US20120255736A1 - Offshore top tensioned riser buoyancy can system and methods of field development - Google Patents
Offshore top tensioned riser buoyancy can system and methods of field development Download PDFInfo
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- US20120255736A1 US20120255736A1 US13/440,747 US201213440747A US2012255736A1 US 20120255736 A1 US20120255736 A1 US 20120255736A1 US 201213440747 A US201213440747 A US 201213440747A US 2012255736 A1 US2012255736 A1 US 2012255736A1
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B19/00—Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrick; Apparatus for feeding the rods or cables
- E21B19/002—Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrick; Apparatus for feeding the rods or cables specially adapted for underwater drilling
- E21B19/004—Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrick; Apparatus for feeding the rods or cables specially adapted for underwater drilling supporting a riser from a drilling or production platform
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
- E21B17/01—Risers
- E21B17/012—Risers with buoyancy elements
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Abstract
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.
Description
- 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.
- Not applicable.
- 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.
- 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.
- For a detailed description of the disclosed embodiments, reference will now be made to the accompanying drawings in which:
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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 ofFIG. 1 ; -
FIG. 3 is a schematic side view of the buoyancy can system ofFIG. 1 ; -
FIG. 4 is a perspective view of the buoyancy can system ofFIG. 1 ; -
FIG. 5 is a schematic top view of the buoyancy can system ofFIG. 1 ; -
FIG. 6 is a schematic top view of one of the support members of the offshore structure ofFIG. 1 ; -
FIG. 7 is an end view of one of the horizontal bumpers ofFIG. 6 ; -
FIG. 8 is a side view of one of the vertical bumpers ofFIG. 6 ; -
FIG. 9 is a schematic view of the coupling system ofFIGS. 1 ; -
FIGS. 10-16 are sequential schematic top views illustrating the transfer of the buoyancy can system ofFIG. 1 from the offshore structure ofFIG. 1 to a secondary relocatable offshore structure; -
FIG. 17 is a schematic side view of the buoyancy can system ofFIG. 3 releasably coupled to a spar platform; -
FIG. 18 is a schematic top view of the buoyancy can system and the spar platform ofFIG. 17 ; -
FIG. 19 is a schematic side view of the buoyancy can system ofFIG. 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 ofFIG. 19 . - 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 cansystem 100 for tensioning an arrangement ofvertical risers 180 is shown releasably coupled to a lead drilling andproduction 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 adjustablybuoyant hull 210 that supports a deck ortopsides 220 above thesea surface 10. -
Hull 210 has a central orlongitudinal axis 215 and includes a plurality of radiallyouter columns 211 uniformly radially spaced fromaxis 215 and a radially inner orcenter column 212 disposed betweencolumns 211 and coaxially aligned withaxis 215. Elongatecylindrical columns axis 215. Further, eachcolumn column hull 210 includes four uniformly circumferentially spacedcolumns 211 generally arranged in a square configuration and onecenter column 212 disposed in the center ofcolumns 211.Columns 211 are coupled together by a plurality oftruss members 213 extending betweenadjacent columns 211, and thus,columns 211 do not move rotationally or translationally relative to each other. However,center column 212 is axially moveable relative tocolumns 211. In particular,center column 212 can be axially extended and retracted relative tocolumns 211. The lower end ofcenter column 212 includes asuction anchor 214 configured to releasably engage the sea bed in the extended position, thereby releasably anchoringhull 210 to thesea floor 20. InFIG. 