OA12898A

OA12898A - Offshore platform with vertically-restrained buoy and well deck.

Info

Publication number: OA12898A
Application number: OA1200500034A
Authority: OA
Inventors: Edward E Horton Iii
Original assignee: Deepwater Technologies Inc
Priority date: 2002-08-07
Filing date: 2003-08-05
Publication date: 2006-10-13
Also published as: EP1540127B1; AU2003257153A1; BR0313324A; AU2003257153A8; WO2004015239A2; DK1540127T3; US20040052586A1; EP1540127A2; BR0313324B1; WO2004015239A3

Abstract

An offshore floating platform for the drilling and/or production of petroleum products from the seabed includes a production deck and a buoyancy apparatus vertically guided and restrained within the platform. The buoyancy apparatus includes a well deck on its upper surface on which are mounted at least two surface trees. At least two vertical risers are supported by the buoyancy apparatus and are attached to the well deck. Each of the risers is connected to one of the surface trees and extends down through the buoyancy apparatus for connection to a seabed wellhead. At least one tendon assembly secures the buoyancy apparatus to the seabed. The tendon assembly is constructed with at least two concentric tubular tendon elements, and it is attached to the well deck and extends along the vertical centerline of the buoyancy apparatus. A manifold on the well deck is fluidly coupled to the surface trees through a pressure reduction choke, and a low pressure jumper fluidly couples the manifold to petroleum handling apparatus on the production deck.

Description

1 012898

OFFSHORE PLATFORM

WITH VERTICALLY-RESTRAINED BUOY AND WELL DECK CROSS-REFERENCE TO RELATED APPLICATIONS[0001] This application daims the benefit, under 35 U.S.C. Section 119(e), of co-pendingProvisional Application No. 60/478,914, filed June 16, 2003, and it is a continuation-in-part ofco-pending Application Serial No 10/213,967, filed August 7,2002, the disclosures of which are 5 incorporated herein by reference.

FEDERALLY-SPONSORED RESEARCH OR DEVELOPMENT

Not Applicable

BACKGROUND OF THE INVENTION 10 [0002] The présent invention relates to offshore platforms, and specifically to offshore platformsdesigned for dry tree applications. More particularly, the présent invention relates to a newproduction and/or drilling riser system used in deep draft dry tree offshore platforms.

[0003] Conventional dry tree offshore platforms are low heave floating platforms, such as spars, 15 TLPs (Tension Leg Platforms), and deep draft semi-submersible platforms. These platforms areable to support a plurality of vertical production and/or drilling risers. These platforms cancomprise a well deck, where the surface trees (arranged on top of the riser) will be located, and aproduction deck where the petroleum product (e.g., crude oil or natural gas) will be distributed toa processing facility to separate water, oil and gas. These two decks are part of the huit of the 20 offshore platform. In a conventional dry tree offshore platform, vertical risers running fiom thewell head to the well deck are supported by a tensioning apparatus. These vertical risers arecalled Top Tensioned Risers (TTRs).

[0004] Offshore environmental conditions axe often harsh. Actions of wind, waves and currents 25 can hâve significant effects on an offshore structure, especially in the uppermost layer of the sea,between the surface and a depth of about 150 - 300 ft. (about 45m to about 90m), which is called 2 012898 the "near surface wave action zone". These actions attenuate with the water depth. In TLPs or semi-submersible platforms, the vertical risers are subjected to the effects of waves and currents in the splash zone, which puts strain on the risers and can lead to VTV (Vortex Induced

Vibrations), thereby requiring expensive VIV strakes to be installed on each riser. In spar 5 platforms, the vertical risers are protected from the effects of waves and currents in the splashzone by a center well.

[0005] There are two conventional designs for applying tension to the TTRs respectivelyillustrated in Figures 10A and 10B. The fîrst design, shown in Figure 10A, uses one or more 10 passive buoyancy cans 10 to independently support a riser 12. Figure 10A shows a top tensionedriser a rrangement 12 w ith b uoyancy c ans 10, ofatypethatism ainly e mployed ο n s par-typefloating platforms, as disclosed and claimed in US 4,701,321 - Horton. Each riser 10 extendsvertically from a wellhead 14 on the seabed to the top of a well deck 18 of the offshore platform.The riser passes from the wellhead 14 through akeelj oint 20 into the center well 22 of the 15 buoyancy c ans 1 0. Inside the center well 22, the riser 1 2 passes through a stem pipe 24 thatpasses through the center of the buoyancy cans 10. The stem pipe 24 extends above thebuoyancy cans 10 and supports the well deck 18 to which the riser 12 and a surface tree 26 areattached. The buoyancy cans 10 and the stem pipe 24 are guided at several locations in the centerwell 22 by a plurality of riser guides 28. Because the risers 12 are independently supported by 20 the buoyancy cans 10 (relative to the hull), the hull is able to move up and down relative to therisers 12, and thus the risers 12 are isolated from the heave motions of the offshore platform. Thebuoyancy cans 10 need to provide enough buoyancy to support the required top tension in therisers 12, as well as the combined weight of the cans 10, the stem pipe 24, and the surface tree26. With increased depth, the buoyancy required to support the riser System will 25 correspondingly increase, requiring larger buoyancy cans 10. Consequently, the size ofthe center well 22 will increase proportionately. Designing and manufacturing individualbuoyancy cans 10 for each riser 12 is also costly.

