CROSS-REFERENCE TO RELATED APPLICATIONS This application claims the benefit of U.S. provisional patent application Ser. No. 61/539,349 filed Sep. 26, 2011, and entitled “MODULAR RELOCATABLE OFFSHORE SUPPORT TOWER,” which is hereby incorporated herein by reference in its entirety.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT Not applicable.
BACKGROUND 1. Field of the Invention
The invention relates generally to offshore structures. More particularly, the invention relates to subsea structures for supporting a marine deck or topsides.
2. Background of the Technology
Offshore production structures are used to store and offload hydrocarbons (e.g., oil and gas) produced by subsea wells. There are several different types of offshore production structures that are typically selected based on the depth of water at the well location. For instance, jackup platforms are commonly employed as drilling structures in water depths less than about 400 feet; fixed platforms are commonly employed as production structures in water depths between about 300 and 800 feet; and floating systems such as semi-submersible platforms are commonly employed as production structures in water depths greater than about 800 feet.
As compared to fixed platforms and floating systems, shallow water jackup platforms have relatively low daily rates (i.e., relatively low cost). Thus, it would be advantageous to be able to use a jackup platform in water depths greater than about 400 feet. The maximum water depth for a jackup is typically determined by the length of the jackup platform legs—the longer the legs, the greater the depth of water in which the platform may be deployed. However, since a jackup platform is transported offshore with its deck floating on the sea surface at the lower ends of the legs (i.e., the legs are fully retracted and extending upward from the deck), there is an upper limit to the length of the legs that will allow controlled and stable transport of the jackup.
Accordingly, there remains a need in the art for offshore production structures and systems that would enable the use of jackup platforms in water depths greater than about 300 feet.
BRIEF SUMMARY OF THE DISCLOSURE These and other needs in the art are addressed in one embodiment by an offshore support tower assembly. In an embodiment, the support tower assembly comprises a base disposed at the sea floor. In addition, the support tower assembly comprises a plurality of anchors securing the base to the sea floor. Further, the support tower assembly comprises a support frame coupled to the base. The support frame comprises plurality of modular tower sections in a stacked arrangement. The support tower assembly also comprises a deck supported by the support frame.
These and other needs in the art are addressed in another embodiment by a method for deploying an offshore support tower assembly. In an embodiment, the method comprises (a) lowering a base subsea to the sea floor. In addition, the method comprises (b) lowering a plurality of anchors subsea. Further, the method comprises (c) securing the base to the sea floor with a plurality of anchors after (a) and (b). Still further, the method comprises (d) installing a modular support frame onto the base. The method also comprises (e) coupling a deck to an upper end of the support frame.
These and other needs in the art are addressed in another embodiment by a method for deploying an offshore tension leg platform (TLP). In an embodiment the method comprises (a) floating the TLP offshore to an installation site. In addition, the method comprises (b) transporting a base to the offshore installation site. Further, the method comprises (c) lowering the base to the sea floor. Still further, the method comprises (d) lowering a plurality of anchors subsea. Each anchor has a lower end and an upper end comprising a tendon termination coupling. The method also comprises (e) securing the base to the sea floor with the plurality of anchors after (d). Moreover, the method comprises (f) coupling the TLP to the base after (e) with a plurality of tendons. Each tendon has a lower end releasably coupled to one of the tendon termination couplings and an upper end secured to the TLP.
Embodiments described herein comprise a combination of features and advantages intended to address various shortcomings associated with certain prior devices, systems, and methods. The foregoing has outlined rather broadly the features and technical advantages of the invention in order that the detailed description of the invention that follows may be better understood. The various characteristics described above, as well as other features, will be readily apparent to those skilled in the art upon reading the following detailed description, and by referring to the accompanying drawings. It should be appreciated by those skilled in the art that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes of the invention. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims.
