WO2012138912A2 - Système de flotteur pour colonne montante mise en tension par le dessus en mer et procédés de développement de champ - Google Patents

Système de flotteur pour colonne montante mise en tension par le dessus en mer et procédés de développement de champ Download PDF

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Publication number
WO2012138912A2
WO2012138912A2 PCT/US2012/032403 US2012032403W WO2012138912A2 WO 2012138912 A2 WO2012138912 A2 WO 2012138912A2 US 2012032403 W US2012032403 W US 2012032403W WO 2012138912 A2 WO2012138912 A2 WO 2012138912A2
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WO
WIPO (PCT)
Prior art keywords
vessel
buoyancy
bay
cable
risers
Prior art date
Application number
PCT/US2012/032403
Other languages
English (en)
Other versions
WO2012138912A4 (fr
WO2012138912A3 (fr
Inventor
James V. Maher
Iii Edward E. Horton
Lyle G. FINN
Original Assignee
Horton Wison Deepwater, Inc.
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Horton Wison Deepwater, Inc. filed Critical Horton Wison Deepwater, Inc.
Priority to CN201280017514.7A priority Critical patent/CN103562484B/zh
Priority to BR112013025746-6A priority patent/BR112013025746B1/pt
Priority to MX2013011557A priority patent/MX344068B/es
Priority to MYPI2013003651A priority patent/MY184287A/en
Publication of WO2012138912A2 publication Critical patent/WO2012138912A2/fr
Publication of WO2012138912A3 publication Critical patent/WO2012138912A3/fr
Publication of WO2012138912A4 publication Critical patent/WO2012138912A4/fr

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK 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
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK 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

