Patent Publication Number: US-2004052586-A1

Title: Offshore platform with vertically-restrained buoy and well deck

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS  
     [0001] This application claims the benefit, under 35 U.S.C. Section 119(e), of co-pending Provisional Application No. 60/478,914, filed Jun. 16, 2003, and it is a continuation-in-part of co-pending application Ser. No. 10/213,967, filed Aug. 7, 2002, the disclosures of which are incorporated herein by reference. 
    
    
     
       FEDERALLY-SPONSORED RESEARCH OR DEVELOPMENT  
       [0002] Not Applicable  
       BACKGROUND OF THE INVENTION  
       [0003] The present invention relates to offshore platforms, and specifically to offshore platforms designed for dry tree applications. More particularly, the present invention relates to a new production and/or drilling riser system used in deep draft dry tree offshore platforms.  
       [0004] Conventional dry tree offshore platforms are low heave floating platforms, such as spars, TLPs (Tension Leg Platforms), and deep draft semi-submersible platforms. These platforms are able to support a plurality of vertical production and/or drilling risers. These platforms can comprise a well deck, where the surface trees (arranged on top of the riser) will be located, and a production deck where the petroleum product (e.g., crude oil or natural gas) will be distributed to a processing facility to separate water, oil and gas. These two decks are part of the hull of the offshore platform. In a conventional dry tree offshore platform, vertical risers running from the well head to the well deck are supported by a tensioning apparatus. These vertical risers are called Top Tensioned Risers (TTRs).  
       [0005] Offshore environmental conditions are often harsh. Actions of wind, waves and currents can have 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 45 m to about 90 m), which is called 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 VIV (Vortex Induced Vibrations), thereby requiring expensive VIV strakes to be installed on each riser. In spar platforms, the vertical risers are protected from the effects of waves and currents in the splash zone by a center well.  
       [0006] There are two conventional designs for applying tension to the TTRs respectively illustrated in FIGS. 10A and 10B. The first design, shown in FIG. 10A, uses one or more passive buoyancy cans  10  to independently support a riser  12 . FIG. 10A shows a top tensioned riser arrangement  12  with buoyancy cans  10 , of a type that is mainly employed on spar-type floating platforms, as disclosed and claimed in U.S. Pat. No. 4,701,321—Horton. Each riser  10  extends vertically 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 a keel joint  20  into the center well  22  of the buoyancy cans  10 . Inside the center well  22 , the riser  12  passes through a stem pipe  24  that passes through the center of the buoyancy cans  10 . The stem pipe  24  extends above the buoyancy cans  10  and supports the well deck  18  to which the riser  12  and a surface tree  26  are attached. The buoyancy cans  10  and the stem pipe  24  are guided at several locations in the center well  22  by a plurality of riser guides  28 . Because the risers  12  are independently supported by the buoyancy cans  10  (relative to the hull), the hull is able to move up and down relative to the risers  12 , and thus the risers  12  are isolated from the heave motions of the offshore platform. The buoyancy cans  10  need to provide enough buoyancy to support the required top tension in the risers  12 , as well as the combined weight of the cans  10 , the stem pipe  24 , and the surface tree  26 . With increased depth, the buoyancy required to support the riser system will correspondingly increase, requiring larger buoyancy cans  10 . Consequently, the size of the center well  22  will increase proportionately. Designing and manufacturing individual buoyancy cans  10  for each riser  12  is also costly.  
       [0007] The second conventional design, shown in FIG. 10B, uses an active hydraulic tensioning mechanism to independently support the risers  12 . Each riser  12  extends vertically from the wellhead  14  to the production deck  32  of the offshore platform. The riser  12  is supported by active hydraulic cylinders  30  connected to the well deck  18  of,the offshore platform, allowing the hull to move up and down relative to the risers  12  and thus partially isolating the risers  12  from the heave motions of the hull. A surface tree  26  is connected to the top of the riser  12 . As the required tension and stroke increase in magnitude, the size of the hydraulic cylinders  30  correspondingly increases and may become prohibitively expensive. Furthermore, the loads have to be supported by the offshore platform.  