BRIEF DESCRIPTION OF THE DRAWINGS For a detailed description of the preferred embodiments of the invention, reference will now be made to the accompanying drawings in which:
FIG. 1 is a perspective view of an embodiment of an offshore subsea support tower assembly in accordance with the principles described herein;
FIG. 2 is an exploded perspective view of the tower assembly of FIG. 1;
FIG. 3 is an enlarged view of the base of the tower assembly of FIG. 2;
FIG. 4 is top view of the base of the tower assembly of FIG. 1;
FIGS. 5-7 are a schematic side views of one tubular of the base of FIG. 4 and associated ballast control system for adjusting the ballast in the tubular;
FIGS. 8 and 9 are perspective views of the base of FIG. 4;
FIGS. 10 and 11 are sequential schematic cross-sectional side views of one of the anchors of FIGS. 1 and 2 penetrating the sea floor during installation;
FIGS. 11-13 are enlarged views of the sub-frames of the tower assembly of FIG. 1;
FIGS. 14 and 15 are enlarged views of the sub-frames and top deck of the tower assembly of FIG. 1;
FIGS. 16-23 are enlarged sequential perspective views of the deployment and installation of the base of FIG. 1;
FIGS. 24-26 are enlarged sequential side views of the installation of an alternative embodiment of a base in accordance with the principles described herein;
FIGS. 27-29 are enlarged sequential side views of the installation of an alternative embodiment a base in accordance with the principles described herein;
FIGS. 30-31 are enlarged sequential perspective views of the installation of the lower sub-frame onto the base of the tower assembly of FIG. 1;
FIGS. 32-33 are enlarged sequential perspective views of the installation of the intermediate sub-frame onto the lower sub-frame of the tower assembly of FIG. 1;
FIGS. 34-35 are enlarged sequential perspective views of the installation of upper sub-frame onto the intermediate sub-frame of the tower assembly of FIG. 1;
FIGS. 36-41 are sequential front views of the installation of the upper deck onto the upper sub-frame of the tower assembly of FIG. 1 using a pair of parallel barges;
FIGS. 42-45 are sequential front views of the installation of the upper deck onto the upper sub-frame of the tower assembly of FIG. 1 using a crane;
FIGS. 46-48 are sequential schematic views of a jackup rig being deployed offshore and installed on an embodiment of an offshore subsea support tower assembly in accordance with the principles described herein;
FIG. 49 is a perspective view of a tension-leg platform (TLP) anchored to an embodiment of a base in accordance with the principles described herein;
FIGS. 50-56 are enlarged sequential perspective views of the installation of tubular piles into the base of FIG. 49;
FIGS. 57-58 are sequential front views of the anchoring of the TLP to the base of FIG. 49; and
FIGS. 59-63 are enlarged sequential perspective views of the installation of the tendons of the TLP of FIG. 49.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS The following discussion is directed to various exemplary embodiments. However, one skilled in the art will understand that the examples disclosed herein have broad application, and that the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to suggest that the scope of the disclosure, including the claims, is limited to that embodiment.
Certain terms are used throughout the following description and claims to refer to particular features or components. As one skilled in the art will appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name but not function. The drawing figures are not necessarily to scale. Certain features and components herein may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in interest of clarity and conciseness.
In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . .” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect connection via other intermediate devices, components, and connections. In addition, as used herein, the terms “axial” and “axially” generally mean along or parallel to a given axis (e.g., central axis of a body or a port), while the terms “radial” and “radially” generally mean perpendicular to the given axis. For instance, an axial distance refers to a distance measured along or parallel to the axis, and a radial distance means a distance measured perpendicular to the axis.
Referring now to FIG. 1, an embodiment of a subsea support tower assembly 100 is shown. Support tower assembly 100 has a vertical central or longitudinal axis 105, an upper end 100a, and a lower end 100b opposite end 100a. Lower end 100b engages and is supported by the sea floor 101. As will be described in more detail below, the axial height of tower assembly 100 may be varied depending on the particular application. Thus, for example, upper end 100a may be disposed subsea, at or near the sea surface 102, or above the sea surface 102. In most applications, tower assembly 100 is employed to support offshore structures at the sea surface 102 (e.g., drilling decks, jackup platforms, semi-submersible platform, etc.). However, tower assembly 100 can also be used to support subsea equipment at the sea floor 101, proximal the sea surface 102, or an any location therebetween.
Referring now to FIG. 2, an exploded view of the subsea tower assembly 100 of FIG. 1 is shown. In this embodiment, tower assembly 100 comprises a base 110 secured to the sea floor 101, a modular support frame 140 coupled to and extending vertically upward from the base 110, and a top platform or deck 150 disposed atop the modular support frame 140.
Referring now to FIG. 3, base 110 sits on the sea floor 101 and is held in position with a plurality of anchors 130. Frame 140 is supported by base 110 and extends vertically therefrom. In this embodiment, base 110 includes a horizontal upper deck 111, a horizontal lower deck 115, and a plurality of parallel, vertical anchor guides 120 coupled to decks 111, 115. A plurality of support members 114 extend between upper and lower decks 111, 115, maintain the axial spacing of decks 111, 115, and enhance the rigidity to base 110.
Referring now to FIGS. 3 and 4, upper deck 111 includes a plurality of upper cross-members 112a and a plurality of upper stringers or support members 112b. Cross-members 112a extend between adjacent guides 120 along the outer periphery of deck 111. Stringers 112b extend perpendicularly between cross-members 112a. Each upper cross-member 112a and upper stringer 112b is positioned at the same axial height relative to guides 120 and sea floor 101. In this embodiment, upper deck 111 has a rectangular periphery defined by four cross-members 112a. One guide 120 is positioned at each of the four corners of upper deck 111. Further, deck 111 has a rectangular central opening 113 defined by a plurality of stringers 112b. Opening 113 provides through access to lower deck 115. As will be described in more detail below, flow conduits such as risers may extend through opening 113. For added surface area on deck 111 (e.g., to support subsea equipment at the sea floor 101), a flat plate (e.g., steel plate) may be positioned across deck 111. However, any such plate preferably does not occlude or block opening 113.
