 in either direction (clockwise or counterclockwise) for up to 360 degrees. The coiled conduits 116 are generally configured to flex in response to whatever number of degrees rotation of the rotatable alignment sub is needed to align the couplings 118 on the rotatable alignment sub with the corresponding couplings 32 of the tubing hanger 14, making the system self-aligning. If upon landing the subsea tree body 18, the tree and/or other subsea field equipment are out of rotational alignment with each other, the tree body 18 may be picked up, rotated to a desired orientation, and set back down. The coiled conduits 116 and rotatable alignment sub may adjust for the difference in rotation and connect the tree body 18 to the tubing hanger 14.
It should be noted that the embodiments of
The disclosed tubing hanger alignment device 16 of
Coiled Conduit Alignment Mechanism with Multi-Start Alignment Threads
Another embodiment of an alignment device 16 having a coiled conduit mechanism is shown in
Similar to the mule shoe sub 110 (110A) of
The alignment sub 612 includes fluid ports and/or electrical cables 120 extending therethrough. The ports and/or cables 120 may be connected to or through the coiled fluid and/or electrical and/or fiber optic conduits 616 at the top of the alignment sub 612 to allow the alignment sub 612 to rotate relative to the body of the tree. Electrical cables and/or fluid ports 120 disposed through the alignment sub 612 may be terminated to a series of electric/fiber contacts and/or fluidic connectors 118 that interface with the tubing hanger at the bottom of the alignment sub 612.
Similar to the embodiments of
The outer timing ring 614 includes one or more key features 626 designed to interact with complementary key features of the tubing hanger (not shown). For example, as shown, the outer timing ring 614 may feature lugs 626 extending in a downward direction from a lower surface of the outer timing ring 614. These lugs 626 are designed to interface with corresponding grooves or slots formed in an upward facing surface of the tubing hanger (not shown) to time the start of alignment rotation so that couplings 118 at the bottom of the alignment sub 612 will be aligned with the corresponding couplings/stabs at the top of the tubing hanger. The lugs 626 may include three lugs, four lugs, or some other number of lugs. The lugs 626 on the outer timing ring 614 may be unevenly spaced from each other around the circumference of the outer timing ring 614, unevenly spaced in a radial direction from a longitudinal axis of the outer timing ring, extending different lengths in the longitudinal direction, having different shapes in a plane perpendicular to the longitudinal axis, or a combination thereof. The corresponding grooves or slots extending into the tubing hanger may be arranged in a similar unevenly positioned, shaped, and/or sized manner. That way, the lugs 626 of the outer timing ring 614 are received into the corresponding grooves or slots of the tubing hanger only when the outer timing ring 614 is in a particular orientation with respect to the tubing hanger about a longitudinal axis.
It should be noted that, in other embodiments, the key features on the outer timing ring and the tubing hanger may be reversed, such that the outer timing ring includes keyed slots or grooves formed therein to be received on upwardly extending lugs of the tubing hanger.
The outer timing ring 614 seats the tubing hanger alignment device 16 in a desired orientation within the tubing hanger, regardless of how the tubing hanger is oriented within the wellhead. Once the outer timing ring 614 is keyed into the tubing hanger, it cannot be rotated with respect to the tubing hanger. The alignment sub 612 then moves downward, rotating with respect to the stationary outer timing ring 614 until it reaches an aligned position relative to the tubing hanger (not shown) for making the desired fluid, electric, and/or fiber optic connections. At this point, the alignment sub 612 will be properly oriented relative to the tubing hanger so as to make the desired mating connections at the interface of couplings 118 and couplings (e.g., 32 of
The production stab sub 610 may be mounted to the tree body (not shown), similar to the production stab sub 114 of
The alignment sub 612 may be equipped with an actuation mechanism 628 used to release the production stab sub 610 from the alignment sub 612 so that the production stab sub 610 can move in a longitudinal direction with respect to the alignment sub 612. The actuation mechanism 628 is designed so that it can only be activated once the alignment sub 612 is in an aligned position with respect to the tubing hanger. In the illustrated embodiment, the actuation mechanism 628 includes one or more actuation buttons 630 and a split ring 632. The split ring 632 is held in position within a circumferential groove formed along a radially inner diameter of the alignment sub 612. The split ring 632 is biased in a radially outward direction so that it retains the alignment sub 612 at a particular longitudinal position relative to the production stab sub 610. Although not shown, the split ring 632 may be coupled to the production stab sub 610 via a shoulder or some other attachment feature. The actuation buttons 630 may extend from a radially outer diameter of the alignment sub 612 to the radially inner diameter of the alignment sub 612 where the split ring 632 is retained. A force applied in a radially inward direction to the one or more buttons 630 presses the buttons 630 into the split ring 632, thereby collapsing the split ring 632 so that the alignment sub 612 is no longer held in a fixed longitudinal position with respect to the production stab sub 610. This enables the production stab sub 610 to move further downward so that the seals 618 at the bottom thereof can be extended to interface with the tubing hanger. It should be noted that other types of actuation mechanisms may be used to selectively allow the production stab sub 610 to move downward and expose the seals 618.
