System and Method for Producing Through a Multi Bore Tubing Hanger to a Subsea Manifold Without BOP Modifications

Abstract

A system for producing hydrocarbons from a subsea wellbore includes a primary conductor extending into the seabed. In addition, the system includes a wellhead disposed at an upper end of the primary conductor. Further, the system includes a multi bore tubing hanger seated in the wellhead. Still further, the system includes a production tree mounted to the wellhead. The production tree includes a spool body and a production spool extending radially from the spool body. The production spool has an end comprising a connector. Moreover, the system includes a rotatable production guide base coupled to the primary conductor and configured to rotate about the wellhead. The production guide base includes a rigid alignment spool. The alignment spool has a first end releasably coupled to the production spool, a second end comprising a second connector, and non-linear deviation positioned between the first end and the second end.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims benefit of U.S. provisional patent application Ser. No. 61/684,057 filed Aug. 16, 2012, and entitled “Systems and Methods for Producing Through a Multi Bore Tubing Hanger to a Subsea Manifold Without BOP Modifications,” which is hereby incorporated herein by reference in its entirety.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND

The invention relates generally to systems and methods for producing hydrocarbon fluids through a multi bore tubing hanger to a subsea manifold. More particularly, the invention relates to systems and methods that reduce and/or eliminate conventional BOP modifications necessary to align the multi bore tubing hanger during installation.

Conventionally, subsea wells are built up by installing a primary conductor in the seabed, securing a wellhead to the upper end of the primary conductor and, with a drilling blowout preventer (BOP) stack installed on the wellhead, drilling down through the BOP stack, wellhead, and primary conductor to produce a borehole while successively installing concentric casing strings that line the borehole. The casing strings are cemented at their lower ends and sealed with mechanical seals at their upper ends. A production guide base (PGB) is typically mounted to and run with the conductor during the well spud. The PGB usually includes a radially extending arm that supports a jumper spool having a production inlet connector and a production outlet connector.

In order to convert the cased well for production, a production tubing string is run through the BOP stack, and a tubing hanger at the upper end of the production tubing string is landed in a mating profile inside the wellhead. Thereafter, bores in the tubing hanger are temporarily closed, and the drilling BOP stack is removed. Next, a production tree having a production bore and associated valves is lowered subsea and mounted to the wellhead, effectively replacing the BOP stack. The production tree includes a production spool with an outlet that connects to the production inlet of the PGB jumper spool. The production spool is in fluid communication with the production bore in the tree, which in turn, is in fluid communication with the production bore of the tubing hanger. Next, a rigid preconfigured jumper is lowered subsea and coupled to the production outlet of the PGB jumper spool and an inlet of a subsea manifold, thereby providing fluid communication between the PGB jumper spool and the manifold. Accordingly, hydrocarbon fluids produced from the wellbore flow through the production tubing and production bore of the tubing hanger, through the production bore and production spool of the tree, and through the PGB jumper spool and jumper to the subsea manifold.

The jumper connecting the PGB jumper spool and the manifold is rigid and preconfigured based on metrological data obtained after permanent installation of the PGB and subsea manifold. Thus, once deployed, the distance between the inlet and outlet of the jumper, as well as the relative heights of the inlet and outlet of the jumper are fixed.

During installation, the PGB is rotationally oriented about the primary conductor such that the production outlet of the jumper spool is located within a specific, pre-determined position to allow the rigid jumper to simultaneously connect to the outlet of the jumper spool and the corresponding inlet of the manifold while avoiding interference with neighboring wells, and associated plumbing, tied into the same subsea manifold. In addition, the tree must be rotationally oriented in a specific position such that the production spool of the tree is circumferentially aligned with the production inlet of the jumper spool for mating connection therebetween.

For mono bore and concentric tubing hangers having a single production bore centered in the tubing hanger (i.e., extending coaxially through the tubing hanger), achieving the desired rotational orientation of the tree and PGB is usually not problematic because the PGB can be lowered subsea and mounted to the wellhead with the desired rotational orientation (i.e., with the production outlet of the jumper spool in the desired position for connection to the jumper), and the tree can then be lowered subsea, rotated to align the production spool with the production inlet of the jumper spool, and then mounted to the wellhead to bring the production spool into engagement with the production inlet of the jumper spool. The rotational orientation of the tree relative to the tubing hanger is generally irrelevant for mono bore and concentric tubing hangers as the centered production bore in the tubing hanger will always be coaxially aligned with the production bore of the production tree regardless of the rotational orientation of the tree relative to the tubing hanger. However, this is not the case with conventional dual bore tubing hangers, and thus, the installation and rotational orientation of the PGB, the tubing hanger, and the production tree must be carefully controlled and monitored. More specifically, to ensure the proper position and orientation of the jumper spool, the PGB must be oriented in a specific rotational orientation when run in with the primary conductor, and further, the multi bore tubing hanger must be installed in a specific rotational orientation to enable alignment and connection with the tubing hanger bores (i.e., alignment and mating engagement between stabbing members on the lower end of the tree and the bores in the tubing hanger) and the inlet of the PGB jumper spool (i.e., alignment and mating engagement between the production spool of the tree and the inlet of the PGB jumper spool). In other words, the PGB and the tubing hanger must be rotationally oriented to allow the production tree to simultaneously mate and engage the tubing hanger bores and the inlet of the properly positioned jumper spool. Typically, the BOP stack, production tree, tubing hanger, or combinations thereof include alignment mechanisms (e.g., mating pins and guides) that facilitate the proper rotational alignment of such components to enable the specific positioning of the PGB jumper spool outlet for connection to the rigid jumper. In addition, complex running, retrieval, installation, and testing tools may be necessary to achieve and assure proper alignment of these components. Such alignment mechanisms often necessitate time consuming, expensive, and complex custom modifications to the BOP stack, production tree, tubing hanger, or combinations thereof Moreover, implementation of select alignment mechanisms and tools may dictate the type of rig that must be employed, thereby limiting the number of available rigs that can be used for a particular job.