[0006] The second conventional design, shown in Figure 10B, uses an active hydraulic

3 ► tensioning mechanism to mdependently support the risers 12. Each riser 12 extends verticallyfrom the wellhead 14 to the production deck 32 of the offshore platform. The riser 12 issupported by active hydraulic cylinders 30 connected to the well deck 18 of the offshoreplatform, allowing the hull to move up and down relative to the risers 12 and thus partially 5 isolating the risers 12 from the heave motions of the hull. A surface tree 26 is connected to thetop o f the r iser 12. As the r equired t ension and stroke i ncrease i n m agnitude, t he s ize o f t hehydraulic cylinders 30 correspondingly increases and may become prohibitively expensive.Furthermore, the loads hâve to be supported by the offshore platform. 10 [0007] For TLPs and deep draft semi-submersible platforms, riser tensioning Systems similar to the above-described designs can be used, although designs employing hydraulic tensioners aremore common.

[0008] In both designs, the tensioning device allows the isolation of the risers from the heave 15 motions of the offshore platform. However, as each riser is independently supported, the welldeck as well as the production deck will move up and down relative to the surface trees.Consequently, in order to absorb these motions, high pressure flexible jumpers 34 (Figures 10Aand 10B) are required to connect each surface tree in the well deck area to a manifold (notshown) on the production deck 32 which carries the liquid petroleum product to a processing 20 facility to separate water, oil and gas. The high pressure flexible jumpers 32 are expensivecompared to rigidpiping and can leadto designproblems, especially in high pressure / hightempérature environments.

[0009] The prior art, as exemplified in US 5,439,321, US 4,995,762 and US 4,913,238, proposes 25 to connect ail the TTRs to a single (independent from the work platform) buoyancy apparatus inorder to create a small well deck TLP to receive the riser. The small well deck TLP is anchoredwith tendons connected to the outer periphery of the buoyancy apparatus. The small well deckTLP has a low natural period in the range of 2-3 seconds, and will hâve the same problems as theconventional TLP (e.g., high cost, springing and ringing problems). Furthermore, as the small 012898 well deck TLP is completely independent from the work platform, the tendons will hâve to be designed to limit the horizontal motion of the small well deck TLP. These concepts will require at least four tendons arranged on the outer periphery of the small well deck TLP, and risers will be arranged in between these tendons. In addition to the cost of these tendons, one must solve the 5 problem of collision between the risers themselves, and between the risers and tendons, byproviding sufficient spacing between the several risers, and between the risers and the tendons.This leads either to a large buoy to accommodate several risers, or a small number of riserssupporting by the small well deck TLP. Furthermore, high pressure jumpers are still required toconnect each surface tree to the manifold of the production deck. 10

SUMMARY OF THE INVENTION

[0010] The présent invention addresses the problems just described and proposes a new passivetensioning system for top-tensioned risers in dry tree f loating platforms, most advantageonslyspars and deep draft semi-submersible platforms. Rather than tensioning independently each 15 vertical riser with individual buoyancy cans or individual hydraulic tensioners, the présentinvention provides for tensioning ail the risers with a single buoyancy apparatus, which can be alarge single buoyancy can or a multi cellular buoyancy apparatus. For the purposes of thisdescription, a “deep draft” semi-submersible floating platform is definedas a low-heave platformhaving a draft of at least about 150 ft. (45m), and able to guide or receive top-tensioned risers. 20 [0011] A first unique feature of the présent invention is that, contrary to prior art (where the welldeck is supported by the offshore platform), the single buoyancy apparatus includes the welldeck arranged on its top surface. Since the risers are connected to the same buoyancy apparatus,they act as a single riser system, and surface trees on top of the risers can be rigidly attached on 25 top of the buoyancy apparatus. Consequently, ail the surface trees can be connected to amanifold ο n t he w ell d eck ( not t he p roduction d eck) w ith r igid p iping. The c rude o il w ill b echoked down in the entry of the manifold, and, contrary to the prior art, one or just a few lowpressure flexible jumper(s) (or rigid articulated arms) can be used to carry the liquid petroleumproduct (e.g., crude oïl) to the processing equipment on the production deck. The use of a small 012898 number (as low as one) of low pressure flexible jumpers or articulated rigid arms will considerably reduce the cost of the riser System as well as the required deck room.