In this embodiment, cross-members 112a and stringers 112b are ballast adjustable tubular members. Thus, as desired, cross-members 112a and stringers 112b can be controllably ballasted to decrease the buoyant forces acting on base 110 and controllably de-ballasted to increase the buoyant forces acting on base 110. Referring now to FIGS. 5-7, one ballast adjustable tubular member is shown, it being understood that each cross-member 112a and stringer 112b comprises a ballast adjustable tubular member as shown in FIGS. 5-7. Each cross-member 112a and stringer 112b has a central or longitudinal axis 215, an upper or top side 213, a lower or bottom side 214, a first end 211a, and a second end 211b opposite first end 211a. As shown in FIGS. 5-7, each of the cross-members 112a and stringers 112b are oriented horizontally such that bottom side 214 faces the sea floor 101. Ends 211a, b are closed or capped, thereby defining an internal variable ballast chamber 216 within each cross-member 112a and stringer 112b. An open port 217 is positioned along the bottom side 214 and allows the free flow of water 15 into and out of chamber 216.
Referring specifically to FIG. 5, a ballast control system 230 is provided for each cross-member 112a and stringer 112b to independently control the relative volumes of air 16 and water 15 within each specific cross-member 112a or stringer 112b. Specifically, ballast control system 230 comprises an access panel 231, a conduit 232, and a valve 234 along conduit 232. Conduit 232 has a first end 232a disposed outside of variable ballast chamber 216 and coupled to access panel 231 and a second open end 232b disposed within chamber 216. As is best shown in FIG. 6, access panel 231 is configured such that a remote operated vehicle 250 (ROV 250) may releasably connect an air supply line to panel 231 and conduit 232.
Referring now to FIG. 6, in order to de-ballast the cross member 112a or stringer 112b, ROV 250 is coupled to access panel 231 and valve 234 is open, thereby allowing ROV 250 to pump air 16 through conduit 232 and open valve 234 and into chamber 216. As air 16 is pumped into chamber 216 via conduit 232, water 15 is forced out of port 217 thereby causing the interface 235 between the water 15 and the air 16 within chamber 216 to move toward the bottom side 214. However, once the interface 235 of water 15 and air 16 reaches port 217, the volume of air 16 in chamber 216 cannot be increased further as any additional air 16 will simply exit chamber 216 through port 217. Alternatively and as is best shown in FIG. 7, in order to ballast a specific cross-member 112a or stringer 112b, valve 234 is open thereby allowing air 16 to escape out of the first end 232a and panel 231. As air 16 escapes out of first end 232a and panel 231, water 15 flows through port 217 into chamber 216 thereby causing the interface 235 within chamber 216 to move toward the top side 213. In at least one embodiment, cross-members 112a and stringers 112b each have their own associated ballast control system 230 such that they may each be independently ballasted or de-ballasted in order to decrease or increase the buoyant forces acting on base 110, respectively. Although each cross member 112a and stringer 112b is provided with its own ballast control system 230, in other embodiments, a single ballast control system (e.g., system 230) can be provided to simultaneously ballast/de-ballast cross-members 112a and stringers 112b.
Referring back to FIG. 3, in this embodiment, lower deck 115 is configured the same as upper deck 111. Thus, lower deck 115 has a rectangular opening 117 aligned with central opening 113 in upper deck 111. As best shown in FIG. 4, a plurality of conduit guides 118 are disposed in opening 117. Referring briefly to FIGS. 8 and 9, guides 118 support and position various fluid flow lines (e.g., risers) that may extend through openings 113, 117. In some embodiments, lower deck 115 is preferably positioned a distance above the sea floor 101 such that tower assembly 100 can be positioned over a subsea wellbore while providing sufficient space to accommodate subsea hardware directly connected to a wellhead (e.g., blowout-preventer, subsea production tree, etc.). In some embodiments, lower deck 115 is preferably positioned at least 30 feet above the sea floor 101.
Referring again to FIGS. 3 and 4, guides 120 are connected to the corners of decks 111, 115. In this embodiment, decks 111, 115, and hence base 110, are rectangular, and thus, four guides 120 are provided. As best shown in FIG. 3, each anchor 130 has a central or longitudinal axis 135 and a recess or receptacle 131 at its upper end. In general, each anchor 130 may comprise any suitable anchoring device known in the art including, without limitation, a driven pile installed by being driven into the sea floor 101, or a gravity pile having an inner chamber that is filled with a weight such as iron ore granules or concrete during installation. In this embodiment, each anchor 130 is a suction pile.