1 ,center column 212 is shown axially extended relative tocolumns 211 and in engagement with thesea floor 20. In the refracted position,center column 212 is moved axially upward betweencolumns 211 towardstopsides 220, and is disengaged from thesea floor 20, thereby allowingvessel 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 ofcenter column 212 in combination with pulling/releasing column with a wireline extending from the upper end ofcenter column 212 totopsides 220. As will be described in more detail below, althoughvessel 200 is a tower in this embodiment, in general, buoyancy cansystem 100, and hencevertical 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 generallyrectangular bay 230 that releasably houses buoyancy cansystem 100.Bay 230 is disposed along the outer perimeter ofvessel 200 and is defined by a pair of rigidhorizontal support members 231 cantilevered fromhull 210 and a rigidhorizontal support member 232 extending between the inner ends ofmembers 231. In addition, askiddable derrick 221 is moveably coupled totopsides 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 afirst position 221 a generally over the center oftopsides 220 and asecond position 221 b (shown in phantom) cantilevered from the outer perimeter of thetopsides 220 overbay 230. Thus, when buoyancy cansystem 100 is disposed inbay 230,derrick 221 is positioned over buoyancy cansystem 100 in thesecond position 221 b. - 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 cansystem 100 is disposed inbay 230 laterallyadjacent vessel 200. Thus, as will be described in more detail below, lead drilling andproduction vessel 200 can be de-coupled fromsystem 100, transported to a different location, and secondary production vessel can be transported tosystem 100 and coupled thereto to continue production viarisers 180. - Referring now to
FIGS. 3-5 , buoyancy cansystem 100 is shown free-standing in the open water aftervessel 200 has been decoupled and moved therefrom. Buoyancy cansystem 100 supports one or moretop tension risers 180, which extend subsea tosea floor 20. In general,risers 180 may be marine drilling or production risers. Buoyancy provided bysystem 100 is sufficient to completely support eachriser 180 coupled thereto, even whensystem 100 is not coupled to any other offshore structure or vessel as shown inFIG. 3 . The tension load applied torisers 180 by buoyancy cansystem 100 is equal to the net buoyancy of system 100 (i.e., the total buoyancy ofsystem 100 minus the weight of system 100), which, as described below, is selectably adjustable to ensure that eachriser 110 coupled tosystem 100 is tensioned to the desired degree. - Referring still to
FIGS. 3-5 , buoyancy cansystem 100 includes a plurality of vertically oriented,elongate buoyancy cans 110 disposed within a generallyrectangular frame 120.Cans 110 are rigidly coupled to one another and to frame 120 such thatcans 110 andframe 120 move together as a single unit in response to external forces (e.g., wind, waves, etc.). In other words,cans 110 andframe 120 do not move translationally or rotationally relative to each other. As best shown inFIG. 5 , in this embodiment,cans 110 are coupled to each other and to frame 120 with a plurality ofrigid girders 150. - Referring again to
FIGS. 3-5 , the upper ends ofrisers 180 are disposed in theinterstitial spaces 130 formed betweencans 110 andframe 120. In addition, the upper ends ofrisers 180 are rigidly coupled to one another, as well as to frame 120 andcans 110. As a result, the upper ends ofrisers 180,cans 110, and frame 120 move together as a single unit in response to external forces. In other words, the upper ends ofrisers 180,cans 110, and frame 120 do not move translationally or rotationally relative to each other. As best shown inFIG. 5 , in this embodiment, the upper ends ofrisers 180 are coupled to each other, to frame 120, and tocans 110 with a plurality ofrigid girders 151. Althoughrisers 180 are positioned withininterstitial spaces 130 betweencans 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 enclosedupper end 110 a and an openlower end 110 b. Eachupper end 110 a 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 thecorresponding can 110. Eachlower end 110 b 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 throughlower end 110 b. The buoyancy of each can 110 is adjusted by varying the relative volumes of sea water and air within thecan 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 theupper end 110 a of thecan 110 is opened to allow air to escape thecan 110 through the opening and sea water to enter thecan 110 through openlower end 110 b; 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 theupper end 110 a of thecan 110 is closed and sealed to prevent air from escaping thecan 110 and a pressurized gas, such as air, is pumped into thecan 110 to displace a desired amount of sea water out of openlower end 110 b. 