BRIEF SUMMARY OF THE DISCLOSURE

These and other needs in the art are addressed in one embodiment by a system for producing hydrocarbons from a subsea wellbore. In an embodiment, the system comprises a primary conductor extending into the seabed. In addition, the system comprises a wellhead disposed at an upper end of the primary conductor. Further, the system comprises a multi bore tubing hanger seated in the wellhead. The tubing hanger including a first bore and a second bore. Still further, the system comprises a production tree mounted to the wellhead. The production tree includes a spool body, a first stabbing member extending from the spool body and disposed in the first bore, a second stabbing member extending from the spool body and disposed in the second bore, and a production spool extending radially from the spool body, wherein the production spool has an end comprising a connector. Moreover, the system comprises a rotatable production guide base coupled to the primary conductor. The production guide base is configured to rotate about the wellhead and releasably lock on to the upper end of the conductor. The production guide base includes an annular connector disposed about the primary conductor, a support frame extending radially from the annular connector, and a rigid alignment spool mounted to the support frame. The alignment spool has a first end comprising a first connector releasably coupled to the connector of the production spool, a second end comprising a second connector, and non-linear deviation positioned between the first end and the second end.

These and other needs in the art are addressed in another embodiment by a method for completing a subsea well. In an embodiment, the method comprises (a) running a multi bore tubing hanger into a wellhead, the tubing hanger including a first bore and a second bore. In addition, the method comprises (b) determining the rotational orientation of the tubing hanger after (a). Further, the method comprises (c) constructing an alignment spool based on the rotational position of the tubing hanger. Still further, the method comprises (d) coupling the alignment spool to a rotatable production guide base. The production guide base is configured to rotate about the wellhead.

These and other needs in the art are addressed in another embodiment by a method for completing a subsea well. In an embodiment, the method comprises (a) running a multi bore tubing hanger into a wellhead, the tubing hanger including a first bore and a second bore. In addition, the method comprises (b) constructing a rigid alignment spool after (a). The alignment spool has a first end comprising a first connector, a second end comprising a second connector. Further, the method comprises (c) mounting the alignment spool to a support frame of a rotatable production guide base after (b). The production guide base is configured to rotate about the wellhead.

Embodiments described herein comprise a combination of features and advantages intended to address various shortcomings associated with certain prior devices, systems, and methods. The foregoing has outlined rather broadly the features and technical advantages of the invention in order that the detailed description of the invention that follows may be better understood. The various characteristics described above, as well as other features, will be readily apparent to those skilled in the art upon reading the following detailed description, and by referring to the accompanying drawings. It should be appreciated by those skilled in the art that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes of the invention. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed description of the preferred embodiments of the invention, reference will now be made to the accompanying drawings in which:

FIG. 1 is a schematic top view of a dual bore tubing hanger;

FIG. 2 is a schematic cross-sectional side view of the dual bore tubing hanger of FIG. 1;

FIG. 3 is a schematic cross-sectional side view of a production tree;

FIG. 4A is a schematic top view of a conventional production guide base;

FIG. 4B is a schematic cross-sectional side view of the production guide base of FIG. 4A;

FIG. 5A is a schematic top view of a jumper;

FIG. 5B is a schematic cross-sectional side view of the jumper of FIG. 5A;

FIG. 6 is a schematic top view of a subsea template illustrating the connection of the jumper of FIG. 5A to the jumper spool of FIG. 4A;

FIGS. 7A-7D are sequential schematic illustrations of the completion of a well in the subsea template of FIG. 6 utilizing the dual bore tubing hanger of FIG. 1, the production tree of FIG. 3, the production guide base of FIG. 4A, and the jumper of FIG. 5A;

FIG. 8 is a schematic top view of an embodiment of a rotatable production guide base including a modified jumper spool; and