       [0008] 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 are more common.  
       [0009] In both designs, the tensioning device allows the isolation of the risers from the heave motions of the offshore platform. However, as each riser is independently supported, the well deck 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  (FIG. 10A and 10B) are required to connect each surface tree in the well deck area to a manifold (not shown) on the production deck  32  which carries the liquid petroleum product to a processing facility to separate water, oil and gas. The high pressure flexible jumpers  32  are expensive compared to rigid piping and can lead to design problems, especially in high pressure/high temperature environments.  
       [0010] The prior art, as exemplified in U.S. Pat. No. 5,439,321, U.S. Pat. No. 4,995,762 and U.S. Pat. No. 4,913,238, proposes to connect all the TTRs to a single (independent from the work platform) buoyancy apparatus in order to create a small well deck TLP to receive the riser. The small well deck TLP is anchored with tendons connected to the outer periphery of the buoyancy apparatus. The small well deck TLP has a low natural period in the range of  2-3  seconds, and will have the same problems as the conventional TLP (e.g., high cost, springing and ringing problems). Furthermore, as the small well deck TLP is completely independent from the work platform, the tendons will have 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 problem of collision between the risers themselves, and between the risers and tendons, by providing 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 risers supporting by the small well deck TLP. Furthermore, high pressure jumpers are still required to connect each surface tree to the manifold of the production deck.  
       SUMMARY OF THE INVENTION  
       [0011] The present invention addresses the problems just described and proposes a new passive tensioning system for top-tensioned risers in dry tree floating platforms, most advantageously spars and deep draft semi-submersible platforms. Rather than tensioning independently each vertical riser with individual buoyancy cans or individual hydraulic tensioners, the present invention provides for tensioning all the risers with a single buoyancy apparatus, which can be a large single buoyancy can or a multi cellular buoyancy apparatus. For the purposes of this description, a “deep draft” semi-submersible floating platform is defined as a low-heave platform having a draft of at least about 150 ft. (45 m), and able to guide or receive top-tensioned risers.  
       [0012] A first unique feature of the present invention is that, contrary to prior art (where the well deck is supported by the offshore platform), the single buoyancy apparatus includes the well deck 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 top of the buoyancy apparatus. Consequently, all the surface trees can be connected to a manifold on the w ell deck (not the production deck) with rigid piping. The crude oil will be choked down in the entry of the manifold, and, contrary to the prior art, one or just a few low pressure flexible jumper(s) (or rigid articulated arms) can be used to carry the liquid petroleum product (e.g., crude oil) to the processing equipment on the production deck. The use of a small 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.  
       [0013] A second unique feature is the use of concentric tendons attached at the well deck (or top of the single buoyancy apparatus) on the center line of the single buoyancy apparatus. When one tendon 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 the apparatus. The use of central tendons limits the over-stressing of the risers and the requirement for a reinforced wellhead foundation, as tension loads will be withstood principally by the tendons themselves and their foundation.  
       [0014] The use of concentric tendons will provide much flexibility in the design of the tendons to achieve the required dynamic behavior. Three factors are important in the design of the tendons: (1) The tendons must be strong enough to withstand the maximum static and dynamic loads imparted to them by the spar. (2) The buoyancy apparatus must impart sufficient upward tension at the top of the tendons to prevent them from going slack at the base. (3) The tendons must have sufficient axial stiffness to keep the riser system from going into resonance due to cyclic wave forces.  
       [0015] Contrary to the prior art, the present invention avoids the need to have several tendons arranged in the outer periphery of the buoy, and thus reduces the cost of the riser system and simplifies the resolution of the problems of riser and riser/tendon collisions. 
