STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
Not applicable.
BACKGROUND
1. Field of the Invention
The invention relates generally to offshore drilling and production systems and methods. More particularly, the invention relates to systems and methods for developing offshore oil and gas fields utilizing an offshore free standing top tensioned riser buoyancy can system.
2. Background of the Technology
Marine risers are typically employed offshore to provide a conduit between an offshore vessel (e.g., platform, floating drilling and/or production vessel, etc.) and the seabed. For example, marine drilling risers are used to guide a drillstring and convey fluids used during various offshore drilling operations, and marine production risers establish a flow path for hydrocarbons produced from a subsea well to the vessel located at the sea surface.
Due to the weight of a marine riser, a certain amount of vertical force is necessary to keep the riser upright and prevent it from dropping to the seafloor 20. Moreover, vertical marine risers are typically over-tensioned beyond their weight to limit deflections and stresses in the riser resulting from exposure to the dynamic ocean environment. Accordingly, such vertically arranged and tensioned risers are commonly known as “top tensioned risers.”
At or proximal the surface, vertical risers are coupled to the offshore vessel. Since the vessel is subject to heave motions induced by waves, the risers are coupled to the vessel in a manner that does not transfer the heave motions of the vessel to the risers. Two conventional riser tensioning devices are hydraulic actuators and buoyancy cans. For a hydraulic riser tensioner, hydraulic actuators are attached between the vessel and the top of the riser. Vessel heave is compensated by actuator stroke, while the riser tension is maintained at a substantially constant level by actively controlling the hydraulic pressure. Buoyancy can tensioners, on the other hand, are passive devices attached to the upper portion of risers. The riser tension is provided by buoyancy, while vessel heave is compensated by allowing the buoyancy can to slide up and down relative to the host vessel in sleeve-type guides. Conventionally, both hydraulic tensioners and buoyancy cans are applied to a single riser. Where a plurality of risers is to be supported, each riser is individually tensioned by a separate tensioner.
The upper ends of top tensioned risers and associated buoyancy cans are typically disposed within the perimeter of the associated surface vessel (e.g., semi-submersible platform, spar, tension-leg platform, etc.). For example, the upper portion of the buoyancy cans usually extends vertically upward into the middle of the hull of the offshore vessel as is shown and described in U.S. Patent App. Pub. No. 2009/0095485 filed Oct. 13, 2008 and entitled “Tube Buoyancy Can System,” which is hereby incorporated herein by reference in its entirety. This arrangement limits the flexibility of the surface vessel as the vessel cannot be disconnected and move away from the buoyancy cans and the risers as they extend through the vessel itself. Consequently, this conventional arrangement presents limitations on methods for developing offshore oil and gas fields. Specifically, the conventional process for bringing a field into production involves a number of sequential definitional steps as follows: (1) geological exploration of the field; (2) appraisal drilling of wells within the field; (3) defining the plan for development of the field; (4) executing the plan; and (5) operating the field.
Geological exploration of a field involves various preliminary geological investigations and sparse 2D seismic work followed by a 3D seismic survey. If a prospect looks promising, an exploratory well is drilled. During this process, various reservoir models are generated from the seismic data and then updated with information checked against the well results. Once the reservoir has been appraised, a plan for the development of the field is defined. The plan typically includes identification of: (a) the number and location of wells to be drilled; (b) the type of surface facilities needed; (c) the type of riser systems; and (d) the export means (e.g. pipelines, tankers, etc.) that will be employed to drill and produce the field. These plans are all based on the reservoir information that is available, which may be incomplete or inaccurate. Once defined, the plan for development is executed, which comprises the procurement, construction, and installation of equipment, infrastructure, and systems needed to operate the field.
During the operation of the field, conditions within the field may change or may not be exactly what was predicted during the evaluation and planning phases. Because most of the infrastructure, equipment and systems specified for the field were designed and built to operate under an anticipated set of conditions, any change to these conditions may cause the equipment to operate at less than optimal efficiency. This loss in efficiency leads to lower levels of production and therefore a significant loss to the operator of the field.