FIGS. 9A-9D are sequential schematic illustrations of an embodiment of a method for completing a well in the subsea template of FIG. 6 utilizing the dual bore tubing hanger of FIG. 1, the production tree of FIG. 3, the rotatable production guide base of FIG. 8, and the jumper of FIG. 5A; and

FIGS. 10A-10D are schematic illustrations of an embodiment of a method for completing a well in the subsea template of FIG. 6 utilizing the dual bore tubing hanger of FIG. 1, the production tree of FIG. 3, the rotatable production guide base of FIG. 8, and the jumper of FIG. 5A at four different, exemplary rotational orientations of the dual bore tubing hanger within the wellhead.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

The following discussion is directed to various exemplary embodiments. However, one skilled in the art will understand that the examples disclosed herein have broad application, and that the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to suggest that the scope of the disclosure, including the claims, is limited to that embodiment.

Certain terms are used throughout the following description and claims to refer to particular features or components. As one skilled in the art will appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name but not function. The drawing figures are not necessarily to scale. Certain features and components herein may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in interest of clarity and conciseness.

In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . . ” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect connection via other devices, components, and connections. 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.

Referring now to FIGS. 1 and 2, a dual bore tubing hanger 10 is schematically shown. Hanger 10 has a central or longitudinal axis 15 and includes a hanger body 11, a production tubing string 12 extending axially downward from body 11, and a secondary or annulus tubing string 13 extending axially downward from body 11. Strings 12, 13 are oriented parallel to each other, but radially offset from axis 15. A production bore 14 extends through body 11 and production tubing string 12, and a secondary or annulus bore 16 extends though body 11 and annulus tubing string 13. When hanger 10 is disposed in a wellhead, production tubing string 12 extends downward and provides fluid communication with a production zone in the well, and secondary tubing string 13 extends downward and provides fluid communication with the “A” annulus disposed below tubing hanger 10 between the production casing string and tubing packed off at a deeper location to isolate the production reservoir from the annulus. Counterbores or recesses 17, 18 extend axially from the upper end of body 11 to bores 14, 16. Counterbores 17, 18 are coaxially aligned with bores 14, 16, respectively, and strings 12, 13, respectively, and thus, are also radially offset from axis 15. The radially outer surface of hanger body 11 includes an annular shoulder 19 configured to engage a mating annular seat provided on the inside of the wellhead. When hanger body 11 is seated within the annular seat on the inside of the wellhead, strings 12, 13 are suspended or hung into the wellbore from hanger body 11, which in turn is supported by the wellhead. As is known in the art, dual bore hangers such as hanger 10 can also include hydraulic and electrical connections to provide control or monitoring of completion installed valves and gauges.

Referring now to FIG. 3, a production tree 20 is schematically shown. Tree 20 includes a spool body 21 having a central axis 25 and a downward facing female connector 22, a production spool 30 extending radially outward from body 21, a production bore stabbing member 24, and an annulus bore stabbing member 26. A production flow bore 27 extends axially through body 21 and stabbing member 24, and an annulus flow bore 28 extends axially through body 21 and stabbing member 26. Valves 27a, 28a control the flow of fluids through bores 27, 28, respectively. Connector 22 is configured to releasably engage a mating upward facing male connector or hub on the wellhead. In general, connector 22 may comprise any suitable hydraulically actuated releasable wellhead-type mechanical connector that is compatible with the corresponding wellhead hub. Examples of suitable connectors include, without limitation, the H-4® profile subsea connector available from VetcoGray Inc. of Houston, Tex. or the DWHC profile subsea connector available from Cameron International Corporation of Houston, Tex.

Stabbing members 24, 26 are sized and positioned to simultaneously engage mating counterbores 17, 18, respectively, upon connection of tree 20 to the wellhead, thereby placing bores 27, 28 in fluid communication with strings 12, 13, respectively. Production spool 30 extends radially outward and axially downward from spool body 21 and includes a production flow bore 31 in selective fluid communication with bore 27 and a downward facing female connector 32 at its end distal body 21 for connection to the inlet of the PGB jumper spool. In general, connector 32 may comprise any suitable hydraulically actuated releasable mechanical connector that is compatible with the corresponding connector or hub on the jumper spool. Examples of suitable connectors include, without limitation, KC4-family collet connectors and connection systems made by FMC Technologies, Inc. of Houston, Tex., mini CVC connectors made by Cameron International Corporation of Houston, Tex., Optima™ subsea connectors made by Vector Technology Group of Drammen, Norway, or other connectors of the like known in the art. Although connector 32 is a single bore vertical connector in this embodiment, in general, the production spool (e.g., spool 30) can utilize vertical or horizontal connectors and/or be single or multi-bore.