Referring now to FIGS. 10 and 11, one anchor 130 is schematically shown, it being understood that each anchor 130 is the same in this embodiment. As previously described, each anchor 130 is a suction pile. In particular, each anchor 130 comprises an annular, cylindrical skirt 341, a first or upper end 341a, a second or lower end 341b, a cap 333 disposed at the upper end 341a, and a cylindrical cavity 342 extending axially between ends 341a, b. Thus, cavity 342 is closed off at upper end 341a by cap 333 while remaining completely open to the surrounding environment at lower end 341b.
As will be described in more detail below, anchor 130 is employed to secure base 110 and modular support frame 140 to the sea floor 101. During installation of anchor 130, skirt 341 is urged axially downward into the sea floor 101 (as shown in FIG. 11), and during removal of anchor 130 from the sea floor 101, skirt 341 is pulled axially upward from the sea floor 101. To facilitate the insertion and removal of anchor 130 into and from the sea floor 101, this embodiment includes a suction/injection control system 370.
Referring again to FIGS. 10 and 11, system 370 includes a main flowline or conduit 371, a fluid supply/suction line 372 extending from main conduit 371, and an injection/suction pump 373 connected to line 372. Conduit 371 extends subsea to cavity 342, and has an upper venting end 371a and a lower open end 371b in fluid communication with cavity 342. A valve 374 is disposed along conduit 371 controls the flow of fluid (e.g., mud, water 15, etc.) through conduit 371 between ends 371a, b. Specifically, when valve 374 is open, fluid is free to flow through conduit 371 from cavity 342 to venting end 371a, and when valve 374 is closed, fluid is restricted and/or prevented from flowing through conduit 371 from cavity 342 to venting end 371a.
Pump 373 is configured to pump fluid (e.g., water 15) into cavity 342 and pump fluid (e.g., water 15, mud, silt, etc.) from cavity 342 via line 372 and conduit 371. A valve 375 is disposed along line 372 and controls the flow of fluid through line 372. Particularly, when valve 375 is open, pump 373 may pump fluid into cavity 342 via line 372 and conduit 371, or pump fluid from cavity 342 via conduit 371 and line 372; and when valve 375 is closed, fluid communication between pump 373 and cavity 342 is restricted and/or prevented.
In this embodiment, pump 373, line 372, and valves 374, 374 are positioned axially above skirt 341 and cap 333 and may be accessed above the sea surface 102. However, in general, the pump (e.g., pump 373), the suction/supply line (e.g., line 372), and valves (e.g., valve 374, 375) may be disposed at any suitable location. For example, the pumps and valves may be disposed subsea and remotely actuated. Further, in this embodiment, main conduit 371 extends into cavity 342 through cap 133. However, in other embodiments, the main conduit (e.g., conduit 171) may enter into cavity 342 at any suitable location.
Referring now to FIG. 11, suction/injection control system 370 may be employed to facilitate the insertion and removal of anchor 130 into and from the sea floor 101. In particular, as skirt 341 is urged into sea floor 101, valve 374 may be opened and valve 375 closed to allow fluid (e.g., water 15) within cavity 342 between sea floor 101 and cap 333 to vent through conduit 371 and out end 371a. To accelerate the penetration of skirt 341 into sea floor 101 and/or to enhance the “grip” between suction skirt 341 and the sea floor 101, suction may be applied to cavity 342 via pump 373, conduit 371 and line 372. In particular, valve 375 may be opened and valve 374 closed to allow pump 373 to pull fluid (e.g., water 15, mud, silt, etc.) from cavity 342 through conduit 371 and line 372. Once skirt 341 has penetrated the sea floor 101 to the desired depth, valves 374, 375 are preferably closed to maintain the positive engagement and suction between anchor 130 and the sea floor 101.
Referring back to FIG. 2, support frame 140 extends vertically upward from base 110 to upper end 100a. In this embodiment, support frame 140 is made from a plurality of stacked sub-frames. Namely, frame 140 comprises a lower sub-frame 141, an intermediate sub-frame 142 mounted to lower sub-frame 141, and an upper sub-frame 143 mounted to intermediate sub-frame 142. Thus, sub-frames 140, 141, 142 are stacked on-atop-the-other. Each sub-frame 141, 142, 143 further comprises a plurality of trusses 144 coupled end-to-end and defining the periphery of the sub-frame 141, 142, 143. In other words, and as best shown in FIGS. 12, 13 and 14, planar trusses 144 define the sides of each sub-frame 141, 142, 143. Posts 147 are disposed at the corners of each sub-frame 141, 142, 143 and thus form the sides of each truss 144. Each planar truss 144 has an upper end 144a, a lower end 144b, a horizontal upper cross-member 145 disposed at the upper end 144a, a horizontal lower cross-member 146 disposed at the lower end 144b, a pair of posts 147, and a pair of support members 148 extending diagonally between posts 147. Trusses 144 may be made of tubular members that may be controllably ballasted to decrease the buoyant forces acting on some or all of the trusses 144 or de-ballasted to increase the buoyant forces acting on trusses 144. Each tubular member may be ballasted/de-ballasted by the same method described for cross-members 112a and stringers 112b disposed on base 110. Additionally, by controllably ballasting/de-ballasting the tubular members in both the base 110 and the frame 140, the overall pressure experienced by some or all of the components of the tower assembly 100 may be adjusted. As previously described, planar trusses 144 are stacked end-to-end within each sub-frame 141, 142, and 143 such that the horizontal upper cross-member 145 of one truss also serves as the horizontal lower cross-member 146 of another truss.