Definitions

  • 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.
  • 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.
  • offshore vessel e.g., platform, floating drilling and/or production vessel, etc.
  • marine drilling risers are used to guide a drillstring and convey fluids used during various offshore drilling operations
  • marine production risers establish a flow path for hydrocarbons produced from a subsea well to the vessel located at the sea surface.
  • top tensioned risers 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.”
  • 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.
  • 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 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.
  • 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.
  • 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.).
  • 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 October 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.
  • 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.
  • 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 method comprises (a) coupling a plurality of top-tens ioned risers to a first vessel at a first location.
  • the method comprises (b) decoupling the first vessel from the plurality of top-tensioned risers after (a).
  • the method comprises (c) coupling a second vessel to the plurality of top-tensioned risers after (b) at the first location.
  • 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.
  • the system comprises a buoyancy can system disposed in the bay.
  • the buoyancy can system supports a plurality of top-tensioned risers.
  • the system comprises a coupling system releasably coupling the vessel to the buoyancy can system.
  • the method comprises (a) supporting a plurality of top-tensioned risers with a buoyancy can system.
  • 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.
  • the method comprises (c) withdrawing the buoyancy can system and the top-tensioned risers from the bay.
  • 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 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.
  • Figure 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;
  • Figure 2 is a schematic top view of the buoyancy can system and the offshore structure of Figure 1;
  • FIG. 3 is a schematic side view of the buoyancy can system of Figure 1;
  • Figure 4 is a perspective view of the buoyancy can system of Figure 1;
  • FIG. 5 is a schematic top view of the buoyancy can system of Figure 1;
  • Figure 6 is a schematic top view of one of the support members of the offshore structure of Figure 1;
  • Figure 7 is an end view of one of the horizontal bumpers of Figure 6;
  • Figure 8 is a side view of one of the vertical bumpers of Figure 6;
  • Figure 9 is a schematic view of the coupling system of Figures 1;
  • Figures 10-16 are sequential schematic top views illustrating the transfer of the buoyancy can system of Figure 1 from the offshore structure of Figure 1 to a secondary relocatable offshore structure;
  • Figure 17 is a schematic side view of the buoyancy can system of Figure 3 releasably coupled to a spar platform;
  • Figure 18 is a schematic top view of the buoyancy can system and the spar platform of Figure 17;
  • Figure 19 is a schematic side view of the buoyancy can system of Figure 3 releasably coupled to a semi-submersible platform;
  • Figure 20 is a schematic top view of the buoyancy can system and the semi-submersible platform of Figure 19.
  • the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to... .”
  • 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.
  • 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.
  • an axial distance refers to a distance measured along or parallel to the central axis
  • a radial distance means a distance measured perpendicular to the central axis.
  • 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.
  • each column 211, 212 is adjustably buoyant. In other words, the buoyancy of each column 211, 212 can be adjusted as desired.
  • hull 210 includes four uniformly circumferentially spaced columns 21 1 generally arranged in a square configuration and one center column 212 disposed in the center of columns 211.
  • Center column 212 is axially moveable relative to columns 211.
  • 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.
  • center column 212 is shown axially extended relative to columns 211 and in engagement with the sea floor 20.
  • center column 212 In the retracted 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 retracted 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.
  • 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.
  • 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.
  • 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.
  • a skiddable derrick 221 is moveably coupled to topsides 220.
  • 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.
  • 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.
  • first position 221a generally over the center of topsides 220
  • second position 221b shown in phantom
  • derrick 221 is positioned over buoyancy can system 100 in the second position 221b.
  • buoyancy can system 100 is disposed in bay 230 laterally adjacent vessel 200.
  • 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.
  • 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.
  • 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 Figure 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.
  • 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.
  • cans 110 are coupled to each other and to frame 120 with a plurality of rigid girders 150.
  • the upper ends of risers 180 are disposed in the interstitial spaces 130 formed between cans 1 10 and frame 120.
  • the upper ends of risers 180 are rigidly coupled to one another, as well as to frame 120 and cans 110.
  • the upper ends of risers 180, cans 110, and frame 120 move together as a single unit in response to external forces.
  • the upper ends of risers 180, cans 110, and frame 120 do not move translationally or rotationally relative to each other.
  • 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.
  • 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).
  • each buoyancy can 110 may comprise any buoyancy can known in the art.
  • each buoyancy can 110 is tubular in shape having an enclosed upper end 1 10a 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.
  • 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 1 10 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 October 13, 2008 and entitled "Tube Buoyancy Can System,” which is hereby incorporated herein by reference in its entirety
  • 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.
  • 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 14 Id as are known in the art.
  • 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 14 Id is used to isolate production from any one of the risers 180 during any phase of production.
  • 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.
  • the manifold e.g., manifold 140
  • the production vessel e.g., vessel 200
  • flexible flow lines supplying produced fluids from the risers (e.g., risers 180) to the manifold.
  • buoyancy can system 100 is designed to be releasably coupled to relocatable offshore vessels (e.g., vessel 200).
  • vessel 200 relocatable offshore vessels
  • system 100 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.
  • 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 231c extending from end 231a, and a second axial segment or portion 23 Id extending from end 23 lb to portion 23 lc.
  • second portions 23 Id 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 23 lc, thereby giving bay 230 its generally rectangular shape.
  • 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.
  • 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.
  • UHMW ultra-high- molecular- weight polyethylene
  • vessel 200 includes a coupling system 240 that releasably couples vessel 200 to buoyancy can system 100.
  • 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.
  • 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 243 a 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.
  • FIG. 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.
  • 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.
  • buoyancy can system 100 is shown coupled to vessel 200 with coupling system 240 and disposed in bay 230; in Figures 11- 13, buoyancy can system 100 is shown exiting bay 230 and being decoupled from vessel 200; in Figure 14, buoyancy can system 100 is shown freestanding following decoupling of vessel 200 therefrom and before coupling of vessel 300 thereto; in Figures 15 and 16, buoyancy can system 100 is shown coupled to vessel 300 and moved into bay 230 of vessel 300.
  • 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.
  • risers 180 are shut-in with manifold 140 and no drilling or production operations are performed.
  • 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.
  • 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.
  • buoyancy can system 100 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.
  • wirelines 243 are disconnected from buoyancy can system 100 and vessel 200 can be moved to another location for drilling and/or production operations.
  • vessel 300 is moved into position to connect to and receive system 100.
  • vessel 300 is moved towards buoyancy can system 100 with bay 230 generally facing and aligned with system 100.
  • 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.
  • outlet flow lines 141 are connected to vessel 300 and valves on manifold 140 are opened to produce from risers 180 to vessel 300.
  • 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).
  • vessels 200, 300 are relocatable towers.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.