While in the retracted position, gallery seals are not energized, allowing for free rotation of the alignment sub 612 around the production stab sub 610. Once the gallery seals are engaged, they will prevent further rotation such that the tree can be removed and reinstalled in the same orientation.
The coiled fluid tubing (i.e., conduit) (616) provides a communication path for fluid (e.g., hydraulic fluid) being communicated from fluid ports in the tree to corresponding fluid ports in the alignment sub 610 and ultimately the tubing hanger. The coiled arrangement of the fluid tubing (616) allows the conduit to flex as the alignment sub 612 rotates to align the couplings 118 with those of the tubing hanger while the tree is being lowered.
The electrical conduits (616) provide a communication path for electrical and/or fiber optic signals being communicated from cables in the tree to corresponding cables in the alignment sub 612 and ultimately the tubing hanger. The coiled arrangement of the electrical conduits (616) allows the conduit to flex as the alignment sub 612 rotates to align the couplings 118 with those of the tubing hanger while the tree is being lowered.
A general description of a method for operating the tubing hanger alignment device 16 of
Once the outer timing ring 614 is firmly seated within the tubing hanger, further downward force applied to the tree causes the alignment sub 612 to rotate relative to the outer timing ring 614 and the tubing hanger. This is illustrated in
When the outer timing ring 614 reaches the top of the alignment threads 620, the alignment sub 612 and its couplings 118 will be rotationally aligned with the connectors of the tubing hanger, and the pins 622 of the outer timing ring 614 will enter the vertical alignment slots 624. This aligned configuration is shown in
In some embodiments, the alignment sub 612 may be equipped with a final/fine alignment socket 640, and the tubing hanger may be equipped with a corresponding final/fine alignment key. The layout and description of these final/fine alignment features is discussed at length below with reference to final alignment key 232 and final alignment slot 234 of
At this point, further lowering of the tree causes the production stab sub 610 to move downward relative to the alignment sub 612, uncovering the seals 618 at the lower end thereof and engaging gallery seals. The production stab sub 610 will move downward, stabbing into the tubing hanger and activating the seals 618 against the tubing hanger interface. The alignment sub 612 may also be lowered a certain amount to complete the stabbing connections between the couplings 118 and the corresponding connectors of the tubing hanger. This brings the tubing hanger alignment device 16 to the fully landed position within the wellhead, as shown in
The tubing hanger alignment device 16 of
It should be noted that the embodiments of
The disclosed tubing hanger alignment device 16 of
Helical Slot Alignment Mechanism
An alignment device 16 having a helical slot mechanism is shown in
The alignment body 210 may be a single, solid piece that houses standard type (or actuated type) fluidic (e.g., hydraulic), electric, and/or fiber optic couplings 216 that interface with the corresponding couplings/stabs 32 at a top end of the first subsea tubular member (hereinafter referred to as “tubing hanger”) 14. In this embodiment, the alignment body 210 may function as the production stab sub that is coupled directly to the second subsea tubular member (hereinafter referred to as “tree”) 18. In other embodiments, however, a separate annular production stab sub captured within the alignment body 210 may be used.
The alignment body 210 may include a fluidic port (not shown) extending therethrough and routed to a fluid (e.g., hydraulic) gallery 218. The fluid gallery 218 is open to and in fluid communication with a fluid (e.g., hydraulic) port (not shown) formed through the tree 18 as well. The fluid gallery 218 is located in an annular space between the tree body 18 and the alignment body 210, and the fluid gallery 218 extends entirely around the circumference of the alignment body 210. The fluid gallery 218 allows for rotation of the alignment body 210 relative to the tree 18 while maintaining fluid communication between the fluid port in the tree body 18 and the fluid port in the alignment body 210.
The alignment body 210 may include electric and/or fiber optic cables (not shown) extending therethrough and routed to an electrical/fiber optic gallery 220. The electric and/or fiber optic cables may be coiled in the electrical/fiber optic gallery 220 between the alignment body 210 and the tree 18. The electric and/or fiber optic cables may extend from the alignment body 210, through the gallery 220, and into the tree body 18. Containing the electric and/or fiber optic cables in a coiled arrangement within the gallery 220 may enable the alignment body 210 to rotate relative to the tree body 18 since the cables are able to flex in response to such movements of the alignment body 210. The cables located within the alignment body 210 may terminate at a series of wet mate electric contacts (couplings 216) on a lower end of the alignment body 210 designed to rotate relative to the tree 18.