To address these issues, alternative methods have been formulated to develop an oil and gas field in a way that avoids the enormous capital costs associated with having infrastructure, equipment, and systems in place which may no longer efficiently produces a given well or wells. Examples of such alternative methods are disclosed in U.S. Pat. No. 8,122,965 entitled “Methods for Development of an Offshore Oil and Gas Field,” which is hereby incorporated herein by reference in its entirety. In particular, U.S. Pat. No. 8,122,965 discloses the use of a lead offshore drilling and production vessel for drilling and producing test wells, followed by the formulation of an initial development plan. In other words, the initial development plan for the offshore field is formulated after initiating production; actual production data is used to develop the plan. Thus, a more suitable secondary production vessel can be selected according to the development plan based on evaluation of actual production from the well. Once selected, the secondary production vessel replaces the lead drilling and production vessel for the long-term production of the field. Thus, the well is “passed” from the lead drilling and production vessel to the secondary production vessel.
The common approach to drill and produce a well from a single vessel is with a surface BOP and vertically tensioned riser systems. However, for top tension riser buoyancy can systems coupled to the surface vessel and disposed within the perimeter of the surface vessel, passing the well to a secondary production vessel may be difficult if not practically impossible since it would require removal and recompleting of the wells. Accordingly, there remains a need in the art for systems and methods for transferring top tensioned risers between different surface vessels to facilitate development of an offshore field.
BRIEF SUMMARY OF THE DISCLOSURE
These and other needs in the art are addressed in one embodiment by a method for developing an offshore field. In an embodiment, the method comprises (a) coupling a plurality of top-tensioned risers to a first vessel at a first location. In addition, the method comprises (b) decoupling the first vessel from the plurality of top-tensioned risers after (a). Further, the method comprises (c) coupling a second vessel to the plurality of top-tensioned risers after (b) at the first location.
These and other needs in the art are addressed in another embodiment by a system. In an embodiment, the system comprises a relocatable offshore vessel including a hull, a topsides supported by the hull, and a bay disposed along the outer perimeter of the offshore vessel. In addition, the system comprises a buoyancy can system disposed in the bay. The buoyancy can system supports a plurality of top-tensioned risers. Further, the system comprises a coupling system releasably coupling the vessel to the buoyancy can system.
These and other needs in the art are addressed in another embodiment by a method for passing a plurality of top-tensioned risers between a first offshore vessel and a second offshore vessel. In an embodiment, the method comprises (a) supporting a plurality of top-tensioned risers with a buoyancy can system. In addition, the method comprises (b) receiving the buoyancy can system and the top-tensioned risers into a bay disposed along the outer perimeter of the first offshore vessel. Further, the method comprises (c) withdrawing the buoyancy can system and the top-tensioned risers from the bay. Still further, the method comprises (d) receiving the buoyancy can system and the top-tensioned risers into a bay disposed along the outer perimeter of the second offshore vessel after (c).
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 disclosed embodiments, reference will now be made to the accompanying drawings in which:
FIG. 1 is a schematic side view of an embodiment of a buoyancy can system in accordance with the principles described herein releasably coupled to a relocatable offshore structure;
FIG. 2 is a schematic top view of the buoyancy can system and the offshore structure of FIG. 1;
FIG. 3 is a schematic side view of the buoyancy can system of FIG. 1;
FIG. 4 is a perspective view of the buoyancy can system of FIG. 1;
FIG. 5 is a schematic top view of the buoyancy can system of FIG. 1;
FIG. 6 is a schematic top view of one of the support members of the offshore structure of FIG. 1;
FIG. 7 is an end view of one of the horizontal bumpers of FIG. 6;
FIG. 8 is a side view of one of the vertical bumpers of FIG. 6;
FIG. 9 is a schematic view of the coupling system of FIGS. 1;
FIGS. 10-16 are sequential schematic top views illustrating the transfer of the buoyancy can system of FIG. 1 from the offshore structure of FIG. 1 to a secondary relocatable offshore structure;
FIG. 17 is a schematic side view of the buoyancy can system of FIG. 3 releasably coupled to a spar platform;
FIG. 18 is a schematic top view of the buoyancy can system and the spar platform of FIG. 17;
FIG. 19 is a schematic side view of the buoyancy can system of FIG. 3 releasably coupled to a semi-submersible platform; and
FIG. 20 is a schematic top view of the buoyancy can system and the semi-submersible platform of FIG. 19.