     
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
     [0016]FIG. 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 are coupled to a central tendon assembly for restraining the vertical motion of a single buoyancy system;  
     [0017]FIG. 2 shows a cross-sectional view of the floating platform in which the risers are supported by a single buoyancy system, vertically restrained by central tendons, the riser being independent from the central tendon;  
     [0018]FIG. 3 shows a cross-sectional view of the floating platform in which the risers a re supported by a single buoyancy system;  
     [0019]FIG. 4 shows a cross-sectional view of the floating platform in which the single buoyancy system also supports the drilling rig and its associated equipment;  
     [0020]FIG. 5 shows a top view of the well deck arrangement;  
     [0021]FIG. 6A is an elevational view, partially in axial cross-section, showing one exemplary embodiment of the tendon riser arrangement;  
     [0022]FIG. 6B is a cross-sectional view taken along line  6 B- 6 B of FIG. 6A;  
     [0023]FIG. 7 shows another exemplary embodiment for the single buoyancy system wherein the buoyancy system comprises a plurality of vertical tubes closely spaced and connected together through elongated vertical webs;  
     [0024]FIG. 8 shows the use of the invention in a deep draft semi-submersible platform;  
     [0025]FIG. 9 shows one exemplary embodiment of the well deck arrangement on top of the buoyancy system; and  
     [0026]FIGS. 10A and 10B show prior art riser systems. 
    
    
     DETAILED DESCRIPTION OF THE INVENTION  
     [0027]FIG. 1 shows one exemplary embodiment of the invention used in a spar type floating platform  100 . FIG. 1 shows the spar type platform  100  having a spar hull  102  defining a center well  104 . A vertically restrained buoyancy apparatus  106  is guided in at least two locations (upper and lower) within the center well  104  of the spar hull  102 . This specific spar type platform  100  comprises an upper hull and a lower hull. The upper hull and the lower hull share the continuous hollow center well  104 , which surrounds and guides the center well buoyancy apparatus  106 . The upper hull includes a cellular structure comprising several compartments  108  for buoyancy purpose (void tanks and variable ballast tanks). The lower hull includes a sleeve  110  with a fixed ballast  112  near the bottom of the lower hull to lower the center of gravity and thus improve the stability of the platform  100 . The spar type platform  100  supports a work platform  114  comprising a production deck  116 , compartments  118  for crew quarters and utilities, and a drilling deck  120  for drilling equipment, such as a drilling rig  122 . The floating platform  100  is moored with lateral mooring lines  124  in a taut leg mooring configuration or catenary mooring configuration. The lateral mooring lines  124  are designed to limit the horizontal movement of the floating platform  100  relative to seabed wellheads to specified limits to prevent the risers (described below) from being over stressed.  
     [0028] Turning now to the riser system, plural top-tensioned risers  126  are tensioned by a single buoyancy apparatus  106  guided in the center well  104  of the spar hull  102 . The buoyancy apparatus  106  can be a single large buoyancy can or a multi-cellular buoyancy system (described below and shown in FIG. 7). Although the spar hull  102  constrains the center well buoyancy apparatus  106 , the center well buoyancy apparatus  106  is itself free floating within the center well  104 . Because the spar hull  102  and the center well  104  are each free-floating, the spar hull  102  moves to accommodate the environmental forces acting on it, and thus moves with respect to the vertically restrained center well buoyancy apparatus  106 . Thus the spar hull  102  heave motion is decoupled from the center well buoyancy apparatus  106 . This isolates the risers  126  that are supported by the center well buoyancy apparatus  106  from the heave motion of the spar type platform  100  due to waves and currents. Furthermore, at least first and second pluralities of guides  128  are provided in the center well  104  at selected, axially-spaced locations, and at least at upper and lower locations, to guide the buoyancy apparatus  106  within the center well  104 . 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 reduce, the impact loads, the guides  128  advantageously include compliant pads (such as elastomeric pads) (not shown) that are positioned to be compressed against the buoyancy apparatus  106 .  
     [0029] A unique feature of this invention is that a well deck  130  is positioned on top of the buoyancy apparatus  106 , and all the risers  126  extend from the well deck  130  to wellheads  132  on the seabed.  