The alignment body 210 includes one or more helical slots 222 formed along an outer surface thereof. The helical slot 222 can be seen more clearly in the illustration of
The timing hub 214 is coupled to the tubing hanger 14, as shown. The timing hub 214 may be directly coupled to the tubing hanger 14 via an attachment mechanism such as a bolt or screw, or the timing hub 214 may be formed integral to the tubing hanger 14. The timing hub 214 may include specific keying features 226 formed on an upwardly facing surface thereof. These keying features 226 on the timing hub 214 are designed to capture the timing ring 212 when the ring 212 is clocked to a unique position and orientation relative to the tubing hanger 14. The keying features 226 on the timing hub 214 may include slots or holes formed on the upper face of the timing hub 214. The keying features 226 may be unevenly spaced from each other around the circumference of the timing hub 214, unevenly spaced in a radial direction from a longitudinal axis of the timing hub, extending different depths in the longitudinal direction, having different shapes in a plane perpendicular to the longitudinal axis, or a combination thereof. The timing ring 212 may include complementary keying features 228 designed to be received directly into the timing hub 214. The keying features 228 extending from the timing ring 212 may be arranged in a similar unevenly positioned, shaped and/or sized manner. The illustrated timing hub 214 includes timed slots machined on the upper face thereof. These slots (226) are positioned such that only one clocked alignment is possible between the timing ring 212 and the timing hub 214. That is, the timing ring 212 will not lock into the timing hub 214 via engagement by the keying features 226 until the timing ring 212 has rotated to a position relative to the timing hub 214 where the features 228 of the timing ring 212 are received into engagement with the corresponding keying features 226 of the timing hub 214.
The timing ring 212 may be attached to the alignment body 210 via one or more alignment pins 230 that land in one or more corresponding helical slots 222 of the alignment body 210. As mentioned above, the timing ring 212 may include uniquely clocked features 228 that interface with the upper face of the timing hub 214. During lowering of the tree 18 (along with the attached alignment body 210 and timing ring 212), the timing ring 212 may land on the timing hub 214. Once landed, continued lowering of the tree body 18 into the wellhead 12 causes the timing ring 212 to rotate until it is stopped by the timing hub 214 and received into mating engagement with the keying features 226 of the timing hub 214. Once the timing ring 212 has been stopped in the timing hub 214, continued lowering of the tree 18 may cause the alignment body 210 to rotate relative to the tree 18 via movement of the alignment pin 230 along the helical slot 222 of the alignment body 210. This rotation will continue until the couplings 216 of the alignment body 210 are aligned with the couplings 32 on the tubing hanger 14.
Once aligned in this manner, the alignment pin(s) 230 coupled to the timing ring 212 may move out of the helical slot 222 and into the straight vertical portion 224. In some embodiments, the alignment body 210 may engage with the tubing hanger 14 via a final alignment key 232 received in a final alignment slot 234. The final alignment slot 234 may be formed in the alignment body 210, and the final alignment key 232 may extend vertically from an engagement surface of the tubing hanger 14. In other embodiments, this arrangement may be reversed, such that the final alignment key extends from the alignment body 210 so as to be received into a final alignment slot formed in the tubing hanger 14. The final alignment key 232 and slot 234 may provide protection to the couplers 216 and 32 and increase machining tolerances of the helical slot 222, the vertical portion of the slot 224, the alignment pins 230, and the keying features of the timing ring 212 and hub 214.
A general description of a method for operating the tubing hanger alignment device 16 of
During construction of the tubing hanger assembly, the timing hub 214 may be installed onto the tubing hanger 14. Specifically, the timing hub 214 may be connected to an upwardly extending portion of the tubing hanger 14 so as to provide a place for seating the timing ring 212 as the tree 18 and alignment body 210 are lowered relative to the tubing hanger 14. The tubing hanger 14 with the connected timing hub 214 may be run in any orientation relative to the wellhead 12 and locked into place within the wellhead 12.
During landing of the tree 18 on the wellhead 12, the timing ring 212 on the alignment body 210 may first land on the timing hub 214. Depending on the initial orientation of the alignment body 210 relative to the tubing hanger 14 and timing hub 214, the timing ring 212 may or may not land directly into a locked position within the timing hub 214. Assuming the timing ring 212 is not in full engagement with the keying features 226 of the timing hub 214 at first, further lowering of the tree 18 may cause the timing ring 212 to rotate relative to the alignment body 210. This rotation of the timing ring 212 relative to the alignment body 310 may be guided by the alignment pin 230 in the helical slot 222. After some rotation, the timing ring 212 may be properly oriented to drop into the slots or other features on the timing hub 214. After dropping into the features on the timing hub 214, the timing ring 212 can no longer rotate with respect to the timing hub 214 and tubing hanger 14.
Lowering the tree 18 further may now cause the alignment body 210 to rotate relative to the tree 18, guided by the helical slot 230 interacting with the stationary alignment pin 222 extending from the timing ring 212. This guiding of the alignment body via the clocked timing ring 212 will cause the alignment body 210 to rotate and align with the tubing hanger 14. Once the alignment body 210 is properly aligned with the tubing hanger 14, the final alignment key 232 may be received into the final alignment slot 234 to finalize the rotational alignment of the couplers 216 on the alignment body 210 to those on the tubing hanger 14.
The tree 18 and alignment body 210 may then be landed and locked to the wellhead 12. All couplings between the alignment body 210 and the tubing hanger 14 will be engaged at this point. The fluidic, electric, and/or fiber optic couplings between the tree 18 and the tubing hanger 14 will then be tested to ensure a proper connection has been made.