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, an embodiment of a buoyancy can system 100 for tensioning an arrangement of vertical risers 180 is shown releasably coupled to a lead drilling and production vessel 200. In this embodiment, vessel 200 is a relocatable tower as described in U.S. patent application Ser. No. 13/288,426 filed Nov. 3, 2011, and entitled “Offshore Tower for Drilling and/or Production,” which is hereby incorporated herein by reference in its entirety for all purposes. More specifically, vessel 200 includes an adjustably buoyant hull 210 that supports a deck or topsides 220 above the sea surface 10.
Hull 210 has a central or longitudinal axis 215 and includes a plurality of radially outer columns 211 uniformly radially spaced from axis 215 and a radially inner or center column 212 disposed between columns 211 and coaxially aligned with axis 215. Elongate cylindrical columns 211, 212 are oriented parallel to each other and axis 215. Further, each column 211, 212 is adjustably buoyant. In other words, the buoyancy of each column 211, 212 can be adjusted as desired. In this embodiment, hull 210 includes four uniformly circumferentially spaced columns 211 generally arranged in a square configuration and one center column 212 disposed in the center of columns 211. Columns 211 are coupled together by a plurality of truss members 213 extending between adjacent columns 211, and thus, columns 211 do not move rotationally or translationally relative to each other. However, center column 212 is axially moveable relative to columns 211. In particular, center column 212 can be axially extended and retracted relative to columns 211. The lower end of center column 212 includes a suction anchor 214 configured to releasably engage the sea bed in the extended position, thereby releasably anchoring hull 210 to the sea floor 20. In FIG. 1, center column 212 is shown axially extended relative to columns 211 and in engagement with the sea floor 20. In the refracted position, center column 212 is moved axially upward between columns 211 towards topsides 220, and is disengaged from the sea floor 20, thereby allowing vessel 200 to be moved to a different offshore location. Center column 212 may be transitioned between the extended and refracted positions by any suitable means including, without limitation, by adjusting the buoyancy of center column 212 in combination with pulling/releasing column with a wireline extending from the upper end of center column 212 to topsides 220. As will be described in more detail below, although vessel 200 is a tower in this embodiment, in general, buoyancy can system 100, and hence vertical risers 180, may be releasably coupled to any type of relocatable marine structure or vessel including, without limitation, a floating platform (e.g., a spar platform, a semi-submersible platform, a tension leg platform), a drilling and/or production ship, or the like.
Referring still to FIGS. 1 and 2, vessel 200 includes a generally rectangular bay 230 that releasably houses buoyancy can system 100. Bay 230 is disposed along the outer perimeter of vessel 200 and is defined by a pair of rigid horizontal support members 231 cantilevered from hull 210 and a rigid horizontal support member 232 extending between the inner ends of members 231. In addition, a skiddable derrick 221 is moveably coupled to topsides 220. As is known in the art, a skiddable derrick (e.g., derrick 221) is a derrick that can be moved across the topsides (e.g., topsides 220) to support weight and/or drill at different locations relative to the topsides. In this embodiment, derrick 221 can be moved between a first position 221a generally over the center of topsides 220 and a second position 221b (shown in phantom) cantilevered from the outer perimeter of the topsides 220 over bay 230. Thus, when buoyancy can system 100 is disposed in bay 230, derrick 221 is positioned over buoyancy can system 100 in the second position 221b.