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 cansystem 100 also functions to support aproduction manifold 140 that is coupled to and receives produced fluids fromrisers 180, and supplies the produced fluids to a production vessel (e.g., vessel 200) via a plurality ofoutlet flow lines 141. In this embodiment,outlet flow lines 141 include a highpressure flow line 141 a, an intermediatepressure flow line 141 b, a lowpressure outflow line 141 c, and atest flow line 141 d 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), highpressure flow line 141 a 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), intermediatepressure flow line 141 b 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), lowpressure flow line 141 c is used to flow the produced fluids to a production vessel (e.g., vessel 200); andtest flow line 141 d is used to isolate production from any one of therisers 180 during any phase of production. Althoughmanifold 140 is mounted to buoyancy cansystem 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). Whensystem 100 is coupled to an offshore vessel, relative vertical movement betweensystem 100 and the vessel is generally permitted, especially if the vessel is a floating vessel. However, relative lateral movement betweensystem 100 and the vessel is preferably minimized. In embodiments described herein, lateral movement ofsystem 100 relative to vessel 200 (or other vessel) is limited bymembers bay 230. - Referring now to
FIGS. 2 and 6 ,members hull 210. In particular, eachsupport member 231 has afirst end 231 a coupled tohull 210, asecond end 231 bdistal hull 210, a first axial segment orportion 231 c extending fromend 231 a, and a second axial segment orportion 231 d extending fromend 231 b toportion 231 c. As best shown inFIGS. 2 and 6 ,second portions 231 d are angled outward relative tofirst portions 231 c, thereby defining a funnel that functions to guide buoyancy cansystem 100 intobay 230 generally betweenportions 231 c.Member 232 extends parallel to the perimeter ofhull 210 betweenfirst portions 231 c ofmembers 231. In particular,member 232 is oriented perpendicular tofirst portions 231 c, thereby givingbay 230 its generally rectangular shape. - As best shown in
FIGS. 6-8 , afender assembly 235 mounted to the inside of eachmember support members system 100. Eachfender assembly 235 includes a plurality of horizontal fenders orbumpers 236 and a plurality of vertical fenders orbumpers 237, each coupled to the associatedsupport member Bumpers system 100 as it is moved into and outbay 230 betweensupport members Bumpers members 231 with a flexible resilient material. For example, in this embodiment, eachbumper corresponding support member 231 with an elastomeric material (e.g., rubber). The inner surface of eachbumper bay 230 and buoyancy cansystem 100 disposed therein preferably comprises a low friction material such as an ultra-high-molecular-weight polyethylene (UHMW) to allow buoyancy cansystem 100 to slidingly engagebumpers - Referring now to
FIGS. 2 and 9 ,vessel 200 includes acoupling system 240 that releasably couplesvessel 200 to buoyancy cansystem 100. In this embodiment,coupling system 240 includes a plurality of laterally spacedtensioning assemblies 241 that connect to buoyancy cansystem 100, and operate together to pull buoyancy cansystem 100 intobay 230 and release buoyancy cansystem 100 frombay 230. As best shown inFIG. 9 , each tensioningassembly 241 includes awinch 242 mounted tovessel 200 betweensupport members 231 in top view, a wireline orcable 243, and a pulley 244.Wireline 243 is wrapped aroundwinch 242, extends around pulley 244, and has adistal end 243 a releasably attached to frame 120 of buoyancy cansystem 100.Winch 242 is anchored tohull 210 and controls the amount of tension or slack inwireline 243. Withwireline 243 attached to buoyancy cansystem 100,winch 242 applies tension towireline 243 to pullvessel 200 toward buoyancy cansystem 100 to enablevessel 200 to receivesystem 100 withinbay 230, and reduces tension and/or applies slack towireline 243 to enablevessel 200 to be moved away from buoyancy cansystem 100, thereby allowingsystem 100 to exitbay 230. - Referring now to