     [0030] In this specific embodiment, at least one central tendon assembly  134 , comprising at least two concentric tubular tendon elements  136  (FIGS. 6A, 6B), secures the buoyancy apparatus  106  to the seabed. As shown in FIG. 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 buoyancy apparatus  126  to a tendon foundation in the seabed. The tendon foundation is of conventional design, described more fully below, comprising a caisson pile  138  anchored in the seabed, and a connective sleeve  140  connecting the tendon assembly  134  to the caisson pile  138 . The advantage of using a central tendon assembly  134  is that it can be designed (in terms of the physical characteristics of the tendons the tendon foundation) to withstand most of the tension load, thereby reducing the tension loads in the risers  126 . Thus, the requirement for reinforced foundations for the wellhead  132  will be further reduced, which is particularly advantageous in ultra deep water where the tension requirement can be quite critical.  
     [0031] As shown in FIGS. 6A and 6B, the tendon assembly  134  may be designed specifically as a tendon, or it may be designed as a riser that functions as a tendon with a reinforced wellhead foundation. In this embodiment, the tendon assembly  134  and a plurality of surrounding risers  126  are coupled together with a plurality of vertically-spaced riser spacers or guides  144 , only one of which is shown in the drawings. The coupling 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 will significantly reduce the cost of the riser assembly  134  as well as the cost of the floating platform  100 . Furthermore, the tension factor required for the risers  126  will be smaller, because the risk of colliding is reduced, thus reducing the size of the buoyancy apparatus  126 . The coupling of the risers  126  with the tendon assembly  134 , as well as the design of the tendon assembly  134  and the riser  126 , will be explained in further detail below.  
     [0032] As shown in FIG. 1, the upper portions of the risers  126  are uncoupled from the tendon assembly  134  within the upper portion of the center well  104 , to allow the connection of each riser  126  to a respective surface tree  170 , and the connection of tendon assembly  134  to a tendon socket or slot  146  (FIG. 5) in the well deck  130 . Similarly, the bottom portions of the risers  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 tendon foundation.  
     [0033]FIG. 2 shows another exemplary embodiment of the invention used in a spar type floating platform  200 , which includes risers  226  that are uncoupled from a tendon assembly  234 . This embodiment provides a simplified riser and tendon construction (no need of riser spacers or guides), but the risers  226  and the tendon assembly  234  will have to be sufficiently spaced and will have to be tensioned sufficiently to avoid any collision between the risers  226  themselves and between the risers  226  and the tendon assembly  234 . Accordingly, this embodiment requires a center well  204  that must be larger than that of the embodiment of FIG. 1.  
     [0034]FIG. 3 shows another exemplary embodiment of the invention used in a spar type floating platform  300 . In this particular embodiment, there is no specific tendon used for vertically restraining the single buoyancy apparatus  306 . Instead, this embodiment employs risers  326  and wellhead foundations  346  that are designed to vertically restrain the center well buoyancy apparatus  306 .  
     [0035]FIG. 4 shows another exemplary embodiment of the invention used in a spar type floating platform  400 . This particular embodiment employs a center well buoyancy apparatus  406  that, in addition to a well deck  430 , supports a drilling deck  420  with a drilling rig  422  and its associated equipment (drilling and work over), while the work platform supported by the floating structure comprises a production deck  416  with compartments  418  for crew quarters and utilities. The decks  416 ,  420  are conventional decks used on floating structures such as spars, TLPs or deep draft semi-submersible platforms. As the buoyancy apparatus  406  is vertically restrained, the drilling and work over operations will be less weather dependant.  
     [0036] In some embodiments, because there will be no relative vertical motion between the drilling riser and the drilling rig, there will be no requirement for a slip joint arranged on the drilling riser to absorb these vertical motions. The embodiment of FIG. 4 employs risers  426  and tendons  442  that are coupled; however, the risers and the tendons can be uncoupled as shown in FIG. 2, or the buoyancy apparatus can be vertically restrained by the riser itself, as shown in FIG. 3. The embodiment of FIG. 4 does, however, require additional buoyancy to support the extra weight of the drilling/work over equipment.  