As best shown in FIGS. 1 and 2, contrary to conventional buoyancy cans and associated top-tensioned risers that extend upward through the middle of the hull of the associated offshore platform, in this embodiment, buoyancy can system 100 is disposed in bay 230 laterally adjacent vessel 200. Thus, as will be described in more detail below, lead drilling and production vessel 200 can be de-coupled from system 100, transported to a different location, and secondary production vessel can be transported to system 100 and coupled thereto to continue production via risers 180.
Referring now to FIGS. 3-5, buoyancy can system 100 is shown free-standing in the open water after vessel 200 has been decoupled and moved therefrom. Buoyancy can system 100 supports one or more top tension risers 180, which extend subsea to sea floor 20. In general, risers 180 may be marine drilling or production risers. Buoyancy provided by system 100 is sufficient to completely support each riser 180 coupled thereto, even when system 100 is not coupled to any other offshore structure or vessel as shown in FIG. 3. The tension load applied to risers 180 by buoyancy can system 100 is equal to the net buoyancy of system 100 (i.e., the total buoyancy of system 100 minus the weight of system 100), which, as described below, is selectably adjustable to ensure that each riser 110 coupled to system 100 is tensioned to the desired degree.
Referring still to FIGS. 3-5, buoyancy can system 100 includes a plurality of vertically oriented, elongate buoyancy cans 110 disposed within a generally rectangular frame 120. Cans 110 are rigidly coupled to one another and to frame 120 such that cans 110 and frame 120 move together as a single unit in response to external forces (e.g., wind, waves, etc.). In other words, cans 110 and frame 120 do not move translationally or rotationally relative to each other. As best shown in FIG. 5, in this embodiment, cans 110 are coupled to each other and to frame 120 with a plurality of rigid girders 150.
Referring again to FIGS. 3-5, the upper ends of risers 180 are disposed in the interstitial spaces 130 formed between cans 110 and frame 120. In addition, the upper ends of risers 180 are rigidly coupled to one another, as well as to frame 120 and cans 110. As a result, the upper ends of risers 180, cans 110, and frame 120 move together as a single unit in response to external forces. In other words, the upper ends of risers 180, cans 110, and frame 120 do not move translationally or rotationally relative to each other. As best shown in FIG. 5, in this embodiment, the upper ends of risers 180 are coupled to each other, to frame 120, and to cans 110 with a plurality of rigid girders 151. Although risers 180 are positioned within interstitial spaces 130 between cans 110 in this embodiment, in other embodiments, one or more of the risers (e.g., risers 180) extend coaxially through the corresponding buoyancy cans (e.g., can 110).
Referring again to FIGS. 3-5, in general, each buoyancy can 110 may comprise any buoyancy can known in the art. In this embodiment, each buoyancy can 110 is tubular in shape having an enclosed upper end 110a and an open lower end 110b. Each upper end 110a is generally enclosed, but includes a port that may be opened and closed as desired to adjust the amount of water ballast, and hence buoyancy, of the corresponding can 110. Each lower end 110b is completely open such that sea water, which functions as ballast, is free to flow in and out of each can 110. The inside of each buoyancy can 110 is preferably devoid of all structures that may substantially inhibit the free flow of sea water through lower end 110b. The buoyancy of each can 110 is adjusted by varying the relative volumes of sea water and air within the can 110. Specifically, to increase the volume of sea water within a can 110 (and decrease the volume of air in the can 110), thereby decreasing its buoyancy, the opening in the upper end 110a of the can 110 is opened to allow air to escape the can 110 through the opening and sea water to enter the can 110 through open lower end 110b; and to increase the volume of air within a can 110 (and decrease the volume of sea water in the can 110), thereby increasing its buoyancy, the opening in the upper end 110a of the can 110 is closed and sealed to prevent air from escaping the can 110 and a pressurized gas, such as air, is pumped into the can 110 to displace a desired amount of sea water out of open lower end 110b. Examples of buoyancy cans that operate in this manner are disclosed in U.S. Patent App. Pub. No. 2009/0095485 filed Oct. 13, 2008 and entitled “Tube Buoyancy Can System,” which is hereby incorporated herein by reference in its entirety.