Referring now to FIGS. 12-14, each truss 144 has an upper width measured horizontally between posts 147 at upper end 144a and a lower width measured horizontally between posts 147 at lower end 144b. For each truss 144 of lower sub-frame 141, the upper width is less than the lower width. Thus each truss 144 of lower sub-frame 141 has a trapezoidal shape with posts 147 tapering inward toward axis 105 as they extend from lower end 144b to upper end 144a. Further, the generally planar trusses 144 of lower sub-frame 141 taper inward toward axis 105 as they extend from lower end 144b to upper end 144a. Therefore, lower sub-frame 141 is shaped like a truncated square pyramid. However, sub-frames 142, 143 and their respective trusses 144 are not tapered and do not taper inward, such that sub-frames 142, 143 take on a rectangular shape.
Referring to FIGS. 3 and 12, the lower portion of each post 147 of subframe 141 comprises a male stabbing pin 132 that extends axially from lower end 144b of lowermost truss 144. Each stabbing pin 132 comprises a shoulder 133 and is slidingly received by a mating receptacle 131 of one anchor 130, thereby coupling base 110 to anchors 130. In particular, stabbing pin 132 is coaxially inserted into one mating receptacle 131 until annular shoulder 133 axially abuts the upper end of the corresponding anchor 130. Once each stabbing pin 132 is seated in the mating receptacle 131, a releasable mechanical connection is made between each stabbing pin 132 and corresponding anchor 130 such that lower sub-frame 141 is secured to anchors 130 and therefore base 110. In general, any suitable releasably mechanical connection may be used including, without limitation, a Merlin™ connector, available from Oil States of Arlington, Tex.
Referring to FIGS. 13 and 14, a recess or receptacle 149a is disposed at the upper end of each post 147 on sub-frames 141, 142, 143. Similarly to stabbing pins 132 disposed on lower sub-frame 141 previously described, the lower end of each post 147 of sub-frames 142, 143 comprises a vertically oriented male stabbing pin 149b. Each of the stabbing pins 149b and the receptacles 149a are configured such that each stabbing pin 149b of intermediate sub-frame 142 is slidingly received by a mating receptacle 149a of lower sub-frame 141, and each stabbing pin 149b of upper sub-frame 143 is slidingly received by a mating receptacle 149a of intermediate sub-frame 142. Once each of the above described stabbing pins 149b is received within its associated receptacle 149a, a releasable mechanical connection is made to secure the stabbing pins 149b within the receptacles 149a. In general, any suitable releasably mechanical connection may be used including, without limitation, a Merlin™ connector, available from Oil States of Arlington, Tex.
Referring now to FIG. 15, a deck 150 is mounted to the upper end of upper sub-frame 143 and defines upper end 100a of support tower assembly 100. In general, deck 150 can be secured to the upper end of support frame 140 by any suitable means known in the art. In this embodiment, deck 150 is a drilling platform disposed above the sea surface 102.
It should be noted that while base 110 and frame 140 are generally rectangular in top view and in cross-sections taken perpendicular to axis 105, in other embodiments, the base (e.g., base 110), the frame (e.g., frame 140), and the upper deck (e.g., deck 150) may have other shapes in top view and cross-sectional view including, without limitation, rectangular, triangular, hexagonal, etc. Additionally, in this embodiment, base 110 is square having dimensions of approximately 200 feet by 200 feet. In other words, each cross-member 112a is about 200 feet long. At upper end 100a, tower assembly 100 of this embodiment is also square, however, since trusses 144 taper inward moving from base 110 to upper end 100a, upper end 100a has dimensions less than 200 feet by 200 feet. Furthermore, in this embodiment, tower assembly 100 has a height measured from sea floor 101 to deck 150 of about 600 to 800 feet. However, the dimensions of each side of the base, the frame, and the deck as well as the height of tower assembly 100 may vary depending on the particular application and environment.