[0012] A second unique feature is the use of concentric tendons attached at the well deck (or top 5 of the single buoyancy apparatus) on the center line of the single buoyancy apparatus. When onetendon is used, it will be connected to the well deck on the centerline of the buoyancy apparatus.When more tendons are used, their centroid will be close to the vertical centerline of theapparatus. The use of central tendons limits the over-stressing of the risers and the requirementfor a reinforced wellhead foundation, as tension loads will be withstood principally by the 10 tendons themselves and their foundation.

[0013] The use of concentric tendons will provide much flexibility in the design of the tendonsto achieve the required dynamic behavior. Three factors are important in the design of thetendons: (1) The tendons must be strong enough to withstand the maximum static and dynamic 15 loads imparted to them by the spar. (2) The buoyancy apparatus must impart suffîcient upwardtension at the top of the tendons to prevent them from going slack at the base. (3) The tendonsmust hâve suffîcient axial stiffness to keep the riser system from going into résonance due tocyclic wave forces. 20 [0014] Contrary to the prior art, the présent invention avoids the need to hâve several tendons arranged in the outer periphery of the buoy, and thus reduces the cost of the riser System andsimplifies the resolution of the problems of riser and riser/tendon collisions.

BRIEF DESCRIPTION OF THE DRAWINGS 25 [0015] Figure 1 shows a cross-sectional view of one exemplary embodiment of a floating platform in which the risers are supported by a single buoyancy System and arecoupled to acentral tendon assembly for restraining the vertical motion of a single buoyancy System; [0016] Figure 2 showsa cross sectional view ofthe floating p latform in which the risers are 6 012898 supported by a single buoyancy system, vertically restrained by central tendons, the riser being independent from the central tendon; [0017] Figure 3 shows a cross sectional view ofthe floating platform in which the risers are5 supported by a single buoyancy System; [0018] Figure 4 shows a cross-sectional view of the floating platform in which the singlebuoyancy system also supports the drilling rig and its associated equipment; 10 [0019] Figure 5 shows a top view of the well deck arrangement; [0020] Figure 6A is an elevational view, partially in axial cross-section, showing one exemplaryembodiment of the tendon riser arrangement; 15 [0021] Figure 6B is a cross-sectional view taken along line 6B - 6B of Figure 6A; [0022] Figure 7 shows another exemplary embodiment for the single buoyancy system whereinthe buoyancy system comprises a plurality of vertical tubes closely spaced and connectedtogether through elongated vertical webs; 20 [0023] Figure 8 shows the use of the invention in a deep draft semi-submersible platform; [0024] Figure 9 shows one exemplary embodiment of the well deck arrangement on top of thebuoyancy system; and 25 [0025] Figures 10A and 10B show prior art riser Systems. DETAILED DESCRIPTION OF THE INVENTION[0026] Figure 1 shows one exemplary embodiment of the invention used in a spar type floating 012898 platform 100. Figure 1 shows the spar type platform 100 having a spar hull 102 defining a center well 104. A vertically restrained b uoyancy apparatus 106 is guidedin at leasttwo locations (upper and lower) within the center well 104 of the spar hull 102. This spécifie spar type platform 100 comprises an upper hull and a lower hull. The upper hull and the lower hull share 5 the continuous hollow center well 104, which surrounds and guides the center well buoyancyapparatus 106. The upper hull includes a cellular structure comprising several compartments 108for buoyancy purpose (void tanks and variable ballast tanks). The lower hull includes a sleeve110 with a fixed ballast 112 near the bottom of the lower hull to lower the center of gravity andthus improve the stability of the platform 100, The spar type platform 100 supports a work 10 platform 114 comprising a production deck 116, compartments 118 for crew quarters andutilities, and a drilling deck 120 for drilling equipment, such as a drilling rig 122. The floatingplatform 100 is moored with latéral mooring fines 124 in a taut leg mooring configuration orcatenary mooring configuration. The latéral mooring fines 124 are designed to limit thehorizontal movement of the floating platform 100 relative to seabed wellheads to specified limits 15 to prevent the risers (described below) from being over stressed.