Referring now to FIG. 4, in this embodiment, buoyancy can system 100 also functions to support a production manifold 140 that is coupled to and receives produced fluids from risers 180, and supplies the produced fluids to a production vessel (e.g., vessel 200) via a plurality of outlet flow lines 141. In this embodiment, outlet flow lines 141 include a high pressure flow line 141a, an intermediate pressure flow line 141b, a low pressure outflow line 141c, and a test flow line 141d as are known in the art. During production of relatively high pressure fluids, typically during early phases of production (i.e., early part of the reservoirs production lifetime), high pressure flow line 141a is used to flow the produced fluids to a production vessel (e.g., vessel 200); during production of intermediate pressure fluids, typically during intermediate phases of production (i.e., during the middle part of a reservoirs production lifetime), intermediate pressure flow line 141b is used to flow the produced fluids to a production vessel (e.g., vessel 200); during production of relatively low pressure fluids, typically during later phases of production (i.e., during the later part of a reservoirs production lifetime), low pressure flow line 141c is used to flow the produced fluids to a production vessel (e.g., vessel 200); and test flow line 141d is used to isolate production from any one of the risers 180 during any phase of production. Although manifold 140 is mounted to buoyancy can system 100 in this embodiment, in other embodiments, the manifold (e.g., manifold 140) may be mounted to the production vessel (e.g., vessel 200), with flexible flow lines supplying produced fluids from the risers (e.g., risers 180) to the manifold.
As previously described, buoyancy can system 100 is designed to be releasably coupled to relocatable offshore vessels (e.g., vessel 200). When system 100 is coupled to an offshore vessel, relative vertical movement between system 100 and the vessel is generally permitted, especially if the vessel is a floating vessel. However, relative lateral movement between system 100 and the vessel is preferably minimized. In embodiments described herein, lateral movement of system 100 relative to vessel 200 (or other vessel) is limited by members 231, 232 defining bay 230.
Referring now to FIGS. 2 and 6, members 231, 232 are attached to hull 210. In particular, each support member 231 has a first end 231a coupled to hull 210, a second end 231b distal hull 210, a first axial segment or portion 231 c extending from end 231 a, and a second axial segment or portion 231d extending from end 231b to portion 231c. As best shown in FIGS. 2 and 6, second portions 231 d are angled outward relative to first portions 231c, thereby defining a funnel that functions to guide buoyancy can system 100 into bay 230 generally between portions 231c. Member 232 extends parallel to the perimeter of hull 210 between first portions 231c of members 231. In particular, member 232 is oriented perpendicular to first portions 231c, thereby giving bay 230 its generally rectangular shape.
As best shown in FIGS. 6-8, a fender assembly 235 mounted to the inside of each member 231, 232 provides a flexible interface between support members 231, 232 and buoyancy can system 100. Each fender assembly 235 includes a plurality of horizontal fenders or bumpers 236 and a plurality of vertical fenders or bumpers 237, each coupled to the associated support member 231, 232. Bumpers 236, 237 are designed to slidingly engage and cushion buoyancy can system 100 as it is moved into and out bay 230 between support members 231, 232. Bumpers 236, 237 are preferably made of a flexible resilient material, and further, are preferably coupled to support members 231 with a flexible resilient material. For example, in this embodiment, each bumper 236, 237 comprises an elastomeric material (e.g., rubber) and is coupled to its corresponding support member 231 with an elastomeric material (e.g., rubber). The inner surface of each bumper 236, 237 facing bay 230 and buoyancy can system 100 disposed therein preferably comprises a low friction material such as an ultra-high-molecular-weight polyethylene (UHMW) to allow buoyancy can system 100 to slidingly engage bumpers 236, 237.