It should be noted that the embodiments of
The disclosed tubing hanger alignment device 16 of
Torsional Spring Alignment Mechanism
An alignment device 16 having a torsional spring mechanism is shown in
The upper body 310 may be a solid piece that houses standard fluidic (e.g., hydraulic), electric, and/or fiber optic couplings 318 that interface with the bottom of the second subsea tubular member (hereinafter referred to as “tree”) 18 to connect fluid ports and/or cables in the tree 18 to those in the upper body 310. In this embodiment, the upper body 310 may function as a production stab sub that is coupled directly to the tree body 18 or that is integral with the tree 18. The lower body 312 may be generally disposed around an outer diameter of the upper body 310, as shown. The lower body 312 may be locked in a particular rotational orientation with respect to the upper body 310 prior to release of the lower body 312 via the trigger assembly 316.
The upper body 310 may include one or more fluid ports 320 extending therethrough and routed to a fluid (e.g., hydraulic) gallery 322. The fluid gallery 322 is open to and in fluid communication with one or more fluid (e.g., hydraulic) ports 324 formed through the lower body 312 as well. The fluid gallery 322 may be located in an annular space located between the upper body 310 and the lower body 312, or the fluid gallery 322 may be located entirely within the lower body 312 as shown. The fluid gallery 322 may extend entirely around the circumference of the upper body 310. The fluid gallery 322 allows for rotation of the lower body 312 relative to the upper body 310 while maintaining fluid communication from the between the fluid port 320 in the upper body 310 and the fluid port 324 in the lower body 312.
The electric couplings (318) may be wired through the upper body 310 to a series of wet mate electric contacts (not shown) that sit between the upper body 310 and the lower body 312. These electric contacts may allow rotation of the lower body 312 with respect to the upper body 310. The upper body 310 may be mounted directly to the tree 18 (e.g., via threads, bolts, or other attachment features) or be integral with the tree 18 such that the upper body 310 is not rotatable with respect to the tree body 18. As shown in
The torsional spring 314 is disposed in an annular space between the upper body 310 and the lower body 312. The torsional spring 314 may be wound during assembly of the tubing hanger alignment device 16 and locked into place via the trigger assembly 316. The torsional spring 314 may be released from its wound position at a desired time in response to actuation by the trigger assembly 316. Such release of the torsional spring 314 may cause the lower body 312 to rotate with respect to the upper body 310.
As shown in
The first pair of spring loaded keys 326A and 326B may together function as a trigger for releasing the torsional spring 314 to rotate the lower body 312 once tripped out to a specific elevation within the tubing hanger 14. The spring loaded key 326A may function as a trip key for the trigger assembly 316. This trip key 326A may be attached to the lower body 312 and biased in a radially outward direction. Before actuation of the trigger assembly 316, the trip key 326A may extend at least partially outward from the outer diameter of the lower body 312.
The spring loaded key 326B may function as a retention key for the triggering mechanism 316. This retention key 326B may be attached to the upper body 310 and biased in a radially outward direction. Before actuation of the trigger assembly 316, the retention key 326B may extend outward from the outer diameter of the upper body 310 into a recess formed along an inner diameter of the lower body 312. This retention key 326B extending into the recess in the lower body 312 may hold the lower body 312 in a particular orientation relative to the upper body 310 during the initial landing of the tree 18 and before the release of the spring 314. As shown, the retention key 326B extending into the recess of the lower body 312 may be aligned in a radial direction with the trip key 326A in the lower body 312.
As the tree 18 (along with the upper body 310 and lower body 312) is lowered toward the wellhead 12, the upper body 310 and lower body 312 are received through an initial opening 328 of the tubing hanger 14. This initial opening 328 may have a bore with a diameter that is slightly larger than the outer diameter of the lower body 312. As such, the trip key 326A is able to stay in the outwardly extended position. As the tree 18 continues lowering, the upper body 310 and lower body 312 may pass from the opening 328 into a portion 330 of the first subsea tubular member (hereinafter referred to as “tubing hanger”) 14 having a relative smaller diameter bore that is just large enough to receive the lower body 312. The tubing hanger 14 may feature a trip shoulder 332 at the boundary between the larger bore initial opening 328 and the smaller bore portion 330. As the lower body 312 passes into the smaller bore portion 330 of the tubing hanger 14, the trip key 326A may be brought into contact with the trip shoulder 332, which presses the trip key 326A radially inward. This radially inward movement of the trip key 326A simultaneously forces the retention key 326B out of the recess in the lower body 312 such that the retention key 326B no longer holds the lower body 312 in rotational alignment with the upper body 310. This allows the lower body 312 to now rotate relative to the upper body 310 as urged by the previously set torsional spring 314.