[0027] Tuming now to the riser System, plural top-tensioned risers 126 are tensioned by a singlebuoyancy apparatus 106 guided in the center well 104 of the spar hull 102. The buoyancyapparatus 106 can be a single large buoyancy can or a multi-cellular buoyancy System (described 20 below and shown in Figure 7). Although the spar hull 102 constrains the center well buoyancyapparatus 106, the center well buoyancy apparatus 106 is itself free floating within the centerwell 104. Because the spar hull 102 and the center well 104 are each free-floating, the spar hull102 moves to accommodate the environmental forces acting on it, and thus moves with respect tothe vertically restrained center· well buoyancy apparatus 106. Thus the spar hull 102 heave 25 motion is decoupled from the center well buoyancy apparatus 106. This isolâtes the risers 126that are supported by the center well buoyancy apparatus 106 from the heave motion of the spartype platfonn 100 due to waves and currents. Furthermore, at least First and second pluralities ofguides 128 are provided in the center well 104 at selected, axially-spaced locations, and at leastat upper and lower locations, to guide the buoyancy apparatus 106 within the center well 104. 8 012898

By reducing the peripheral gap between the spar hull 102 and the buoyancy apparatus 106, the guides 128 significantly reduce the impact loads between the hull 102 and the buoyancy apparatus 106 due to wave and current actions on the outer hull. Preferably, the buoyancy apparatus 106 and the guides 128 are in actual physical contact. To absorb, and thereby further 5 reduce, the impact loads, the guides 128 advantageously include compilant pads (such aselastomeric pads) (not shown) that are positioned to be compressed against the buoyancyapparatus 106.

[0028] A unique feature o f this i nvention i s that a w ell d eck 1 30 is p ositioned on top o f the 10 buoyancy apparatus 106, and ail the risers 126 extend from the well deck 130 to wellheads 132on the seabed.

[0029] In this spécifie embodiment, at least one central tendon assembly 134, comprising at leasttwo concentric tubular tendon éléments 136 (Figures 6A, 6B), secures the buoyancy apparatus 15 106 to the seabed. As shown in Figure 1, the tendon assembly 134 is attached at its upper end to the center of the well deck 130, and it extends down along the centerline of the buoyancyapparatus 126 to a tendon foundation in the seabed. The tendon foundation is of conventionaldesign, described more fully below, comprising a caisson pile 138 anchored in the seabed, and aconnective sleeve 140 connecting the tendon assembly 134 to the caisson pile 138. The 20 advantage o f u sing a c entrai t endon a ssembly 134isthatitcanbed esigned ( in t erms o f t hephysical characteristics of the tendons the tendon foundation) to withstand rnost of the tensionload, thereby reducing the tension loads in the risers 126. Thus, the requirement for reinforcedfoundations for the wellhead 132 will be further reduced, which is particularly advantageous inultra deep water where the tension requirement can be quite critical. 25 [0030] As shown in Figures 6A and 6B, the tendon assembly 134 may be designed specificallyas a tendon, or it may be designed as a riser that functions as a tendon with a reinforced wellheadfoundation. In this embodiment, the tendon assembly 134 and a plurality of surrounding risers126 are coupled together with a plurality of vertically-spaced riser spacers or guides 144, only 012898 one of which is shown in the drawings. The couplmg of the risers 126 with the tendon assembly 134 helps prevent the risers 126 and the tendon assembly 134 from clashing or colliding with one another due to floating platform movement. It will not be necessary to space the several tendon assemblies from each other to avoid colliding, and a smaller center well 104 can be used which 5 will significantly reduce the cost of the riser assembly 134 as well as the cost of the floatingplatform 100. Furthermore, the tension factor required for the risers 126 will be smaller, becausethe risk of colliding is reduced, thus reducing the size of the buoyancy apparatus 126. Thecoupling of the risers 126 with the tendon assembly 134, as well as the design of the tendonassembly 134 and the riser 126, will be explained in further detail below. 10 [0031] As shown in Figure 1, the upper portions of the risers 126 are uncoupled from the tendonassembly 134 within the upper portion of the center well 104, to allow the connection of eachriser 126 to a respective surface tree 170, and the connection of tendon assembly 134 to a tendonsocket or slot 146 (Figure 5) in the well deck 130. Similarly, the bottom portions of the risers 15 126 are uncoupled from the tendon assembly 134 to allow the connection of the risers 126 to their respective wellheads 132 and the connection of the tendon assembly to the tendonfoundation, [0032] Figure 2 shows another exemplary embodiment of the invention used in a spar type 20 floating platform 200, which includes risers 226 that are uncoupled from a tendon assembly 234.This embodiment provides a simplifîed riser and tendon construction (no need of riser spacers orguides), but the risers 226 and the tendon assembly 234 will hâve to be sufficiently spaced andwill hâve to be tensioned sufficiently to avoid any collision between the risers 226 themselvesand between the risers 226 and the tendon assembly 234. Accordingly, this embodiment requires 25 a center well 204 that must be larger than that of the embodiment of Figure 1.

[0033] Figure 3 shows another exemplary embodiment of the invention used in a spar typefloating platform 300. In this particular embodiment, there is no spécifie tendon used forvertically restraining the single buoyancy apparatus 306. Instead, this embodiment employs 10 012898 risers 326 and wellhead foundations 346 that are designed to vertically restrain the center well buoyancy apparatus 306.