Referring again to FIGS. 1 and 2, due to the size and weight of anchors 130, base 110, sub-frames 141, 142, 143 and deck 150, a modular, component-by-component installation of tower assembly 100 is preferred. In particular, anchors 130, base 110, sub-frames 141, 142, 143 are transported to the offshore installation site, and then lowered subsea and built from the bottom up. In some embodiments, sub-frames 141, 142, 143 may be transported to the desired location by a ballasting/de-ballasting the various tubular members via a ballast control system (e.g., ballast control system 230 as previously described), such that each sub-frame 141, 142, 143 can be floated to the installation site in a horizontal orientation, and then controllably ballasted to transition the sub-frame 141, 142, 143 to a vertical orientation at the installation side before being lowered subsea. In this embodiment, anchors 130 and base 10 are installed first. In particular, base 110 is lowered subsea and secured to the sea floor 101, and then anchors 130 are lowered subsea, coupled to base 110, and installed into the sea floor. Next frame 140 is lowered subsea and mounted to base 110. Each sub-frame 141, 142, 143 of frame 140 can be lowered individual, or any two or more of sub-frames 141, 142, 143 can be preassembled and lowered simultaneously. Once installation of frame 140 is complete, deck 150 is lowered and mounted to the upper end of frame 140.
One or more subsea ROVs (e.g., ROV 250) may be employed to aid in the positioning, monitoring, and installation of the various components of tower assembly 100. For example, ROVs may be used to aid in the alignment of mating pins 132 and receptacles 131 (e.g., FIG. 32) and mating pins 149a and receptacles 149a (as best shown in FIG. 34). Further, each component of tower assembly 100 (e.g., anchors 130, base 110, sub-frames 141, 142, 143, and deck 150) can be controllably lowered subsea with one or more cables or wirelines extending from a surface vessel. Such cables are preferably sufficiently strong (e.g., steel cables) to withstand the anticipated tensile loads. A winch or crane mounted to a surface vessel is preferably employed to support and lower each component on the cables. Alternatively, the components of tower assembly 11 may be deployed subsea on a pipe string. To manage loads during installation while ensuring stability after installation, one or more components of tower assembly 100 can be de-ballasted prior to and/or while being lowered subsea, and then ballasted (e.g., with water, iron ore granules, etc.) after installation.
Referring to FIG. 16, in this embodiment, base 110 is lowered to the sea floor 101 by cables 25 suspended from a vessel (not shown) disposed at the sea surface 102. To manage loads while being lowered subsea, base 110 is preferably de-ballasted prior to and/or while being lowered subsea, and then ballasted (e.g., with water, iron ore granules, etc.) after being lowered to the sea floor 101.
Referring now to FIGS. 17-23, once base 110 is settled on the sea floor 101, anchors 130 are lowered subsea and secured to the sea floor 101 in each of the guides 120 disposed at each of the corners of base 110. In this embodiment, anchors 130 are lowered by cables (e.g., cables 25) with the aid of one or more subsea ROVs 250. Next, anchors 130 are coupled to base 110 and installed into the sea floor 101.
Referring to FIGS. 24-26, another embodiment of a base 410 for a subsea support tower assembly (e.g., assembly 100) is shown. Base 410 is substantially similar to base 110 described above, except that guides 420 completely surround anchors 130, as previously described, such that each anchor 130 is disposed coaxially within each guide 420. Additionally, each anchor 130 is coupled to an associated guide 420 such that each anchor 130 is allowed to move axially relative to each associated guide 420. In the embodiment shown, the base 410 and anchors 130 are lowered to the sea floor 101 by the methods described above for base 110. However, because anchors 130 are coupled to connectors 420, both the anchors 130 and the base 410 are lowered simultaneously. Once the base 110 and the anchors 130 make contact with the sea floor 101, the anchors 130 are secured to the sea floor 101 in the same manner as previously described.
Referring now to FIGS. 27-29, another embodiment of a base 510 for a subsea support tower assembly (e.g., assembly 100) according to the principles of this disclosure is shown. Base 510 is substantially similar to base 110, previously described, except that anchors 130, previously described, are fixably coupled to guides 520 such that each anchor 130 may not move axially relative to its associated guide 520. In the embodiment shown, the base 510 and anchors 130 are lowered to the sea floor 101 by the methods described above. Once the base 510 and anchors 130 reach the sea floor 101, the anchors 130 are driven into and secured to the sea floor 101 by substantially the same methods described above. However, because each guide 520 is fixably connected to an associated anchor 130, the base 510 is also lowered as the anchors 130 are installed into the sea floor 101.
Referring now to FIGS. 30 and 31, once base 110 and anchors 130 are secured to the sea floor 101, frame 140 is mounted atop base 110. Specifically, lower sub-frame 141 is lowered subsea, stabbing pins 132 are aligned and inserted into mating receptacles 131, and a releasable mechanical connection is made therebetween.
Referring now to FIGS. 32 and 33, once lower sub-frame 141 is secured to base 110, intermediate sub-frame 142 is mounted atop lower sub-frame 141. Specifically, intermediate sub-frame 142 is lowered subsea, stabbing pins 149b are aligned and inserted into mating receptacles 149a of lower sub-frame 141, and a releasable mechanical connection is made therebetween.