The final spring loaded key 326C may function as an alignment key to stop rotation of the lower body 312 when the lower body 312 reaches the proper orientation relative to the tubing hanger 14. The alignment key 326C may be attached to the lower body 310 and biased in a radially outward direction. During rotation of the lower body 310 relative to the upper body 312 in response to force exerted by the torsional spring 314, the alignment key 326C may be held in place within a recess in the lower body 312 by the inner wall of the relatively smaller bore portion 330 of the tubing hanger 14. The lower body 312 may rotate until the alignment key 326C reaches a position that is rotationally aligned with a slot 334 formed in the inner diameter of the tubing hanger 14. The slot 334 may be vertically oriented, as shown. Once the alignment key 326C is aligned with the slot 334, the key 326C is biased radially outward into the slot 334, thereby halting rotation of the lower body 312 at a desired position relative to the tubing hanger 14.
The lower body 312 may be a solid piece that houses fluidic (e.g., hydraulic), electric, and/or fiber optic couplings 336 designed to interface directly with those couplings 32 on the tubing hanger 14. The couplings 336 may be a standard design, or they may be an actuated design so that they can make up linear differences in elevations between the bottom of the lower body 312 and the top of the tubing hanger 14. As mentioned above, the lower body 312 may include one or more fluid ports 324 routed to the fluid gallery 322 so as to allow rotation of the lower body 312 relative to the upper body 310. Electric couplings at the bottom of the lower body 312 may be wired to a series of wet mate electric contacts (not shown) that sit between the upper body 310 and the lower body 312. These electric contacts may allow rotation of the lower body 312 with respect to the upper body 310. The lower body 312 may also house the alignment key 326C and the retention key 326B of the trigger assembly 316.
In the embodiments of
A general description of a method for operating the tubing hanger alignment device 16 of
The tubing hanger 14 may be run in any orientation and locked into place within the wellhead 12. The tree 18 (with connected alignment device 16) may then be run and oriented into a desired location prior to landing. While landing the tree 18, the trigger assembly 316 of the alignment device 16 trips out on the trip shoulder 332 in the inner diameter of the tubing hanger 14 to release the spring 314, as described at length above. Once the torsional spring 314 is released, the lower body 312 is able to rotate until the spring loaded alignment key 326C enters the mating slot 334 in the inner diameter of the tubing hanger 14. Once the lower body 312 is rotationally locked into the alignment slot 334, the fluidic, electric, and/or fiber optic couplings 336 may be engaged with the corresponding couplings 32 of the tubing hanger 14. The fluidic, electric, and/or fiber optic couplings between the tree 18 and the tubing hanger 14 will then be tested to ensure a proper connection has been made.
It should be noted that the embodiment of
The disclosed tubing hanger alignment device 16 of
Plug-based Alignment Mechanism
An alignment device 16 having a plug-based alignment mechanism is shown in
The alignment sleeve 510 may be a solid piece that is located within and interfaces with an inner surface of a main bore of the second subsea tubular member (hereinafter referred to as “tree”) 18. The alignment sleeve 510 may be directly coupled to a production stab sub 514 of the tree 18 and held in place relative to the sub 514 via a shear pin 516 or other type of shear mechanism. The tree 18 may include standard fluidic (e.g., hydraulic), electric, and/or fiber optic couplings 518 designed to be communicatively coupled with the couplings 32 on the first subsea tubular member (hereinafter referred to as “tubing hanger”) 14.
Turning to
The inner plug body 520 is generally disposed within the outer plug body 522, as shown. The outer plug body 522 may include two components that are connected (e.g., via threads 540) together to define a cavity 542 within which the inner body 520 is partially captured. A distal portion 544 of the inner body 520 may extend outside the cavity 542 in one direction, and this distal portion 544 may have a bore formed therethrough. A connecting portion 546 of the orientation sleeve 524 may be received within the bore in the distal portion 544 of the inner plug body 520, and the retaining bolt 526 may be positioned through the connecting portion 546 of the orientation sleeve 524 and coupled directly to the inner body 520 via threads. As such, the retaining bolt 526 may couple the orientation sleeve 524 to the inner plug body 520. It should be noted that other arrangements of an orientation sleeve and one or more plug bodies may be utilized in other embodiments of the disclosed plug assembly 512.
The locking mechanism 528 may include a set of locking dogs or a split ring, or any other type of lock as known to one of ordinary skill in the art. The locking mechanism 528 may be disposed at least partially around an outer edge of the inner body 520 and may extend into and/or through at least one slot 548 formed radially through the outer body 522. This allows the locking mechanism 528 to be actuated into locking engagement with a radially inner surface of the tubing hanger 14 so as to lock the plug assembly 512 in place within the tubing hanger 14. A generally sloped surface 550 forming a radially outer edge of the inner plug body 520 may be used to hold the locking mechanism 528 into its extended locking position until it is time to remove the plug assembly 512 from the tubing hanger 14.