[0034] Figure 4 shows another exemplary embodiment of the invention used in a spar type 5 floating p latform 4 00. T his p articulai embodiment e mploys a c enter w ell b uoyancy apparatus406 that, in addition to a well deck 430, supports a drilling deck 420 with a drilling rig 422 andits associated equipment (drilling and work over), while the work platform supported by thefloating structure comprises a production deck 416 with compartments 418 for crew quarters andutilities. The decks 416, 420 are conventional decks used on floating structures such as spars, 10 TLPs or deep draft semi-submersible platforms. As the buoyancy apparatus 406 is verticallyrestrained, the drilling and work over operations will be less weather dépendant.

[0035] In sorne embodiments, because there will be no relative vertical motion between thedrilling riser and the drilling rig, there will be no requirement for a slip joint arranged on the 15 drilling riser to absorb these vertical motions. The embodiment of Figure 4 employs risers 426and tendons 442 that are coupled; however, the risers and the tendons can be uncoupled asshown in Figure 2, or the buoyancy apparatus can be vertically restrained by the riser itself, asshown in Figure 3. The embodiment of Figure 4 do es, however, require additional buoyancy tosupport the extra weight of the drilling/work over equipment. 20 [0036] As illustrated in Figures 1-4, the tendons and/or the risers are secured to the seabed at oneend (wellhead or tendon foundation), and to the well deck on the center well buoyancy apparatusat the othér end. 25 [0037] Figure 5 shows a horizontal cross sectional view of an example of a well deck assembly500, The well deck assembly includes a well deck 130 having a tendon Socket or slot 146 in itscenter to receive a tendon assembly 134. Around the tendon slot 146 are several riser sockets orslots 548. There is a space that serves as a tendon riser center well 550 around the tendon socket146 to provide space for running equipment down to the seabed (for example landing bases, 11 012898 blow-ouî preventers, or any other equipment that will occur to those of ordinary skill in the art).

On either side of the tendon riser center well 550 is a drilling well or moon pool 552. The moon pools 552 also provide space for performing drilling and work over operations or for running equipment down to the seahed. As shown in Figure 5, the center well buoyancy apparatus 106 is 5 guided with a plurality of guides 128 (four guides, in this example), arranged around itsperimeter. The number of guides 128 may be varied from as few as two to fîve or more,depending on the loads they are to absorb.

[0038] In Figures 1 to 5, only one tendon assembly 134 attached to the well deck 130 and10 extending down the centerline of the buoyancy apparatus 106 is shown. However, in otherembodiments, there may be more than one tendon assembly aligned and/or parallel with thevertical centerline of the buoyancy apparatus. The various other embodiments may employmultiple tendon assemblies (not illustrated), closely arranged around the central tendon assembly. 15 [0039] As further shown in Figures 1-4, the tendon assembly 134 is secured to the seabed by acaisson pile 138, which is altematively called an anchor caisson or a suction pile. The caissonpile 138 secures the tendon assembly 134 to the seabed. As shown in Figure 1, the tendonassembly 134 may optionally be connected to the caisson pile by the tendon connection sleeve 20 140, which is located in the center of the caisson pile 138, through which the bottom end of the tendon assembly 134 is fixed to the seabed. Radial plates 154 connect the tendon assembly 134to the interior wall of the connection sleeve 140.

[0040] To install the caisson pile 138, in one embodiment, the caisson pile 138 is pushed into the 25 seabed by pumping water out of its interior. As water is pumped out, the ambient extemal waterpressure pushes the caisson pile 138 down into the seabed. In other embodiments, the caissonpile 138 is pushed into the seabed by means of submersible pumps (not shown), airlifts (notshown), or any other method that may suggest itself to those of ordinary skill in the art. With the caisson pile 138 firmly anchored in the seabed, the tendon connection sleeve 140 connects the tendon assembly 134 to the caisson pile 138, thereby securing the tendon assembly 134 to the seabed. 012898 12 5 [0041] In still another embodiment, at least one of the tubulax tendon éléments 136 of the tendonassembly 134 is drilled into the seabed and anchored therein by cernent. This increases the pull-out résistance of the tendon assembly 134. The tendon connection sleeve 140 is extended out ofthe bottom of the caisson pile 138, thereby providing a connector through which the tendonéléments 136 are drilled and connected. 10 [0042] It will be appreciated that the tendon assembly 134 may be secured to the seabed by anyother method that may suggest itself to those of ordinary skill in the art.

