OFFSHORE TOP TENSIONED RISER BUOYANCY CAN SYSTEM AND METHODS OF FIELD DEVELOPMENT
A method for developing an offshore field 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.
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This application claims benefit of U.S. provisional patent application Ser. No. 61/472,754 filed Apr. 7, 2011, and entitled “Offshore Top Tensioned Riser Buoyancy Can System and Methods of Field Development,” which is hereby incorporated herein by reference in its entirety.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENTNot applicable.
BACKGROUND1. 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 DISCLOSUREThese 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.
For a detailed description of the disclosed embodiments, reference will now be made to the accompanying drawings in which:
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.
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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
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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.
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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
As another example, in
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.
Claims
1. A method for developing an offshore field, comprising:
- (a) coupling a plurality of top-tensioned risers to a first vessel at a first location;
- (b) decoupling the first vessel from the plurality of top-tensioned risers after (a);
- (c) coupling a second vessel to the plurality of top-tensioned risers after (b) at the first location.
2. The method of claim 1, wherein (b) further comprises moving the first vessel away from the first location;
- wherein (c) comprises moving the second vessel towards the first location.
3. The method of claim 1, further comprises:
- drilling a subsea well through one of the top-tensioned risers with the first vessel after (a) and before (b); and
- producing the subsea well through one of the top-tensioned risers with the second vessel after (c).
4. The method of claim 3, further comprising:
- initiating production from the subsea well through one of the top-tensioned risers with the first vessel after drilling the subsea well with the first vessel.
5. The method of claim 4, further comprising:
- evaluating production from the at least one well after initiating production;
- selecting the second vessel based upon the evaluated production from the subsea well; and
- deploying the second vessel to the first location so as to replace the first vessel.
6. The method of claim 1, further comprising:
- supporting the top-tensioned risers is a buoyancy can system during (a), (b), and (c).
7. The method of claim 6, wherein (a) comprises:
- (a1) coupling a first cable extending from the first vessel to the buoyancy can system; and
- (a2) applying tension to the first cable to move the buoyancy can system into a bay disposed on the outer perimeter of the first vessel.
8. The method of claim 7, wherein (b) comprises:
- (10) reducing the tension on the first cable;
- (b2) pulling the first vessel away from the buoyancy can system to remove the buoyancy can system from the bay; and
- (b3) decoupling the first cable from the buoyancy can system.
9. The method of claim 7, wherein (c) comprises:
- (18) coupling a second cable extending from the second vessel to the buoyancy can system; and
- (c2) applying tension to the second cable to move the buoyancy can system into a bay disposed on the outer perimeter of the second vessel.
10. A system comprising:
- 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;
- a buoyancy can system disposed in the bay, wherein the buoyancy can system supports a plurality of top-tensioned risers; and
- a coupling system releasably coupling the vessel to the buoyancy can system.
11. The system of claim 10, wherein the vessel is an adjustably buoyant tower, an adjustably buoyant spar platform, or an adjustably buoyant semi-submersible platform.
12. The system of claim 10, wherein the bay is defined by a pair of support members extending outward from the vessel, wherein each support member comprises a fender for slidably engaging the buoyancy can system.
13. The system of claim 12, wherein each fender includes a plurality of flexible, resilient bumpers configured to engage the buoyancy can system.
14. The system of claim 13, wherein each bumper is made of an elastomeric material with an inner surface comprising an ultra-high-molecular-weight polyethylene.
15. The system of claim 10, wherein the coupling system comprises:
- a winch mounted to the vessel; and
- a cable extending from the winch to the buoyancy can system;
- wherein the winch is configured to adjust the tension and slack in the cable.
16. The system of claim 10, wherein the buoyancy can system comprises a frame and a plurality of adjustably buoyant buoyancy cans coupled to the frame;
- wherein the top-tensioned risers are coupled to the frame and are positioned between the buoyancy cans.
17. The system of claim 16, wherein a production manifold is disposed on the buoyancy can system.
18. A method for passing a plurality of top-tensioned risers between a first offshore vessel and a second offshore vessel, the method comprising:
- (a) supporting a plurality of top-tensioned risers with a buoyancy can system;
- (b) receiving the buoyancy can system and the top-tensioned risers into a bay disposed along the outer perimeter of the first offshore vessel;
- (c) withdrawing the buoyancy can system and the top-tensioned risers from the bay; and
- (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).
19. The method of claim 18, wheren (b) comprises
- (10) coupling a first cable extending from the first vessel to the buoyancy can system; and
- (b2) applying tension to the first cable to move the buoyancy can system into a bay disposed on the outer perimeter of the first vessel.
20. The method of claim 19, wherein (c) comprises:
- (18) reducing the tension on the first cable;
- (c2) pulling the first vessel away from the buoyancy can system to remove the buoyancy can system from the bay; and
- (c3) decoupling the first cable from the buoyancy can system.
21. The method of claim 20, wherein (d) comprises:
- (18) coupling a second cable extending from the second vessel to the buoyancy can system; and
- (c2) applying tension to the second cable to move the buoyancy can system into a bay disposed on the outer perimeter of the second vessel.
22. The method of claim 21, wherein the tension in the first cable is controlled by a first winch mounted to the first vessel and tension in the second cable is controlled by a second winch mounted to the second vessel.
23. The method of claim 18, wherein each bay is defined by a pair of support members extending outward from the vessel, wherein each support member comprises a fender for slidably engaging the buoyancy can system.
24. The system of claim 23, wherein each fender includes a plurality of flexible, resilient bumpers configured to engage the buoyancy can system.
Type: Application
Filed: Apr 5, 2012
Publication Date: Oct 11, 2012
Applicant: HORTON WISON DEEPWATER, INC. (Houston, TX)
Inventors: James V. Maher (Houston, TX), Edward E. Horton, III (Houston, TX), Lyle D. Finn (Sugar Land, TX)
Application Number: 13/440,747
International Classification: E21B 15/02 (20060101); E21B 7/12 (20060101);