Referring now to FIGS. 2 and 9, vessel 200 includes a coupling system 240 that releasably couples vessel 200 to buoyancy can system 100. In this embodiment, coupling system 240 includes a plurality of laterally spaced tensioning assemblies 241 that connect to buoyancy can system 100, and operate together to pull buoyancy can system 100 into bay 230 and release buoyancy can system 100 from bay 230. As best shown in FIG. 9, each tensioning assembly 241 includes a winch 242 mounted to vessel 200 between support members 231 in top view, a wireline or cable 243, and a pulley 244. Wireline 243 is wrapped around winch 242, extends around pulley 244, and has a distal end 243a releasably attached to frame 120 of buoyancy can system 100. Winch 242 is anchored to hull 210 and controls the amount of tension or slack in wireline 243. With wireline 243 attached to buoyancy can system 100, winch 242 applies tension to wireline 243 to pull vessel 200 toward buoyancy can system 100 to enable vessel 200 to receive system 100 within bay 230, and reduces tension and/or applies slack to wireline 243 to enable vessel 200 to be moved away from buoyancy can system 100, thereby allowing system 100 to exit bay 230.
Referring now to FIGS. 10-16, an embodiment of a method for transferring or passing buoyancy can system 100 and risers 180 coupled thereto from lead drilling and production vessel 200 to a secondary production vessel 300 is shown. Vessel 300 is the same as vessel 200 previously described except that vessel 300 is specifically designed for production operations and is tailored to accommodate the actual production from risers 180 following drilling and initiation of production with vessel 200. Thus, vessel 300 includes a hull 210, topsides, 220, skiddable derrick 221, bay 230 defined by support members 231, 232, and coupling system 240, each as previously described. In FIG. 10, buoyancy can system 100 is shown coupled to vessel 200 with coupling system 240 and disposed in bay 230; in FIGS. 11-13, buoyancy can system 100 is shown exiting bay 230 and being decoupled from vessel 200; in FIG. 14, buoyancy can system 100 is shown freestanding following decoupling of vessel 200 therefrom and before coupling of vessel 300 thereto; in FIGS. 15 and 16, buoyancy can system 100 is shown coupled to vessel 300 and moved into bay 230 of vessel 300. When system 100 is coupled to vessel 200, drilling or production operations may be performed with vessel 200 via risers 180, and when system 100 is coupled to vessel 300, production operations may be performed with vessel 300 via risers 180. When buoyancy can system 100 is not coupled to either vessel 200, 200 and is “standalone,” risers 180 are shut-in with manifold 140 and no drilling or production operations are performed.
Referring first to FIG. 10, buoyancy can system 100 and risers 180 coupled thereto are disposed in bay 230 of vessel 200 and coupled to vessel 200 with coupling system 240. Support members 231, 232 and fender assemblies 60 limit the lateral movement of buoyancy can system 100 and coupling system 240 limits the gap between vessel 200 and buoyancy can system 100. In particular, winch 242 includes an auto-tensioning system that enables winch 242 to automatically adjust tension and slack as necessary to maintain the gap between buoyancy can system 100 and vessel 200 as vessel 200 and/or buoyancy can system 100 move under environmental loads (e.g., wind, waves, currents, etc.). Relative vertical movement between vessel 200 and system 100 is generally permitted.
Moving now to FIGS. 11-13, to release buoyancy can system 100, risers 180 are shut-in with manifold 140 and outlet flow lines 141 are disconnected from vessel 200. Next, slack is slowly provided to wirelines 243 with winches 242 as vessel 200 is slowly moved away from buoyancy can system 100 (e.g., with tugs), thereby allowing system 100 to exit bay 230. When vessel 200 is at a safe distance from buoyancy can system 100 (i.e., such that there is no risk of vessel 200 impacting buoyancy can system 100 due to environmental loads), wirelines 243 are disconnected from buoyancy can system 100 and vessel 200 can be moved to another location for drilling and/or production operations.