[0043] Figures 6A and 6B show the structural details of one exemplary embodiment of a tendon 15 assembly 134. The tendon assembly 134 comprises multiple (at least two) concentric tubulartendon éléments 136. The concentric tubular éléments 136 are secured to the well deck 130 onthe vertical centerline of the center well buoyancy apparatus 106, and they extend down to ananchor assembly at the seabed, as discussed above. The use of concentric tubular tendonéléments 136 provides great flexibility in the design of the tendons to achieve the required 20 dynamic behavior.

[0044] Three factors are important in the design of the tendon assemblies 134: (1) The tendonassemblies 134 must be strong enough to withstand the maximum static and dynamic loadsimparted on them by the buoyancy apparatus 106. (2) The buoyancy apparatus 106 must impart 25 suffïcient upward tension at the top of the tendon assemblies 134 to prevent them from goingslack at the bottom. (3) The tendon assemblies 134 must hâve suffïcient axial stiffness to keepthe riser/tendon assembly System from going into résonance due to cyclic wave forces. Byvarying the number of concentric tubular tendon éléments 136, both the strength and springcharacteristics are varied to meet spécifie design requirements on a case-by-case basis, as will 13 012898 occur to those of ordinary skill in the art.

[0045] There are other benefîts stemming from the above-described concentric tendon design.For example, corrosion and fatigue are minimized by the use of corrosion inhibitors in the 5 annular spaces defîned between the concentric tubular éléments 136. Furthermore, the use ofmultiple tubular tendon éléments 136 provides redundancy compared to prior art tendons, shouldone of the tubular éléments 136 fail. Another benefit is that the annular spaces can bepressurized to detect cracks and to check joint integrity. 10 [0046] As best shown in Figure 6A, the tubular tendon éléments 136 may further comprise conventional oilfield casing joints with a flanged coupling 156. In various embodiments, thecasing joints are of various sizes, depending on the required tensile loads. These loads vary on acase-by-case basis, as will occur to those of ordinary skill in the art. 15 [0047] In one embodiment, the tendon assembly 134 is installed in s écrions, in a section-by- section sequence, using the drilling rig 122 on the platform. Each section is installed on the deckand lowered using the rig, and the sections are connected using the flanged couplings 156. Theadvantages of installing the tendon assembly 134 in sections in this manner using the platform’sown drilling rig will be readily apparent to those skilled in the art. 20 [0048] Figure 6B shows a cross section of the tendon assembly 134 of Figure 6A, showing oneof the riser guides or spacers 144, which is also shown in Figure 6A. Each of the riser guides144 couples each tendon assembly 134 to the adjacent risers 126. The riser guides 144 separatethe risers 126 from one another and from the central tendon assembly 134, thereby preventing 25 the risers 126 and the tendon assembly 134 from clashing or colliding with each other. Each ofthe riser guides 144 comprises a central tendon conduit 158, through which the tendon assembly134 passes, and a plnrality of riser conduits 160 through which the risers 126 pass. The riserguides 144 are secured to the tendon assembly 134, and they may or may not be secured to therisers 126. As mentioned above, in the preferred embodiments of the invention, there are several 14 012898 vertically-spaced riser guides or spacers 144, separated by a vertical distance of about 15 ft. (4.5m) to about 70 ft. (21m), depending on the design parameters of the particular platform.

[0049] The tendon conduit 158 and the riser conduits 160 are rigidly connected and separated by5 a web of séparation members 162. By rigidly separating the riser conduits 160 and the centraltendon conduit 158, the risers 126 passing through the riser conduits 160 are separated from thecentral tendon 134 assembly passing through the tendon conduit 158. This prevents the risers 126 and the tendon assembly 134 from clashing or colliding below the keel of the platform dueto waves, currents, and floating platform motion, which can occur even when it is subjected to 10 light océan currents. In other embodiments (e.g., that of Figure 2), the risers are not coupled tothe tendon assembly by means such as the riser guides 144.

[0050] In the various embodiments of the présent invention, a wide range of riser types may beused to connect the wellhead to the platform. The various types of risers include those used for 15 drilling, production, and workover, as will occur to those skilled in the pertinent arts. Forexample, in alternative embodiments, the risers are drilling risers used with full sub-sea blow-outpreventor (BOP) stacks, pressure risers with surface BOPs, and those used with split BOPs (e.g.,a surface BOP for well control and a limited function BOP on the seabed). Still furtherembodiments may employ production risers and workover risers used with surface trees, sub-sea 20 trees, split trees, wet trees, dry trees, or any other type of tree that may suggest itself to thoseskilled in the pertinent arts. In still another embodiment, the platform is designed for verticalentry into the well. Altematively, the platform may be designed for any other directional entryinto the well. 25 [0051] The spring characteristics of the risers and/or tendons, when acting together, hâve to be such that the riser system does not respond significantly to the waves, taking into account themass of the System and the draft of the floating platform. A plurality of risers and/or tendons willact together with a spring characteristic and a strength characteristic for the group of risers and/ortendons. Said differently, the risers and /or tendons act as a system, and their structural and 15 012898 spring properties achieve a uniform behavior for the group of riser and/or tendons.