     [0037] As illustrated in FIGS.  1 - 4 , the tendons and/or the risers are secured to the seabed at one end (wellhead or tendon foundation), and to the well deck on the center well buoyancy apparatus at the other end.  
     [0038]FIG. 5 shows a horizontal cross sectional view of an example of a well deck assembly  500 . The well deck assembly includes a well deck  130  having a tendon socket or slot  146  in its center to receive a tendon assembly  134 . Around the tendon slot  146  are several riser sockets or slots  548 . There is a space that serves as a tendon riser center well  550  around the tendon socket  146  to provide space for running equipment down to the seabed (for example landing bases, blow-out 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 seabed. As shown in FIG. 5, the center well buoyancy apparatus  106  is guided with a plurality of guides  128  (four guides, in this example), arranged around its perimeter. The number of guides  128  may be varied from as few as two to five or more, depending on the loads they are to absorb.  
     [0039] In FIGS.  1  to  5 , only one tendon assembly  134  attached to the well deck  130  and extending down the centerline of the buoyancy apparatus  106  is shown. However, in other embodiments, there may be more than one tendon assembly aligned and/or parallel with the vertical centerline of the buoyancy apparatus. The various other embodiments may employ multiple tendon assemblies (not illustrated), closely arranged around the central tendon assembly.  
     [0040] As further shown in FIGS.  1 - 4 , the tendon assembly  134  is secured to the seabed by a caisson pile  138 , which is alternatively called an anchor caisson or a suction pile. The caisson pile  138  secures the tendon assembly  134  to the seabed. As shown in FIG. 1, the tendon assembly  134  may optionally be connected to the caisson pile by the tendon connection sleeve  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  134  to the interior wall of the connection sleeve  140 .  
     [0041] To install the caisson pile  138 , in one embodiment, the caisson pile  138  is pushed into the seabed by pumping water out of its interior. As water is pumped out, the ambient external water pressure pushes the caisson pile  138  down into the seabed. In other embodiments, the caisson pile  138  is pushed into the seabed by means of submersible pumps (not shown), airlifts (not shown), 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.  
     [0042] In still another embodiment, at least one of the tubular tendon elements  136  of the tendon assembly  134  is drilled into the seabed and anchored therein by cement. This increases the pullout resistance of the tendon assembly  134 . The tendon connection sleeve  140  is extended out of the bottom of the caisson pile  138 , thereby providing a connector through which the tendon elements  136  are drilled and connected.  
     [0043] It will be appreciated that the tendon assembly  134  may be secured to the seabed by any other method that may suggest itself to those of ordinary skill in the art.  
     [0044]FIGS. 6A and 6B show the structural details of one exemplary embodiment of a tendon assembly  134 . The tendon assembly  134  comprises multiple (at least two) concentric tubular tendon elements  136 . The concentric tubular elements  136  are secured to the well deck  130  on the vertical centerline of the center well buoyancy apparatus  106 , and they extend down to an anchor assembly at the seabed, as discussed above. The use of concentric tubular tendon elements  136  provides great flexibility in the design of the tendons to achieve the required dynamic behavior.  
     [0045] Three factors are important in the design of the tendon assemblies  134 : (1) The tendon assemblies  134  must be strong enough to withstand the maximum static and dynamic loads imparted on them by the buoyancy apparatus  106 . (2) The buoyancy apparatus  106  must impart sufficient upward tension at the top of the tendon assemblies  134  to prevent them from going slack at the bottom. (3) The tendon assemblies  134  must have sufficient axial stiffness to keep the riser/tendon assembly system from going into resonance due to cyclic wave forces. By varying the number of concentric tubular tendon elements  136 , both the strength and spring characteristics are varied to meet specific design requirements on a case-by-case basis, as will occur to those of ordinary skill in the art.  