Referring now to FIGS. 34 and 35, once intermediate sub-frame 142 is secured to lower sub-frame 141, upper sub-frame 143 is secured to the intermediate sub-frame 142 in a manner similar to the securing of intermediate sub-frame 142 to lower sub-frame 141. Specifically, upper sub-frame 143 is lowered such that stabbing pins 149b disposed on the lower end of upper sub-frame 143 are received within receptacles 149a disposed on the upper end of the intermediate sub-frame 142 in the manner previously described above. Once each stabbing pin 149b is fully received within receptacle 149a, the two are secured to each other by way of a releasable mechanical connection as previously described.
Referring now to FIGS. 36-41, once installation of frame 140 is complete, deck 150 is mounted to the top of frame 140. Referring first to FIGS. 37 and 38, in one embodiment, deck 150 is transported out to modular tower support assembly 100 by means of a pair of laterally spaced, parallel barges 50. Parallel barges 50 are spaced such that they form an open bay or passage (not shown) therebetween. Deck 150 sits atop of parallel barges such that deck 150 spans the bay or passage (not shown) disposed between parallel barges 50. In other embodiments, parallel barges 50 may be replaced with a single U-shaped barge which defines a bay or passage between two extended pontoons.
Referring to FIGS. 38-41, parallel barges 50 maneuver such that barges 50 are disposed on opposite sides of frame 140 with deck 150 disposed immediately over frame 140. Barges 50 are then ballasted such that deck 150 is lowered into engagement with frame 140. Deck 150 is then releasably secured to frame 140 by any suitable means known in the art. Once deck 150 is secured to frame 140, barges 50 may be pulled away from the completed structure.
Referring now to FIGS. 42-45, an alternative method of installing top deck 150 onto frame 140 is shown. Referring first to FIGS. 42 and 43, deck 150 is transported out to modular tower support assembly 100 by means of a barge 60 in a manner similar to that described above. Additionally, a second barge 65 with a crane 70 disposed thereon is maneuvered proximal to barge 60 and frame 140. Crane 70 may be any suitable crane for lifting a drilling platform while still complying with the basic principles of this disclosure. As is shown in FIG. 43, once barge 65, crane 70, barge 60, and deck 150 are all arranged around frame 140, crane 70 lifts deck 150 from barge 60 via cabling 75. Referring now to FIGS. 44 and 45, crane 70 then maneuvers deck 150 such that it is placed directly over frame 140. Deck 150 is then lowered onto the upper end of frame 140 and releasably secured thereto.
Although deck 150 is a drilling platform disposed above the sea surface 102 in this embodiment, in other embodiments, the deck supported by frame 140 may be a deck disposed subsea (e.g., to support subsea equipment). Further, as will be described in more detail below, in still other embodiments, no deck is disposed atop frame 140.
It should be appreciated that the modular nature of tower assembly 100, the releasable mechanical connections between the components of tower assembly 100, and the ballast adjustable components of tower assembly 100 enable tower assembly 100 to be dis-assembled and transported from one offshore installation site to a different offshore installation site. In general, disassembly of tower assembly 100 is performed by reversing the steps employed to assembly tower assembly 100. In particular, deck 150 is decoupled and removed from upper sub-frame 143, upper sub-frame 143 is decoupled and removed from intermediate sub-frame 142, intermediate sub-frame 142 is decoupled and removed from lower sub-frame 141, and base 110 is lifted from the sea floor 101. Depending on the types of anchors 130 employed (e.g., driven piles, gravity piles, or suction piles) and the coupling between anchors 130 and base 110, anchors 130 may be withdrawn from the sea floor 101 (e.g., when anchors 130 are suction piles as shown in FIGS. 10 and 11) or cut to enable decoupling of base 110 and left behind. In relatively deep offshore installation sites (i.e., when tower assembly 100 is tall) tower assembly 100 can be moored with mooring lines or guy wires coupled to the frame 140 and/or deck 150 and secured to the sea floor 101 to enhance the stability of tower assembly 100 in the vertical orientation.
Referring now to FIGS. 46-48, a jackup rig 600 is shown being deployed offshore and installed onto an embodiment of a modular tower assembly 700 in accordance with the principles described herein. Jackup rig 600 may be any conventional jackup rig including a buoyant hull 601 and a plurality of legs 602 moveably coupled to hull 601. In particular, each leg 602 may be controllably moved up and down relative to hull 601. Tower assembly 700 is the same as modular tower assembly 100 previously described except that deck 150 is disposed directly on the upper end of lower sub-frame 140 and is positioned below the sea surface 102.
Referring first to FIG. 47, to transport jackup rig 600 to the desired offshore location, all legs 602 are retracted upward such that hull 601 is positioned at or proximal the lower ends of legs 602, and rig 600 is floated out to the offshore location with hull 601 disposed on the sea surface 102.