FIGS. 10-16 , an embodiment of a method for transferring or passing buoyancy cansystem 100 andrisers 180 coupled thereto from lead drilling andproduction vessel 200 to asecondary production vessel 300 is shown.Vessel 300 is the same asvessel 200 previously described except thatvessel 300 is specifically designed for production operations and is tailored to accommodate the actual production fromrisers 180 following drilling and initiation of production withvessel 200. Thus,vessel 300 includes ahull 210, topsides, 220,skiddable derrick 221,bay 230 defined bysupport members coupling system 240, each as previously described. InFIG. 10 , buoyancy cansystem 100 is shown coupled tovessel 200 withcoupling system 240 and disposed inbay 230; inFIGS. 11-13 , buoyancy cansystem 100 is shown exitingbay 230 and being decoupled fromvessel 200; inFIG. 14 , buoyancy cansystem 100 is shown freestanding following decoupling ofvessel 200 therefrom and before coupling ofvessel 300 thereto; inFIGS. 15 and 16 , buoyancy cansystem 100 is shown coupled tovessel 300 and moved intobay 230 ofvessel 300. Whensystem 100 is coupled tovessel 200, drilling or production operations may be performed withvessel 200 viarisers 180, and whensystem 100 is coupled tovessel 300, production operations may be performed withvessel 300 viarisers 180. When buoyancy cansystem 100 is not coupled to eithervessel risers 180 are shut-in withmanifold 140 and no drilling or production operations are performed. - Referring first to
FIG. 10 , buoyancy cansystem 100 andrisers 180 coupled thereto are disposed inbay 230 ofvessel 200 and coupled tovessel 200 withcoupling system 240.Support members system 100 andcoupling system 240 limits the gap betweenvessel 200 and buoyancy cansystem 100. In particular,winch 242 includes an auto-tensioning system that enableswinch 242 to automatically adjust tension and slack as necessary to maintain the gap between buoyancy cansystem 100 andvessel 200 asvessel 200 and/or buoyancy cansystem 100 move under environmental loads (e.g., wind, waves, currents, etc.). Relative vertical movement betweenvessel 200 andsystem 100 is generally permitted. - Moving now to
FIGS. 11-13 , to release buoyancy cansystem 100,risers 180 are shut-in withmanifold 140 andoutlet flow lines 141 are disconnected fromvessel 200. Next, slack is slowly provided towirelines 243 withwinches 242 asvessel 200 is slowly moved away from buoyancy can system 100 (e.g., with tugs), thereby allowingsystem 100 to exitbay 230. Whenvessel 200 is at a safe distance from buoyancy can system 100 (i.e., such that there is no risk ofvessel 200 impacting buoyancy cansystem 100 due to environmental loads),wirelines 243 are disconnected from buoyancy cansystem 100 andvessel 200 can be moved to another location for drilling and/or production operations. - Moving now to
FIGS. 14-16 , following the decoupling ofvessel 200 and buoyancy cansystem 100,vessel 300 is moved into position to connect to and receivesystem 100. In particular,vessel 300 is moved towards buoyancy cansystem 100 withbay 230 generally facing and aligned withsystem 100. Whilevessel 300 is still a safe distance away from buoyancy can system 100 (i.e., such that there is no risk ofvessel 200 impacting buoyancy cansystem 100 due to environmental loads),wirelines 243 are connected to buoyancy cansystem 100, and tension is controllably applied towirelines 243 withwinches 242 to slowly pullvessel 300 towards buoyancy cansystem 100, thereby movingsystem 100 intobay 230. Next,outlet flow lines 141 are connected tovessel 300 and valves onmanifold 140 are opened to produce fromrisers 180 tovessel 300. It should be appreciated thatrisers 180 are coupled to thesea floor 20, and thus, the transfer of buoyancy cansystem 100 andrisers 180 fromvessel 200 tovessel 300 occurs at a particular offshore location (i.e., buoyancy cansystem 100 andrisers 180 are not moved during the transfer). - As previously described,