     [0046] There are other benefits stemming from the above-described concentric tendon design. For example, corrosion and fatigue are minimized by the use of corrosion inhibitors in the annular spaces defined between the concentric tubular elements  136 . Furthermore, the use of multiple tubular tendon elements  136  provides redundancy compared to prior art tendons, should one of the tubular elements  136  fail. Another benefit is that the annular spaces can be pressurized to detect cracks and to check joint integrity.  
     [0047] As best shown in FIG. 6A, the tubular tendon elements  136  may further comprise conventional oilfield casing joints with a flanged coupling  156 . In various embodiments, the casing joints are of various sizes, depending on the required tensile loads. These loads vary on a case-by-case basis, as will occur to those of ordinary skill in the art.  
     [0048] In one embodiment, the tendon assembly  134  is installed in sections, in a section-by-section sequence, using the drilling rig  122  on the platform. Each section is installed on the deck and lowered using the rig, and the sections are connected using the flanged couplings  156 . The advantages of installing the tendon assembly  134  in sections in this manner using the platform&#39;s own drilling rig will be readily apparent to those skilled in the art.  
     [0049]FIG. 6B shows a cross section of the tendon assembly  134  of FIG. 6A, showing one of the riser guides or spacers  144 , which is also shown in FIG. 6A. Each of the riser guides  144  couples each tendon assembly  134  to the adjacent risers  126 . The riser guides  144  separate the risers  126  from one another and from the central tendon assembly  134 , thereby preventing the risers  126  and the tendon assembly  134  from clashing or colliding with each other. Each of the riser guides  144  comprises a central tendon conduit  158 , through which the tendon assembly  134  passes, and a plurality of riser conduits  160  through which the risers  126  pass. The riser guides  144  are secured to the tendon assembly  134 , and they may or may not be secured to the risers  126 . As mentioned above, in the preferred embodiments of the invention, there are several vertically-spaced riser guides or spacers  144 , separated by a vertical distance of about 15 ft. (4.5 m) to about 70 ft. (21 m), depending on the design parameters of the particular platform.  
     [0050] The tendon conduit  158  and the riser conduits  160  are rigidly connected and separated by a web of separation members  162 . By rigidly separating the riser conduits  160  and the central tendon conduit  158 , the risers  126  passing through the riser conduits  160  are separated from the central 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 due to waves, currents, and floating platform motion, which can occur even when it is subjected to light ocean currents. In other embodiments (e.g., that of FIG. 2), the risers are not coupled to the tendon assembly by means such as the riser guides  144 .  
     [0051] In the various embodiments of the present invention, a wide range of riser types may be used to connect the wellhead to the platform. The various types of risers include those used for drilling, production, and workover, as will occur to those skilled in the pertinent arts. For example, in alternative embodiments, the risers are drilling risers used with full sub-sea blow-out preventor (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 further embodiments may employ production risers and workover risers used with surface trees, sub-sea trees, split trees, wet trees, dry trees, or any other type of tree that may suggest itself to those skilled in the pertinent arts. In still another embodiment, the platform is designed for vertical entry into the well. Alternatively, the platform may be designed for any other directional entry into the well.  
     [0052] The spring characteristics of the risers and/or tendons, when acting together, have to be such that the riser system does not respond significantly to the waves, taking into account the mass of the system and the draft of the floating platform. A plurality of risers and/or tendons will act together with a spring characteristic and a strength characteristic for the group of risers and/or tendons. Said differently, the risers and /or tendons act as a system, and their structural and spring properties achieve a uniform behavior for the group of riser and/or tendons.  
     [0053] One of the key aspects of this invention is the interaction between the risers or of the risers with the tendons when subjected to the movement of the floating support. As an example, when the floating platform is subjected to environmental forces, the distance between the wellhead on the seabed and the riser slot at the keel increases for the upstream riser and decreases for the downstream riser. Should a tendon be used, these distances will be also different. This means that the spring characteristics, in consideration of the hydrodynamic and gravitational forces, have to be selected so that the riser system will act in unison, and the separation between the risers will be maintained to avoid clashing and collisions: as the floating platform moves.  