Moving now to FIGS. 46 and 48, rig 600 is positioned over tower assembly 700 and legs 602 are lowered from hull 601. Legs 602 are lowered until they engage and are supported by deck 150 at the upper end of tower assembly 100. Continued lowering of legs 602 relative to hull 601 results in hull 601 being raised out of the water above the sea surface 102. As legs 602 engage deck 150 and hull 601 is raised out of the water, substantially all of the weight of jackup rig 600 will be supported by tower assembly 700. Once legs 602 engage with deck 150 the legs 602 and the deck 150 are secured to deck 150 with a releasable mechanical connection. In general, any releasably mechanical connection known in the art may be employed.
In the manner described, tower assembly 700 may be utilized to effectively increase the depth of water in which jackup rig 600 may be used. For example, if legs 602 are about 300 feet tall, jackup rig 600 by itself can generally be used in water depths up to about 300 feet. However, by mounting jackup rig 600 to tower assembly 700, which itself may be 600-800 feet tall, jackup rig 600 may be used in water depths of up to 900-1100 feet, thereby expanding the versatility and range of jackup rig 600.
Referring to FIGS. 49-63, wherein a tension-leg platform 800 (TLP 800) is shown being deployed offshore and anchored base 110. Referring first to FIG. 49, TLP 800 may be any conventional TLP including a deck 801 supported above the sea surface 102 on a buoyant hull 802. In this embodiment, hull 802 comprises an adjustably buoyant horizontal base 803 disposed below the sea surface 102 and a plurality of adjustably buoyant columns 804 extending vertically from base 803 through the sea surface 102 to deck 801. Additionally, TLP 800 further comprises a plurality of tendons 805 extending from horizontal base 803. Tendons 805 are used to anchor TLP 800 to the sea floor 101.
In this embodiment, TLP 800 is anchored to base 110, which is secured to the sea floor 101 with a plurality of anchors 930 installed in guides 120 as best shown in FIGS. 50-56. anchors 930 are on base 110 in lieu of anchors 130. In this embodiment, each anchor 930 is the same as anchors 130 previously described except that each anchor 930 comprises a pair of tendon termination couplings 904 mounted on the upper end thereof. In this embodiment, tendon termination couplings 904 are termination pedestals 904. In general, any suitable mechanical coupling for receiving and releasably securing the lower end of a tendon of a TLP (e.g., tendon 805 on TLP 800) to anchor 930 can be used such as a ball-grab connector. While two termination pedestals 904 are shown, other embodiments of anchors 930 may have a fewer or greater number of termination pedestals 904 installed thereon while still complying with the basic principles of this disclosure. As is shown in FIGS. 50-56, installation of anchors 930, is the same as previously described for anchors 130. Specifically, anchors 930 are suction piles installed by the methods described above and shown in FIGS. 10 and 11.
Referring to FIG. 57, in order to transport TLP 800 to the desired offshore location, the buoyancy of hull 802 is adjusted to achieve a stable configuration and then TLP 800 is floated out to the offshore location. Moving now to FIGS. 57 and 58, TLP 800 is positioned over the installed base 110 and the buoyancy of hull 802 is adjusted for installation of tendons 805. For example, TLP 800 may be ballasted to allow installation of tendons 805. Next, tendons 805 are coupled to hull 802 and, as is best shown in FIGS. 59-63, are coupled to the installed anchors 930 via tendon termination pedestals 904. Referring back to FIG. 49, once all of the tendons 805 have been coupled to both hull 802 and assembly 900, hull 802 is de-ballasted to place tendons 805 in tension. Although TLP 800 is shown anchored to base 110 in this embodiment, it should be appreciated that TLP 800 may also be anchored to a subsea tower assembly including more modular components than base (e.g., combinations of base 110, sub-frame 141, sub-frame 142, sub-frame 143, etc.).
In the manner described, tower assembly 900 may be utilized to effectively increase the depth of water in which TLP 800 may be used for a set of tendons 805 having a finite length. For example, if each tendon 805 is about 800 feet long, TLP 800 by itself can generally be used in water depths up to about 800 feet. However, by connecting tendons 805 to a base 110 or a subsea tower assembly, which itself may be up to 600-800 feet tall, TLP 800 may be used in water depths of up to 1400-1600 feet, thereby expanding the versatility and range of TLP 800 without the need for increased length tendons 805.
While preferred embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teachings herein. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the systems, apparatus, and processes described herein are possible and are within the scope of the invention. For example, the relative dimensions of various parts, the materials from which the various parts are made, and other parameters can be varied. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims. Unless expressly stated otherwise, the steps in a method claim may be performed in any order. The recitation of identifiers such as (a), (b), (c) or (1), (2), (3) before steps in a method claim are not intended to and do not specify a particular order to the steps, but rather are used to simplify subsequent reference to such steps.