The actuation mechanism 530 may be used to actuate the plug and thereby set the locking mechanism 528 within the tubing hanger 14. The actuation mechanism 530 may include an actuation button 552 and a split ring 554 (or similar type of actuation ring). The actuation mechanism 530 may function as follows. The split ring 554 may be biased in a radially outward direction. When the plug assembly 512 is being run in, the split ring 554 may be held within two opposing recesses 556 and 558 formed in a radially outer surface of the inner body 520 and a radially inner surface of the outer body 522, respectively. In this position, the split ring 554 may generally prevent the inner body 520 and outer body 522 from moving relative to each other in an axial direction. The actuation button 552 may be positioned through the wall of the outer body 522 and have a flat surface extending into the recess 558 of the outer body 522.
When the plug assembly 512 is run into the tubing hanger 14, a shoulder 560 (
The seal or packing element 532 located at the lower end of the outer plug body 522 is used to provide a high pressure seal within the bore of the tubing hanger 14. When the plug assembly 512 enters the locked position, the seal or packing element 532 is energized. The seal or packing element 532 may seal the tubing hanger 14 so that the BOP can be removed from the wellhead, and replaced by the tree 18, while maintaining two high pressure seals in the system (one via a downhole safety valve and a backup via the plug 512).
The tapered gear/spline 534 may be disposed at the intersection of the connecting portion 546 of the orientation sleeve 524 and the inner body 520. The tapered gear/spline mechanism 534 may include threads that enable an incremental adjustment of the orientation (e.g., by 1 degree, 2 degrees, or some other amount) of the orientation sleeve 524 about the longitudinal axis relative to the rest of the plug assembly 512. The outer plug body 522 may be held rotationally in place via the anti-rotation key 535 fitted in a corresponding slot of the tubing hanger 14 when the plug assembly 512 is in the locked position. At this point, a running and/or adjustment tool disposed inside and engaged with running/adjustment grooves 566 of the orientation sleeve 524 may pick up the orientation sleeve 524 and rotate the orientation sleeve 524 relative to the outer and inner bodies of the plug. This rotation may be performed in an incremental fashion in accordance with the relative size and number of threads present in the tapered gear/spline mechanism 534. The retaining bolt 526 may be sized and positioned such that the orientation sleeve 524 can move axially back and forth as needed during this adjustment process. The orientation of the sleeve 524 is so that the sleeve 524 can be brought into a desired rotational alignment with respect to the wellhead 12. An ROV based tool or some other type of tool may be used to determine how far the orientation sleeve 524 has been adjusted within the wellhead.
The orientation sleeve 524 includes an orientation profile 568 formed along a distal end of the orientation sleeve 524. The orientation profile 568 may include, for example, a slanted end surface and a series of different sized slots 570 extending through the orientation sleeve 524. The alignment sleeve 510 on the tree 18 may feature a complementary profile 572 designed to fit into the orientation profile 568 of the orientation sleeve 524 when the alignment sleeve 510 (and consequently tree 18) are brought into a desired alignment with the orientation sleeve 524. The slots 50 may each have different widths so as to only allow mating engagement of the alignment sleeve 510 with the orientation sleeve 524 in a single orientation of the parts relative to each other. The alignment sleeve 510 may rotate until it is brought into this desired orientation. In this orientation, the couplings 518 on the tree 18 will be directly aligned with the couplings 32 on the tubing hanger 14. The slots 570 may be elongated in a vertical direction, as shown, so that the tree couplings 518 can be brought into the correct alignment with the tubing hanger couplings 32 first and then be lowered directly downward to form a mating connection.
It should be noted that other types or arrangements of an orientation profile 568 on the orientation sleeve 524 and complementary profile 572 on the alignment sleeve 510 may be utilized in other embodiments. For example, the orientation profile 568 may be a helix and the alignment sleeve 572 may include a pin designed to be received into the helix and directed therethrough until the tree 18 is brought into alignment and a mating connection with the tubing hanger 14. In other embodiments, the orientation profile 568 may have a helical shape and the alignment sleeve 572 may have a complementary helical shape designed to be received into the orientation profile 568 and directed therethrough until the tree 18 is aligned with the tubing hanger 14.
A general description of a method for operating the tubing hanger alignment device 16 of
Further lowering of the plug assembly 512 will cause the plug assembly 512 to lock into the tubing hanger 14, as shown in
Once the plug assembly 512 is locked, the BOP may be removed from the wellhead 12. The orientation sleeve 524 may be adjusted relative to the rest of the plug 512, as shown in
The tree 18 (illustrated just as the alignment sleeve 510 in
After the tree is landed, the plug assembly 512 may be removed. The plug assembly 512 may be reusable in different wellheads once it is removed. To remove the plug assembly 512, a retrieval tool may be coupled to the orientation sleeve 524 and used to pull the plug upward. This upward force may cause the spring-loaded shear pin 536 to shear, thereby releasing the inner body 520 from its axial position within the outer body 522. The inner body 520 may be lifted up within the outer body 522, causing the sloped surface 550 to move out of the outwardly biasing contact with the locking mechanism 528. The locking mechanism 528 may collapse into the recess in the outer body 522, freeing the plug 512 to be extracted from the bore of the tubing hanger 14.