     [0054] Reference is again made to FIGS.  1 - 4 . As the riser system is protected by the center well of the spar platform, the riser system will be excited only at the keel of the spar (for example, at about 500 ft or about 150 m of water depth). Because the influence of waves and currents is minimized at this water depth and the area of excitation is small, the natural period of the riser assembly when the tendons and/or risers are connected does not need to be as short as the 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 considerably less steel than a comparable tendon for conventional TLP.  
     [0055] FIGS.  1 - 4  illustrate the use of the present 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 platforms.  
     [0056]FIG. 8 shows the use of the present invention in a deep draft semi-submersible platform  600 . As shown, a vertically restrained buoy  606 , which supports a plurality of top-tensioned risers (TTRs)  608 , is guided within the hull of the deep draft semi-submersible platform  600  by a 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 specific 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 FIG. 4 for a spar-type platform. In this example, the buoy  606  is vertically restrained by the TTRs  608  only (as shown in FIG. 3 for a spar-type platform). Alternatively, however a tendon assembly coupled or uncoupled with the riser can be used to vertically restrain the buoy  606 . As opposed to a spar type platform, this vertically restrained buoy  606  will not be protected by a center well in the splash zone, and will be subjected to wave and current action which can lead to VIV problems. Since the diameter of the vertically restrained buoy  606  is large compared to a riser  608 , 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 .  
     [0057] Turning now to another feature of this invention, the vertically restrained buoy is guided 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. While the floating platform is pitching, the contact loads between the buoy and the guide assemblies provide to the floating platform a restoring moment. This restoring moment allows an improvement (reducing the pitch angle) in the pitch motion of the floating structure. Indeed, this resulting moment is proportional to the weight of the risers supported by the buoy (which can be quite important, especially in deeper water).  
     [0058]FIG. 7 shows another embodiment of the vertically restrained buoy. In all the embodiments already described, the vertically restrained buoy comprises a single, large buoyancy can. To achieve a high degree of compartmentalization, the buoy must be divided into compartments by a plurality of internal lateral bulkheads, thereby increasing the cost of manufacturing 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 heavy welding procedure. In the embodiment shown in FIG. 7, a vertically restrained buoyancy 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 bulkheads and thus at a reduced cost. Furthermore, the risers  126  can be arranged around the vertical tubes  702  (i.e. in the interstices defined in between the vertical tubes) and will not have to cross through any buoyancy compartment, thereby avoiding the problem of sealing the intersections of the risers with the bulkheads.  
     [0059] In all the described embodiments, the well deck is supported directly by the vertically restrained buoy, the surface trees are attached on the well deck, and there are no relative motions between the surface trees and the well deck. To carry the crude oil to the production deck and the process equipment to separate oil, water and gas, high pressure flexible jumpers can be used to connect each sub-sea tree to the production deck manifold. However, a unique feature of the present invention, shown in FIG. 9, is that contrary to the prior art (where the well deck is supported by the offshore platform), the single buoyancy apparatus  106  includes the well deck  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 of the risers  126  can be rigidly attached to the top of the buoyancy apparatus  106 .  
     [0060] Consequently, all the surface trees  170  can be connected to a manifold  172  situated on the well deck  130  (rather than the production deck) with rigid piping  174 . The crude oil will be choked down by a pressure-reduction choke  176  in the inlet of the manifold  172 , and, contrary to the prior art, as few as one low pressure flexible jumper  178  (or, alternatively an articulated rigid arm, not shown) can be used to carry the crude oil to the processing equipment on the production deck  116 . The use of just one flexible jumper  178 , or perhaps a few flexible jumpers (or articulated rigid arms) will considerably reduce the cost of the riser system as well as the required deck room.