Referring now to FIGS. 4A and 4B, a conventional PGB 40 is schematically shown. PBG 40 includes an annular downward facing female connector 41, a support frame or arm 42 extending radially outward from connector 41, and a jumper spool 43 mounted to support arm 42. Connector 41 is configured to be disposed about the wellhead and releasably engage the upper end of the primary conductor or low pressure housing extending into the seabed and to which the wellhead is secured. In general, connector 41 may comprise any suitable hydraulically actuated releasable wellhead-type mechanical connector that is compatible with the corresponding wellhead hub. In conventional PGB 40, once connector 41 is locked onto the conductor and wellhead, PGB 40 is prohibited from being rotated about the wellhead.

Jumper spool 43 is a rigid fluid conduit including a radially inner inlet end 43a and a radially outer outlet end 43b. Each end 43a, 43b comprises an upward facing male connector or hub 46, 47, respectively. Hub 46 is configured to releasably engage mating female connector 32 of production spool 30. In general, connector 46 may comprise any suitable hydraulically actuated releasable mechanical connector that is compatible with connector 32 on production spool 30. Examples of suitable connectors include, without limitation, mini CVC connectors made by Cameron International Corporation of Houston, Tex., Optima™ subsea connectors made by Vector Technology Group of Drammen, Norway, or other connectors of the like known in the art. As will be described in more detail below, hub 47 at outlet end 43b is configured to releasably engage a mating female connector on an inlet end of a rigid jumper.

In conventional PGB 40, jumper spool 43 is a rigid linear conduit having ends 43a, 43b comprising upturned connectors 46, 47. Further, jumper spool 43 is radially oriented relative to connector 41, namely, jumper spool 43 extends along a horizontal axis 43a that intersects a vertical central axis 41a of connector 41.

Referring now to FIGS. 5A and 5B, a jumper 50 is schematically shown. Jumper 50 is an elongate conduit having a central or longitudinal axis 55, a first or inlet end 50a, a second or outlet end 50b, and a production bore or passage 51 extending between ends 50a, 50b. Each end 50a, 50b comprises a downward facing female connector 52, 53, respectively. Connector 52 is configured to releasably engage mating male hub 47 of jumper spool 43 (shown in phantom in FIG. 5), and connector 53 is configured to releasably engage a mating male hub 61 of a subsea manifold 60 (shown in phantom in FIG. 5B). In general, each connector 52, 53 may comprise any suitable hydraulically actuated releasable mechanical connector that is compatible with connector 47, 61, respectively. Examples of suitable connectors include, without limitation, mini CVC connectors made by Cameron International Corporation of Houston, Tex., Optima™ subsea connectors made by Vector Technology Group of Drammen, Norway, or other connectors of the like known in the art. Although connectors 52, 53 of jumper 50 are designed for vertical connections, in other embodiments, one or both of the connectors on the jumper (e.g., connectors 52, 53 on the ends of jumper 50) may be designed for horizontal connections.

Referring now to FIGS. 5A, 5B, and 6, jumper 50 is a rigid conduit specifically designed and constructed to extend between hubs 47, 61. Based on the pre-determined layout of the subsea template (i.e., relative locations of a cluster of wells around a manifold) and final metrology, jumper 50 is dimensioned such that ends 50a, 50b are vertically spaced relative to each other to account for the vertical distance D between hubs 47, 61, and such that ends 50a, 50b are horizontally spaced apart a length L measured between hubs 47, 61. In particular, length L is the horizontal distance between hubs 47, 61 after installation with hub 47 disposed at the desired predetermined position “A” and hub 61 disposed at predetermined position “B.” If hub 47 is not disposed at, or sufficiently proximal, the specific position “A”, jumper 50 could be custom built to connect to both hubs 47, 61, but may interfere with neighboring wells or other subsea plumbing connected to manifold 60. As a result, the positioning of hub 47 at position “A” is vital during installation of conventional PGB 40. As will be described in more detail below, the proper positioning of hub 47 of conventional PGB 40 is achieved by carefully aligning and orienting various components during completion of the wellbore

Referring now to FIGS. 7A-7D, the completion of a subsea wellbore is schematically illustrated. A primary conductor 91 extends downward into the seabed. PGB 40 is run in and installed with conductor 91, and thus, PGB 40 is mounted to the upper end of conductor 91 with hub 47 in position “A”. Wellhead 95 is secured within conductor 91 and comprises an upward facing male connector or hub 96 at its upper end. As shown in FIG. 7A, during drilling operations, a BOP stack 100 is mounted to wellhead 95. In particular, BOP stack 100 includes a downward facing female connector 101 that releasably engages hub 96. In general, connector 101 may comprise any suitable hydraulically actuated releasable wellhead-type mechanical connector that is compatible with wellhead hub 96. Examples of suitable connectors include, without limitation, the H-4® profile subsea connector available from VetcoGray Inc. of Houston, Tex. or the DWHC profile subsea connector available from Cameron International Corporation of Houston, Tex. As will be described in more detail below, BOP stack 100 has been modified and is rotationally oriented in a specific position relative to PBG 40 to enable proper alignment of tubing hanger 10 and production tree 20 relative to PGB 40.