[0052] One of the key aspects of this invention is the interaction between the risers or of therisers with the tendons when subjected to the movement of the floating support. As an example, 5 when the floating platform is subjected to environmental forces, the distance between thewellhead on the seabed and the riser slot at the keel increases for the upstream riser anddecreases for the downstream riser. Should a tendon be used, these distances will be alsodifferent. This means that the spring characteristics, in considération of the hydrodynamic andgravitational forces, hâve to be selected so that the riser System will act in unison, and the10 séparation between the risers will be maintained to avoid clashing and collisions as the floating platform moves.

[0053] Reference is again made to Figures 1-4. As the riser System is protected by the centerwell of the spar platform, the riser system will be excited only at the keel of the spar (for 15 example, at about 500 fit or about 150m of water depth). Because the influence of waves andcurrents is minimized at this water depth and the area of excitation is small, the natural period ofthe riser assembly when the tendons and/or risers are connected does not need to be as short asthe period of a conventional TLP and thus can be designed to be above the 2 to 3 second range.Thus, the requirement for axial stiffness will be reduced, and the tendon will require 20 considerably less Steel than a comparable tendon for conventional TLP.

[0054] Figures 1-4 illustrate the use of the présent invention in a spar type floating platform.However, the invention may be applied to any deep draft floating platform, such as for example,conventional deep draft submersible platforms or self-installing deep draft submersible 25 platforms.

I

[0055] Figure S shows the use of the présent invention in a deep draft semi-submersible platform600, As shown, a vertically restrained buoy 606, which supports a plurality of top-tensionedrisers (TTRs) 608, is guided within the hull of the deep draft semi-submersible platform 600 by a 16 012898 lower guide assembly 610 provided in the base 612 of the floating platform 600, and an upper guide assembly 614 provided in a work deck 616 supported by the hull. In this spécifie example, the single buoy 606 supports only a well deck 618 and the TTRs 608. However the buoy 606 can be designed to support the drilling deck and the drilling equipment as shown in'Figure 4 for a

5 spar-type platform. In this example, the buoy 606 is vertically restrained by the TTRs 608 only(as shown in Figure 3 for a spar-type platform). Altematively, however a tendon assemblycoupled or uncoupled with the riser can be used to vertically restrain the buoy 606. As opposedto a spar type platform, this vertically restrained buoy 606 will not be protected by a center wellin the splash zone, and will be subjected to wave and current action which can lead to VIV 10 problems. Since the diameter of the vertically restrained buoy 606 is large compared to a riser608, the tension of the riser System can be designed to limit the VIV problem, or VIV strakes(not shown) can be provided on the outer periphery of the buoy 606.

[0056] Tuming now to another feature of this invention, the vertically restrained buoy is guided 15 by guide assemblies provided in the floating platform in at least two locations (upper and lower),whether the platform is a spar-type platform or a deep draft semi-submersible platform. Whilethe floating platform is pitching, the contact loads between the buoy and the guide assembliesprovide to the floating platform a restoring moment. This restoring moment allows animprovement (reducing the pitch angle) in the pitch motion of the floating structure. Indeed, this 20 resulting moment is proportional to the weight of the risers supported by the buoy (which can be i quite important, especially in deeper water).

[0057] Figure 7 shows another embodiment of the vertically restrained buoy. In ail theembodiments already described, the vertically restrained buoy comprises a single, large 25 buoyancy can. To achieve a high degree of compartmentalization, the buoy must be divided intocompartments by a plurality of internai latéral bulkheads, thereby increasing the cost ofmanufacturing the buoy. Furthermore, because the risers and/or tendons pass through the buoy,the intersections between the risers and the bulkheads must be sealed by welding using a heavywelding procedure. In the embodiment shown in Figure 7, a vertically restrained buoyancy 17 012898 apparatus 700 comprises an assembly of a plurality of vertical tubes 702 closely spaced and connected together by vertically-elongated webs 704. This arrangement provides a high degree of compartmentalization with few bulkbeads and thus at a reduced cost. Furthermore, the risers 126 can be arranged around the vertical tubes 702 (i.e. in the interstices defîned in between the 5 vertical tubes) and will not hâve to cross through any buoyancy compartment, thereby avoidingthe problem of sealing the intersections of the risers with the bulkheads.