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  • Life Sciences & Earth Sciences (AREA)
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Abstract

L'invention porte sur un procédé de développement d'un champ en mer, lequel procédé consiste (a) à accoupler une pluralité de colonnes montantes mises en tension par le dessus à un premier navire à un premier emplacement. En outre, le procédé consiste (b) à désaccoupler le premier navire de la pluralité de colonnes montantes mises en tension par le dessus après (a). En outre, le procédé consiste (c) à accoupler un second navire à la pluralité de colonnes montantes mises en tension par le dessus après (b) au premier emplacement.
PCT/US2012/032403 2011-04-07 2012-04-05 Système de flotteur pour colonne montante mise en tension par le dessus en mer et procédés de développement de champ WO2012138912A2 (fr)

Priority Applications (4)

Application Number Priority Date Filing Date Title
CN201280017514.7A CN103562484B (zh) 2011-04-07 2012-04-05 海上顶部张紧式立管浮力罐系统和油田开采方法
BR112013025746-6A BR112013025746B1 (pt) 2011-04-07 2012-04-05 Método de desenvolvimento de campo, sistema de latão flutuante de riser superiormente tensionado offshore e método para passagem de uma pluralidade de risers superiormente tensionados entre uma primeira embarcação offshore e uma segunda embarcação offshore
MX2013011557A MX344068B (es) 2011-04-07 2012-04-05 Sistema y métodos de desarrollo de campo de cubo flotante de elevador tensionado superior maritimo.
MYPI2013003651A MY184287A (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
US201161472754P 2011-04-07 2011-04-07
US61/472,754 2011-04-07

Publications (3)

Publication Number Publication Date
WO2012138912A2 true WO2012138912A2 (fr) 2012-10-11
WO2012138912A3 WO2012138912A3 (fr) 2013-02-28
WO2012138912A4 WO2012138912A4 (fr) 2013-04-18

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AT511850B1 (de) * 2011-07-13 2013-03-15 Univ Wien Tech Schwimmplattform
JP6919581B2 (ja) * 2018-01-19 2021-08-18 トヨタ自動車株式会社 張力付加装置
CN111488139B (zh) * 2019-01-25 2023-01-31 成都鼎桥通信技术有限公司 一种基于专网终端的集群业务二次开发方法

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US20080277123A1 (en) * 2004-10-01 2008-11-13 Stanwell Consulting Limited Offshore Vessel Mooring and Riser Inboarding System
US20070187109A1 (en) * 2006-02-10 2007-08-16 Millheim Keith K System for and method of restraining a subsurface exploration and production system
WO2009067539A1 (fr) * 2007-11-19 2009-05-28 Millheim Keith K Stations d'amarrage et de forage pour le déploiement de colonnes montantes autoporteuses

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MY184287A (en) 2021-03-30
BR112013025746A2 (pt) 2016-12-13
US20120255736A1 (en) 2012-10-11
WO2012138912A4 (fr) 2013-04-18
MX2013011557A (es) 2015-02-05
WO2012138912A3 (fr) 2013-02-28
CN103562484B (zh) 2016-05-25
BR112013025746B1 (pt) 2021-03-23
CN103562484A (zh) 2014-02-05
MX344068B (es) 2016-12-02

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