Moving now to FIG. 7B, after drilling operations, dual bore tubing hanger 10 is run through BOP stack 100 and set in wellhead 95. In particular, annular shoulder 19 on the outside of tubing hanger body 11 is seated against a mating annular seat 97 provided on the inside of wellhead 95. Strings 12, 13 extend downhole from hanger body 11.

Moving now to FIG. 7C, once tubing hanger 10 is set in wellhead 95, BOP stack 100 is removed from wellhead 95 by hydraulically actuating connector 101 to unlock and release hub 96. Before removing BOP stack 100 and until connection of production tree 20 to wellhead 95, bores 14, 16 are temporarily closed (e.g., closed with valves in tubing strings 12, 13 or plugs run with wireline) to isolate the flow of hydrocarbons from the well. Next, as shown in FIG. 7D, production tree 20 is lowered subsea and mounted to wellhead 95 via engagement of connector 22 and hub 96. Tree 20 is rotationally oriented such that stabbing members 24, 26 are aligned with and engage mating counterbores 17, 18, respectively, and simultaneously, connector 32 is aligned with and engages mating hub 46 of jumper spool 43 as tree 20 is connected to wellhead 95. Following connection of tree 20 to wellhead 95, mating engagement of stabbing members 24, 26 and counterbores 17, 18, respectively, and mating engagement of connector 32 and hub 46, jumper 50 is lowered subsea and connected to jumper spool 43 and manifold 60. In particular, connector 52 is releasably coupled to hub 47 and connector 53 is releasably coupled to hub 61.

Referring now to FIGS. 6 and 7D, as previously described, the particular positioning of hub 47 in position “A” is vital during installation of conventional PGB 40. To locate hub 47 in position “A”, PGB 40 is rotationally oriented at a particular position during installation with primary conductor 91. To enable simultaneous alignment of (a) production spool connector 32 of production tree 20 and jumper spool hub 46 of PGB 40, and (b) stabbing members 24, 26 of production tree 20 and counterbores 17, 18, respectively, of tubing hanger 10, tubing hanger 10 and production tree 20 must be rotationally oriented in specific positions relative to PGB 40. Thus, the desired positioning of hub 47 of jumper spool 43 dictates the proper rotational orientation of tubing hanger 10 and production tree 20. Accordingly, conventional BOP stacks are modified to include alignment mechanism(s) to facilitate the orientation of the BOP stack relative to the PGB and the orientation of the tubing hanger (as the tubing hanger is run through the BOP stack set within the wellhead) to enable the production tree to engage both the tubing hanger counterbores and the inlet connector of the PGB jumper spool. For example, BOP stack 100 has been modified to include an external orientation funnel (not shown) at its lower end and an inner orientation pin (not shown) extending radially inward about one inch into the main bore of BOP stack 100. The orientation pin is designed to engage a helical orientation recess on the outer surface of the completion landing string that runs in tubing hanger 10. The orientation funnel is configured to rotationally orient BOP stack 100, and hence the orientation pin, to a specific position that allows sliding engagement of the orientation pin and helical recess to rotate tubing hanger 10 into near perfect (i.e., within 1°) rotational orientation relative to PGB 40 as tubing hanger 10 is lowered with the completion landing string. Thus, the orientation funnel orients the pin in BOP stack 100 such that it can properly orient tubing hanger 10 relative to PGB 40 to enable simultaneous engagement of (a) production spool connector 32 of production tree 20 and jumper spool hub 46 of PGB 40, and (b) stabbing members 24, 26 of production tree 20 and counterbores 17, 18, respectively, of tubing hanger 10. Such modifications necessary to properly position and align the tubing hanger and other completion components are time consuming and expensive. However, embodiments described herein offer the potential to eliminate the need for such alignment mechanisms by employing a rotatable PGB in conjunction with a modified jumper spool and/or jumper. In addition, embodiments described herein offer the potential to eliminate the need for complex running, retrieval, installation, and testing tools such as completion landing strings.

Referring now to FIG. 8, an embodiment of a rotatable PGB 40′ is shown. In general, PGB 40′ may comprise any PGB known in the art capable of and configured to be rotated about the conductor and wellhead. Examples of known rotatable PGBs are disclosed in U.S. Pat. No. 6,968,902, which is hereby incorporated herein by reference in its entirety for all purposes. In this embodiment, rotatable PGB 40′ includes a annular downward facing female connector 41′, a support frame 42′ disposed about and extending radially from connector 41′, and an alignment spool 43′ mounted to support frame 42′. Connector 41′ is configured to be disposed about the wellhead and the upper end of the primary conductor, rotated about wellhead 95 and conductor 91, and releasably locked to the primary conductor at the desired rotational position. For example, connector 41′ may be configured similarly to ring 125 disclosed in U.S. Pat. No. 6,968,902.