vessels FIGS. 17 and 18 , buoyancy cansystem 100 and associatedrisers 180 are shown releasably coupled to a floatingspar platform 400 including a deck ortopsides 220 as previously described and an elongate cylindrical adjustablybuoyant hull 410 that that supportstopsides 220 above thesea surface 10.Mooring lines 350couple spar platform 400 to thesea floor 20 such thatplatform 400 is maintain in a substantially fixed position during drilling and/or production operations.Spar platform 400 can be disconnected frommooring lines 350 ormooring lines 350 can be removed from thesea floor 20 to relocateplatform 400 to a different offshore location. Askiddable derrick 221 as previously described is moveably coupled totopsides 220. In addition,platform 400 includes abay 230 defined bysupport members coupling system 240, each as previously described.Platform 400 is releasably coupled to buoyancy cansystem 100 and associated top-tensionedrisers 180 in the same manner as previously described. - As another example, in
FIGS. 19 and 20 , buoyancy cansystem 100 is shown releasably coupled to a floatingsemi-submersible platform 500 including a deck ortopsides 220 as previously described and an elongate cylindrical adjustablybuoyant hull 510 that that supportstopsides 220 above thesea surface 10.Mooring lines 350 couplesemi-submersible platform 500 to thesea floor 20 such thatplatform 500 is maintain in a substantially fixed position during drilling and/or production operations.Semi-submersible platform 500 can be disconnected frommooring lines 350 ormooring lines 350 can be removed from thesea floor 20 to relocateplatform 500 to a different offshore location. Askiddable derrick 221 as previously described is moveably coupled totopsides 220. In addition,platform 500 includes abay 230 defined bysupport members coupling system 240, each as previously described.Platform 500 is releasably coupled to buoyancy cansystem 100 and associated top-tensionedrisers 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.
Claims (24)
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.
Priority Applications (1)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US13/440,747 US20120255736A1 (en) | 2011-04-07 | 2012-04-05 | Offshore top tensioned riser buoyancy can system and methods of field development |
Applications Claiming Priority (2)
Application Number | Priority Date | Filing Date | Title |
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US201161472754P | 2011-04-07 | 2011-04-07 | |
US13/440,747 US20120255736A1 (en) | 2011-04-07 | 2012-04-05 | Offshore top tensioned riser buoyancy can system and methods of field development |
Publications (1)
Publication Number | Publication Date |
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US20120255736A1 true US20120255736A1 (en) | 2012-10-11 |
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ID=46965207
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US13/440,747 Abandoned US20120255736A1 (en) | 2011-04-07 | 2012-04-05 | Offshore top tensioned riser buoyancy can system and methods of field development |
Country Status (6)
Country | Link |
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US (1) | US20120255736A1 (en) |
CN (1) | CN103562484B (en) |
BR (1) | BR112013025746B1 (en) |
MX (1) | MX344068B (en) |
MY (1) | MY184287A (en) |
WO (1) | WO2012138912A2 (en) |
Cited By (2)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US20150298774A1 (en) * | 2011-07-13 | 2015-10-22 | Technische Universität Wien | Floating platform |
CN111488139A (en) * | 2019-01-25 | 2020-08-04 | 成都鼎桥通信技术有限公司 | Cluster service secondary development method based on private network terminal |
Families Citing this family (1)
Publication number | Priority date | Publication date | Assignee | Title |
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JP6919581B2 (en) * | 2018-01-19 | 2021-08-18 | トヨタ自動車株式会社 | Tension application device |
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- 2012-04-05 CN CN201280017514.7A patent/CN103562484B/en active Active
- 2012-04-05 MX MX2013011557A patent/MX344068B/en active IP Right Grant
- 2012-04-05 US US13/440,747 patent/US20120255736A1/en not_active Abandoned
- 2012-04-05 BR BR112013025746-6A patent/BR112013025746B1/en active IP Right Grant
- 2012-04-05 WO PCT/US2012/032403 patent/WO2012138912A2/en active Application Filing
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Also Published As
Publication number | Publication date |
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MX2013011557A (en) | 2015-02-05 |
WO2012138912A2 (en) | 2012-10-11 |
MY184287A (en) | 2021-03-30 |
BR112013025746A2 (en) | 2016-12-13 |
MX344068B (en) | 2016-12-02 |
CN103562484B (en) | 2016-05-25 |
WO2012138912A4 (en) | 2013-04-18 |
BR112013025746B1 (en) | 2021-03-23 |
WO2012138912A3 (en) | 2013-02-28 |
CN103562484A (en) | 2014-02-05 |
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