One or more aspects of the present disclosure provide a system including a subsea equipment alignment device for coupling a first subsea tubular member to a second subsea tubular member. The subsea equipment alignment device includes one or more fluid, electric, or fiber optic lines extending therethrough and one or more couplings disposed on at least one end thereof, and the subsea equipment alignment device is configured to couple one or more fluid, electric, or fiber optic lines of the first subsea tubular member with one or more fluid, electric, or fiber optic couplings of the second subsea tubular member regardless of a relative orientation of the first subsea tubular member and the second subsea tubular member with respect to each other.
In one or more aspects, the subsea equipment alignment device is configured to couple the one or more fluid, electric, or fiber optic lines of the second subsea tubular member with the one or more fluid, electric, or fiber optic couplings on the first subsea tubular member disposed in a wellhead during landing of the second subsea tubular member onto the wellhead regardless of a relative orientation of the first subsea tubular member and the second subsea tubular member with respect to the wellhead.
In one or more aspects, the subsea equipment alignment device includes: a production stab sub, an alignment sub disposed around and rotatably coupled to the production stab sub, one or more conduits wrapped around the production stab sub, and an outer timing ring disposed around and coupled to the alignment sub. One or more fluid, electric, or fiber optic lines of the subsea equipment alignment device extend through the alignment sub to the one or more couplings of the subsea equipment alignment device at an end of the alignment sub. The one or more conduits are coupled to the one or more fluid, electric, or fiber optic lines of the alignment sub at one end and configured to be coupled to the one or more fluid, electric, or fiber optic lines of the second subsea tubular member at an opposite end. The outer timing ring includes one or more keyed features configured to interface with complementary features on the first subsea tubular member.
In one or more aspects, the alignment sub includes multiple alignment threads formed therein, and wherein the outer timing ring includes multiple pins extending therefrom that interface with the alignment threads.
In one or more aspects, the system further includes multiple vertical alignment slots formed in the alignment sub and extending from ends of the multiple alignment threads.
In one or more aspects, the system further includes an actuation mechanism disposed on the alignment sub and configured to selectively release the production stab sub to move axially with respect to the alignment sub.
In one or more aspects, the actuation mechanism includes one or more buttons extending through the alignment sub and a split ring coupled between the alignment sub and the production stab sub, wherein a radially inward force on the one or more buttons from the outer timing ring collapses the split ring.
In one or more aspects, the production stab sub includes one or more seals located at a distal end thereof.
In one or more aspects, the subsea equipment alignment device includes an alignment body configured to be rotatably coupled to the second subsea tubular member, a timing ring coupled to the alignment body, and a timing hub configured to be mounted to the first subsea tubular member. The alignment body is configured to define an electrical gallery and a fluid gallery in an annular space between the second subsea tubular member and the alignment body. The timing ring includes keyed features extending therefrom. The timing hub includes complementary features that receive the keyed features of the timing ring therein when the timing ring is in a specific orientation.
In one or more aspects, the alignment body includes a helical groove formed in an external surface thereof and the timing ring is coupled to the alignment body via a pin extending from the timing ring into the helical groove.
In one or more aspects, the alignment body further includes: a vertical alignment slot which extends from a first end of the helical groove; and a final alignment pin disposed at a second end of the alignment body.
In one or more aspects, the subsea equipment alignment device includes: a first body configured to be coupled to the second subsea tubular member; a second body coupled to the first body; a torsional spring disposed in the second annular space between the first and second bodies; and a trigger assembly. First and second annular spaces are formed between the first body and the second body, the first annular space defining an electrical gallery and a fluid gallery, and the one or more couplings of the subsea equipment alignment device are disposed on the second body. The trigger assembly is configured to selectively trigger the torsional spring to rotate the second body relative to the first body until the one or more couplings on the second body are aligned with the one or more couplings on the first subsea tubular member.
In one or more aspects, the trigger assembly includes a first button extending radially outward from the second body, a second button extending radially outward from the first body into the second body immediately adjacent the first button, and a third button biased in a radially outward direction and disposed within the second body. The third button is configured to be received into an alignment slot on the first subsea tubular member to stop rotation of the second body in a desired orientation.
One or more aspects of the present disclosure provide a system for coupling a first subsea tubular member to a second subsea tubular member. The system includes: a rotating sub rotatably coupled to a portion of the first subsea tubular member; one or more fluid, electric, or fiber optic lines extending through the rotating sub and terminating at one or more couplings disposed at an end of the rotating sub; an orientation profile disposed on a surface of the rotating sub; and a corresponding alignment member with a profile designed to interface with the orientation profile of the rotating sub, wherein the alignment member remains stationary while the rotating sub rotates relative to the alignment member.
In one or more aspects, the first subsea tubular member includes one of a tree body, a spool, or a flowline connection body, and wherein the second subsea tubular member includes a tubing hanger.
In one or more aspects, the orientation profile of the rotating sub includes a key and the alignment member includes a helical profile, wherein the key is a generally rectangular shaped member having at least one tapered surface at one end thereof.