Alignment spool 43′ is a rigid fluid conduit including a radially inner inlet end 43a′ and a radially outer outlet end 43b′. Each end 43a′, 43b′ comprises an upward facing male connector or hub 46, 47, respectively, each as previously described. Hub 46 is configured to releasably engage mating female connector 32 of production spool 30, and hub 47 is configured to releasably engage mating female connector 52 of jumper 50. Although connectors 46, 47 are designed for vertical connections in this embodiment, in other embodiments, one or both of the connectors on the alignment spools (e.g., connectors 46, 47 on the ends of alignment spool 43′) may be designed for horizontal connections.

As previously described, jumper spool 43 of conventional PGB 40 is a rigid linear conduit fixed in a radial orientation relative to corresponding connector 41. However, in this embodiment, alignment spool 43′ is custom built and includes a non-linear deviation or bend 44′ between ends 43a′, 43b′. As a result, alignment spool 43′ mounted to frame 42′ includes a first portion 44a′ extending from end 43a′ to deviation 44′ and a second portion 44b′ extending from end 43b′ to deviation 44′. First portion 44a′ is oriented at an angle a relative to second portion 44b′. As will be described in more detail below, angle a can be varied as necessary to enable simultaneous connection between hub 46 and connector 32, hub 47 and connector 52, and connector 53 and hub 61. In some cases, the alignment spool (e.g., spool 43′) may include more than one deviation (e.g., deviation 44′). Further, although deviation 44′ is shown as a discrete bend, in general, the deviation (e.g., deviation 44′) may have any non-linear geometry such as an elbow, a smooth curve, an arcuate shape, etc.

Referring now to FIGS. 9A-9D, sequential schematic illustrations of an embodiment of a completion operation employing rotatable PGB 40′ in accordance with the principles described herein is shown. In FIG. 9A, the installation and landing of tubing hanger 10 in wellhead 95 secured to primary conductor 91 is shown. For purposes of clarity, the BOP stack is not shown in FIG. 9A, although it should be appreciated that tubing hanger 10 is run through the BOP stack. In FIG. 9B, the installation of rotatable PGB 40′ is shown. In FIG. 9C, production tree 20 is shown being installed following removal of the BOP stack, and PGB 40′ is shown being rotated during installation of tree 20 to align hub 46 with connector 32 of production spool 20. In FIG. 9D, the connection of jumper 50 to alignment spool 43′ and manifold 60 is shown. As is shown in sequential FIGS. 9A-9D and will be described in more detail below, in this embodiment, rotatable PGB 40′ is not run and installed with primary conductor 91. Rather, in this embodiment, PGB 40′ is installed during completion after running dual bore tubing hanger 10.

Referring first to FIG. 9A, following drilling operations, dual bore tubing hanger 10 is run through the BOP stack mounted to wellhead 95 and set in wellhead 95 as previously described. Due to the use of rotatable PGB 40′ and custom built alignment spool 43′ described in more detail below, tubing hanger 10 can be disposed in any rotational orientation. In other words, tubing hanger 10 can be installed without concern for its rotational orientation. Accordingly, the BOP stack need not be modified to enable a specific orientation of tubing hanger 10. Thus, the alignment mechanism in the BOP stack (e.g., orientation funnel, orientation pin, etc.) can be eliminated.

Moving now to FIG. 9B, with tubing hanger 10 set in wellhead 95, the BOP stack is removed from wellhead 95. Bores 14, 16 are temporarily closed (e.g., with plugs run on wirelines or valves within tubing hanger 10) until production tree 20 is connected to wellhead 95. With the BOP stack removed, the rotational orientation of tubing hanger 10 is determined with techniques known in the art (e.g., with subsea ROVs and associated metrology). Based on the final positions of tubing hanger 10 and manifold hub 61, alignment spool 43′ is custom built and installed on frame 42′ at the surface. The number and type of deviations 44′ in alignment spool 43′ are selected to enable (a) positioning of hub 46 such that production tree 20 can simultaneously mate and engage tubing hanger 10 and hub 46, and (b) positioning hub 47 in position “A” such that jumper 50 can connect to both hubs 47, 61 while being located in a desirable position (e.g., so as not to interfere with neighboring wells). Thus, alignment spool 43′ is custom designed and constructed based on the final positions of tubing hanger 20 and the desired position “A” for hub 47.

With alignment spool 43′ built and installed on frame 42′, rotatable PGB 40′ is lowered subsea and coupled to conductor 91. Next, PGB 40′ is rotated about conductor 91 and wellhead 95 to align hub 46 with tubing hanger 10 such that production tree 20 can simultaneously mate and engage tubing hanger 10 and hub 46. Rotation of PGB 40′ can be performed with a subsea ROV, and proper alignment of PGB 40′ can be checked/confirmed using known techniques such as laser orientation.

Moving now to FIG. 9C, with PGB 40′ aligned with tubing hanger 10, production tree 20 is lowered subsea and installed. In particular, tree 20 is rotationally oriented such that stabbing members 24, 26 are aligned with mating counterbores 17, 18, respectively, and connector 32 is aligned with hub 46. As previously described, angle a between sections 44a′, 44b′ of alignment spool 43′ is selected such that hub 47 is located in position “A” when hub 46 is aligned with connector 32, even though connector 32 is circumferentially offset from hub 47.