[0058] In ail the described embodiments, the weîl deck is supported directly by the verticallyrestrained buoy, the surface trees are attached on the well deck, and there are no relative motions 10 between the surface trees and the well deck. To carry the crude oil to the production deck and theprocess equipment to separate oil, water and gas, high pressure flexible jumpers can be used toconnect each sub-seatree to t he p roduction deckmanifold. However, a unique feature of theprésent invention, shown in Figure 9, is that contrary to the prior art (where the well deck issupported by the offshore platform), the single buoyancy apparatus 106 includes the well deck 15 130 arranged on its top surface. Since the risers 126 are connected to the same buoyancy apparatus 106, they act as a single riser System, and surface trees 170 connected to upper ends ofthe risers 126 can be rigidly attached to the top of the buoyancy apparatus 106.

[0059] Consequently, ail the surface trees 170 can be connected to a manifold 172 situated on 20 the well deck 130 (rather than the production deck) with rigid piping 174. The crude oil will bechoked down by a pressure-reduction choke 176 in the inlet of the manifold 172, and, contrary tothe prior art, as few as one low pressure flexible jumper 178 (or, altematively an articulated rigidarm, not shown) can be used to carry the crude oil to the processing equipment on the productiondeck 116. The use of just one flexible jumper 178, or perhaps a few flexible jumpers (or 25 articulated rigid arms) will considerably reduce the cost of the riser System as well as therequired deck room.

Claims

012898 18 WHATIS CLAIMED IS:

1. A riser system for use in a deep draft floating platform, the riser System comprising: a buoyancy apparatus having an upper portion and a lower portion guided within thefloating platform, the buoyancy apparatus having an upper surface;a well deck provided on the upper surface of the buoyancy apparatus; 5 at least two vertical risers supported by the buoyancy apparatus and attached to the well deck and extending down through the buoyancy apparatus for connection to a seabedwellhead; and at least one tendon assembly securing the buoyancy apparatus to the seabed;wherein the tendon assembly comprises at least two concentric tubular tendon éléments; 10 and wherein the tendon assembly is attached to the well deck and extends along the verticalcenterline of the buoyancy apparatus.
2. The riser System of Claim 1, wherein the tension loads are absorbed principally by the tendon15 assembly.
3. The riser System of Claim 1, wherein the platform includes a drilling deck supported by thebuoyancy apparatus.
4. The riser System of Claim 1, wherein the risers are coupled to the tendon assembly.
5. The riser System of Claim 1, wherein the risers and the tendon assembly are uncoupled.
6. The riser System of Claim 1, wherein the platform includes a surface tree on the well deck. 25
7. The riser System of Claim 6, wherein the platform includes a manifold on a production deck,and a jumper fluidly connecting the surface tree to the manifold. 19 012898
8. The riser System of Claim 1, wherein the buoyancy apparatus includes a moon pool.
9. The riser System of Claim 1, wherein the buoyancy apparatus comprises a single elongatetubular buoy. 5
10. The riser System of Claim 1, wherein the buoyancy apparatus comprises a plurality ofinterconnected elongate tubular buoys.
11. The riser System of Claim 1, wherein each of the tubular tendon éléments comprises a 10 plurality of sections connected with casing joints.
12. The riser System of Claim 1, wherein the tendon assembly comprises a riser specifïcallydesigned to fonction as a tendon. 15 13. A deep draft floating platform for drilling and/or production of petroleum from the seabed, comprising: a production deck including petroleum handling apparatus;a buoyancy apparatus guided within the platform and having an upper surface;a well deck provided on the top surface of the buoyancy apparatus; 20 at least two surface trees on the well deck; at least two vertical risers extending ftom the seabed to the surface trees;a manifold on the well deck and fluidly coupled to the surface trees through a pressure réduction choke; and a low pressure jumper fluidly coupling the manifold to the petroleum handling apparatus 25 on the production deck.
14. The platform of Claim 13, forther comprising a drilling deck supported by the buoyancyapparatus. 20 012898
15. The platform of Claim 13, wherein the buoyancy apparatus includes a moon pool.
16. The platform of Claim 13, wherein the buoyancy apparatus is guided within the platform atan upper part of the buoyancy apparatus and at a lower part of the buoyancy apparatus. 5
17. The platform of Claim 13, wherein the jumper is a low pressure flexible pipe.
18. The platform of Claim 13, wherein the jumper is an articulated rigid arm.
19. The platform of Claim 13, wherein the buoyancy apparatus comprises a single elongate tubular buoy.
20. The platform of Claim 13, wherein the buoyancy apparatus comprises a plurality ofinterconnected elongate tubular buoys. 15
21. The platform of Claim 13, wherein the buoyancy apparatus is vertically restrained by therisers.
22. The platform of Claim 13, wherein the buoyancy apparatus is vertically restrained by a20 central tendon assembly passing axially through the buoyancy apparatus and connected to the well deck and to the seabed.
23. The platform of Claim 22, wherein the risers are coupled to the tendon assembly.
24. The riser System of Claim 22, wherein the risers and the tendon assembly are uncoupled.