In one or more aspects, the orientation profile of the rotating sub includes a helical profile and the alignment member includes a key and wherein the key is a generally rectangular shaped member having at least one tapered surface at one end thereof.
In one or more aspects, the orientation profile of the rotating sub and the profile of the alignment member are both helically shaped.
In one or more aspects, the alignment member is disposed on an orientation sub that is mounted to the second subsea tubular member.
In one or more aspects, the alignment member is integral with the second subsea tubular member.
One or more aspects of the present disclosure provide a system for coupling a first subsea tubular member with a second subsea tubular member. The system includes at least one alignment member including a profile formed on a surface of the first subsea tubular member; a rotating sub; and an orientation profile disposed on a surface of the rotating sub. The orientation profile is designed to interface with the profile of the alignment member, wherein the alignment member remains stationary while the rotating sub rotates relative to the alignment member.
In one or more aspects, the first subsea tubular member includes a tubing hanger and the second subsea tubular member includes one of a tree body, a spool, or a flowline connection body.
In one or more aspects, the orientation profile of the rotating sub includes a key and the alignment member includes a helical groove, wherein the key is a generally rectangular shaped member having at least one tapered surface at one end thereof.
In one or more aspects, the orientation profile of the rotating sub includes a helical groove and the alignment member includes a key, wherein the key is a generally rectangular shaped member having at least one tapered surface at one end thereof.
In one or more aspects, the orientation profile of the rotating sub and the profile of the alignment member are both helically shaped.
In one or more aspects, the system further includes a production stab sub mounted to the second subsea tubular member, wherein the rotating sub is rotatably coupled to the production stab sub.
In one or more aspects, the system further includes a generally cylindrical body integral with a body of the second subsea tubular member, wherein the rotating sub is rotatably coupled to the generally cylindrical body.
In one or more aspects, the system further includes a generally cylindrical body extending from a body of the second subsea tubular member, wherein the rotating sub is disposed around and rotatably coupled to the generally cylindrical body.
In one or more aspects, the system further includes one or more conduits wrapped around the generally cylindrical body and coupled to one or more fluid, electric, or fiber optic lines of the second subsea tubular member at one end and to the one or more fluid, electric, or fiber optic lines of the rotating sub at an opposite end.
One or more aspects of the present disclosure provide a system for coupling subsea tubular members. The system includes an alignment sub and a corresponding alignment member. The alignment sub includes a generally cylindrical body having one or more fluid, electric, or fiber optic lines extending therethrough, one or more couplings coupled to at least one end of the alignment sub, and a helically shaped orientation profile disposed on a surface of the alignment sub. The alignment member has a helically shaped profile designed to interface with the orientation profile of the alignment sub. One of the alignment sub and the alignment member remains stationary while the other rotates relative to the stationary structure.
In one or more aspects, the alignment sub rotates while the alignment member remains stationary.
In one or more aspects, the alignment sub is rotatably coupled to a surface of one of the subsea tubular members.
In one or more aspects, the alignment member includes an orientation sub coupled to a surface of one the subsea tubular members.
In one or more aspects, the alignment member is integral with one of the subsea tubular members.
In one or more aspects, the orientation profile of the alignment sub includes at least one helical groove and the profile of the alignment member includes at least one helical protrusion.
In one or more aspects, the orientation profile of the alignment sub includes at least one helical protrusion and the profile of the alignment member includes at least one helical groove.
Although the present disclosure and its advantages have been described in detail, it should be understood that various changes, substitutions and alterations can be made herein without departing from the spirit and scope of the disclosure as defined by the following claims.
The present application is a continuation in part claiming the benefit of U.S. patent application Ser. No. 16/869,452, entitled “Tubing Hanger Alignment Device,” filed on May 7, 2020, which is a continuation in part claiming the benefit of U.S. patent application Ser. No. 16/111,987, entitled “Tubing Hanger Alignment Device,” filed on Aug. 24, 2018, which claims priority to Provisional Patent Application Ser. No. 62/574,491, entitled “Tubing Hanger Alignment Device,” filed on Oct. 19, 2017. The present application is also a continuation in part claiming the benefit of U.S. patent application Ser. No. 17/067,590, entitled “Tubing Hanger Alignment Device,” filed on Oct. 9, 2020, which is a continuation of U.S. patent application Ser. No. 16/111,987, entitled “Tubing Hanger Alignment Device,” filed on Aug. 24, 2018, which claims priority to Provisional Patent Application Ser. No. 62/574,491, entitled “Tubing Hanger Alignment Device,” filed on Oct. 19, 2017.
| Number | Date | Country | |
|---|---|---|---|
| 62574491 | Oct 2017 | US | |
| 62574491 | Oct 2017 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 16111987 | Aug 2018 | US |
| Child | 17067590 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 16869452 | May 2020 | US |
| Child | 17112951 | US | |
| Parent | 16111987 | Aug 2018 | US |
| Child | 16869452 | US | |
| Parent | 17067590 | Oct 2020 | US |
| Child | 16111987 | US |