With stabbing members 24, 26 aligned with counterbores 17, 18, respectively, and hub 46 aligned with connector 32, production tree 20 is mounted to wellhead 95 via engagement of connector 22 and hub 96, stabbing members 24, 26 are seated in counterbores 17, 18, respectively, and connector 32 is releasably connected to mating hub 46. Next, jumper 50 is lowered subsea and connected to alignment spool 43′ and manifold 60. In particular, connector 52 is releasably coupled to hub 47 and connector 53 is releasably coupled to hub 61. Although tubing hanger 10 and production tree 20 are circumferential offset from hub 47, deviation 44′ in alignment spool 43′ enables hub 47 to be disposed in position “A” and hub 46 to be aligned with connector 32.

In the manner described, embodiments described herein eliminate the need for modification of a BOP stack to include alignment mechanisms to rotationally orient a multi bore tubing hanger within a wellhead in a particular orientation. In particular, variations in the rotational orientation of the tubing hanger within the wellhead are accommodated by employing a modified/customized alignment spool (based on the final installed positions of the tubing hanger and the subsea manifold) mounted to a rotatable production guide base. In general, modifications to the jumper spool as described herein are simpler, less time consuming, and less expensive that the conventional modification of the BOP to include alignment mechanisms to orient the tubing hanger. In addition, since rotational orientation of the tubing hanger is generally irrelevant, complex running, retrieval, installation, and testing tools such as completion landing strings can be eliminated, thereby expanding the appropriate choices for the rig to perform the job.

In the embodiment shown in FIGS. 9A-9D, alignment spool 43′ included a single deviation 44′ to account for the slight circumferential misalignment of tubing hanger 10 and production tree 20 relative to manifold hub 61 and the desired position “A” of hub 47. However, in other embodiments, the custom built alignment spool (e.g., spool 43′) may include any number of deviations, bends, elbows, or the like necessary to orient the outlet hub of the alignment spool (e.g., hub 47) in the desired position “A”. For example, referring now to FIGS. 10A-10D, embodiments of rotatable PGBs 40-1, 40-2, 40-3, 40-4, respectively, that include a connector 41′ and support frame 42′ as previously described. However, PGBs 40-1, 40-2, 40-3, 40-4 include alignment spools 43-1, 43-2, 43-3, 43-4, respectively, that accommodate a variety of different, exemplary misalignment scenarios. In FIG. 10A, alignment spool 43-1 extends across frame 42′ and includes one deviations 44′ to account for about a 45° misalignment between outlet hub 47 of alignment spool 43-1 and the desired position “A”. In FIG. 10B, alignment spool 43-2 extends across frame 42′ and includes two deviations 44′ to account for about a 125° misalignment between outlet hub 47 of alignment spool 43-2 and the desired position “A”. In FIG. 10C, alignment spool 43-3 extends across frame 42′ and includes three deviations 44′ to account for about a 180° misalignment between outlet hub 47 of alignment spool 43-3 and the desired position “A”. In FIG. 10D, alignment spool 43-4 extends across frame 42′ and includes one deviation 44′ to account for about a −120° misalignment between outlet hub 47 of alignment spool 43-4 and the desired position “A”. Each rotatable PGB 40-1, 40-2, 40-3, 40-4 is installed in the same manner as rotatable PGB 40′ previously described. Since frame 42′ extends around and radially outward from connector 41′, frame 42′ and provide sufficient support to the alignment spool (e.g., alignment spool 43-1, 43-2, 43-3, 43-4) regardless of the specific positions of connectors 46, 47. In the embodiments shown in FIGS. 10A-10D, alignment spools 43-1, 43-2, 43-3, 43-4 are custom built to accommodate specific, exemplary misalignment scenarios. However, in general, customization of the alignment spool can be made to suit any desired position of the outlet hub (e.g., hub 47) regardless of the rotational orientation of the dual bore tubing hanger (e.g., tubing hanger 10).

While preferred embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teachings herein. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the systems, apparatus, and processes described herein are possible and are within the scope of the invention. For example, the relative dimensions of various parts, the materials from which the various parts are made, and other parameters can be varied. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims. Unless expressly stated otherwise, the steps in a method claim may be performed in any order. The recitation of identifiers such as (a), (b), (c) or (1), (2), (3) before steps in a method claim are not intended to and do not specify a particular order to the steps, but rather are used to simplify subsequent reference to such steps.