Moving now to FIGS. 14-16, following the decoupling of vessel 200 and buoyancy can system 100, vessel 300 is moved into position to connect to and receive system 100. In particular, vessel 300 is moved towards buoyancy can system 100 with bay 230 generally facing and aligned with system 100. While vessel 300 is still a safe distance away from buoyancy can system 100 (i.e., such that there is no risk of vessel 200 impacting buoyancy can system 100 due to environmental loads), wirelines 243 are connected to buoyancy can system 100, and tension is controllably applied to wirelines 243 with winches 242 to slowly pull vessel 300 towards buoyancy can system 100, thereby moving system 100 into bay 230. Next, outlet flow lines 141 are connected to vessel 300 and valves on manifold 140 are opened to produce from risers 180 to vessel 300. It should be appreciated that risers 180 are coupled to the sea floor 20, and thus, the transfer of buoyancy can system 100 and risers 180 from vessel 200 to vessel 300 occurs at a particular offshore location (i.e., buoyancy can system 100 and risers 180 are not moved during the transfer).
As previously described, vessels 200, 300 are relocatable towers. However, systems and methods described herein for a passing buoyancy can system and associated top-tensioned risers may be employed with any type of relocatable offshore structure or vessel known in the art. For example, in FIGS. 17 and 18, buoyancy can system 100 and associated risers 180 are shown releasably coupled to a floating spar platform 400 including a deck or topsides 220 as previously described and an elongate cylindrical adjustably buoyant hull 410 that that supports topsides 220 above the sea surface 10. Mooring lines 350 couple spar platform 400 to the sea floor 20 such that platform 400 is maintain in a substantially fixed position during drilling and/or production operations. Spar platform 400 can be disconnected from mooring lines 350 or mooring lines 350 can be removed from the sea floor 20 to relocate platform 400 to a different offshore location. A skiddable derrick 221 as previously described is moveably coupled to topsides 220. In addition, platform 400 includes a bay 230 defined by support members 231, 232, and coupling system 240, each as previously described. Platform 400 is releasably coupled to buoyancy can system 100 and associated top-tensioned risers 180 in the same manner as previously described.
As another example, in FIGS. 19 and 20, buoyancy can system 100 is shown releasably coupled to a floating semi-submersible platform 500 including a deck or topsides 220 as previously described and an elongate cylindrical adjustably buoyant hull 510 that that supports topsides 220 above the sea surface 10. Mooring lines 350 couple semi-submersible platform 500 to the sea floor 20 such that platform 500 is maintain in a substantially fixed position during drilling and/or production operations. Semi-submersible platform 500 can be disconnected from mooring lines 350 or mooring lines 350 can be removed from the sea floor 20 to relocate platform 500 to a different offshore location. A skiddable derrick 221 as previously described is moveably coupled to topsides 220. In addition, platform 500 includes a bay 230 defined by support members 231, 232, and coupling system 240, each as previously described. Platform 500 is releasably coupled to buoyancy can system 100 and associated top-tensioned risers 180 in the same manner as previously described.
Embodiments described herein are directed to systems and methods for transferring top tensioned risers from a first or lead offshore vessel to a second offshore vessel. Such embodiments are particularly adapted for use with “dry tree” wells. A “dry tree” generally refers to a well in which the “Christmas Tree” valve assembly is disposed above the water line. Specifically, embodiments disclosed herein make it possible to pass a dry tree well from a lead drilling and production vessel to a secondary production vessel without recompleting the well by releasably coupling the vessels to buoyancy can system 100. Development of a field in this manner allows for more rapid field development (e.g., due to simplification of swapping out vessels without the need to recomplete wells), as well as much less expensive capital expenses up front before the production is known and understood per the methods described in U.S. Pat. No. 8,122,965 filed May 29, 2007 and entitled “Methods for Development of an Offshore Oil and Gas Field,” which is hereby incorporated herein by reference in its entirety.
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 simply subsequent reference to such steps.
Patent Application
20120255736