Claims

1. A system for producing hydrocarbons from a subsea wellbore, the system comprising:

a primary conductor extending into the seabed;

a wellhead disposed at an upper end of the primary conductor;

a multi bore tubing hanger seated in the wellhead, the tubing hanger including at least a first bore and a second bore;

a production tree mounted to the wellhead, wherein the production tree includes a spool body, a first stabbing member extending from the spool body and disposed in the first bore, a second stabbing member extending from the spool body and disposed in the second bore, and a production spool extending radially from the spool body, wherein the production spool has an end comprising a connector;

a rotatable production guide base coupled to the primary conductor, wherein the production guide base is configured to rotate about the wellhead and releasably lock on to the upper end of the conductor, wherein the production guide base includes an annular connector disposed about the primary conductor, a support frame extending radially from the annular connector, and a rigid alignment spool mounted to the support frame;

wherein the alignment spool has a first end comprising a first connector releasably coupled to the connector of the production spool, a second end comprising a second connector, and non-linear deviation positioned between the first end and the second end.

2. The system of claim 1, wherein the second connector of the alignment spool is coupled to an inlet end of a rigid jumper.

3. The system of claim 2, wherein the jumper has an outlet end coupled to a manifold.

4. The system of claim 1, wherein the alignment spool has a first section extending linearly from the first end to the deviation and a second section extending linearly from the second end to the deviation, wherein the first section is oriented at an angle a relative to the second section.

5. The system of claim 4, wherein the angle a is greater than 90° and less than 180°.

6. The system of claim 1, wherein the support frame is disposed about the annular connector.

7. The system of claim 1, wherein the alignment spool includes a plurality of non-linear deviations.

8. A method for completing a subsea well, the method comprising:

(a) running a multi bore tubing hanger into a wellhead, the tubing hanger including a first bore and a second bore;

(b) determining the rotational orientation of the tubing hanger after (a);

(c) constructing an alignment spool based on the rotational position of the tubing hanger; and

(d) coupling the alignment spool to a rotatable production guide base, wherein the production guide base is configured to rotate about the wellhead.

9. The method of claim 8, wherein (c) comprises constructing the alignment spool to include a non-linear deviation positioned between a first end of the alignment spool and a second end of the alignment spool.

10. The method of claim 9, wherein the alignment spool has a first section extending from the first end to the deviation and a second section extending from the second end to the deviation, wherein the first section is oriented at an angle a relative to the second section.

11. The method of claim 10, wherein the angle a is greater than 90° and less than 180°.

12. The method of claim 8, wherein the rotatable production guide base includes an annular connector and a support frame extending radially from the annular connector; and

wherein (d) comprises mounting the alignment spool to the support frame.

13. The method of claim 12, further comprising:

(e) lowering the rotatable production guide base subsea after (d);

(f) positioning the annular connector of the rotatable production guide base about the wellhead;

(g) rotating the production guide base about the wellhead after (f) to facilitate alignment of a first end of the alignment spool with a connector disposed at an end of a production spool of a production tree; and

(h) aligning a first stabbing member of a production tree with the first bore and aligning a second stabbing member of the production tree with the second bore.

14. The method of claim 13, further comprising:

(i) stabbing the first stabbing member into the first bore of the tubing hanger and stabbing the second stabbing member into the second bore of the tubing hanger; and

(j) connecting the connector of the production spool to the first end of the alignment spool.

15. The method of claim 14, further comprising:

(k) connecting an inlet end of a rigid jumper to the second end of the alignment spool; and

(l) connecting an outlet end of the rigid jumper spool to a subsea manifold.

16. A method for completing a subsea well, the method comprising:

(a) running a multi bore tubing hanger into a wellhead, the tubing hanger including a first bore and a second bore;

(b) constructing a rigid alignment spool after (a), wherein the alignment spool has a first end comprising a first connector and a second end comprising a second connector; and

(c) mounting the alignment spool to a support frame of a rotatable production guide base after (b), wherein the production guide base is configured to rotate about the wellhead.

17. The method of claim 16, further comprising:

(d) coupling the rotatable production guide base to the wellhead after (c).

18. The method of claim 16, wherein the alignment spool includes a deviation positioned between the first end and the second end.

19. The method of claim 18, wherein the alignment spool has a first section extending from the first end to the deviation and a second section extending from the second end to the deviation, wherein the first section is oriented at an angle a relative to the second section.

20. The method of claim 19, wherein the angle a is greater than 90° and less than 180°.

21. The method of claim 19, further comprising determining the angle a based on the rotational orientation of the tubing hanger within the wellhead.

22. The method of claim 21, further comprising:

(e) aligning a first stabbing member of a production tree with the first bore and aligning a second stabbing member of the production tree with the second bore;

(f) rotating the production guide base about the wellhead to align a first end of the alignment spool with a connector disposed at an end of a production spool of the production tree.

23. The method of claim 22, further comprising:

stabbing the first stabbing member into the first bore of the tubing hanger and stabbing the second stabbing member into the second bore of the tubing hanger; and

connecting the connector of the production spool to the first end of the alignment spool.

24. The method of claim 21, further comprising:

connecting an inlet end of a rigid jumper to the second end of the alignment spool; and

connecting an outlet end of the rigid jumper spool to a subsea manifold.