Abstract:
A top-tensioned riser system comprises a substantially vertical riser extending upward from the seafloor; a conductor surrounding an upper portion of the riser in spaced-apart relation; a coaxial keel guide surrounding a lower portion of the conductor; a tensioner attached to the conductor and the riser; a keel guide support structure attached to the keel guide and connected to the keel of a dry-tree, semi-submersible vessel; and, a keel joint centralizer attached to the riser proximate the keel guide and sized to prevent radial movement of the riser relative to the conductor. Side loads on the riser (such as those arising from displacement of the vessel from its nominal position or currents acting on the riser) are reacted from the riser to the conductor via the keel joint centralizer and then to the keel of the vessel via the keel guide.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application claims the benefit of U.S. Provisional Application No. 61/812,106, filed on Apr. 15, 2013. 
    
    
     STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
     Not Applicable 
     BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     The present invention generally relates to the offshore production of oil and gas. More particularly, it concerns dry-tree, vertical risers supported by semisubmersible vessels. 
     2. Description of the Related Art including information disclosed under 37 CFR 1.97 and 1.98 
     A semi-submersible is floating unit with its deck(s) supported by columns to enable the unit to become almost transparent for waves and provide favorable motion behavior. The unit stays on location using dynamic positioning and/or is moored by means of catenary mooring lines terminating in piles or anchors in the seafloor. A DeepDraftSemi® platform is a semi-submersible unit fitted with oil and gas production facilities in ultra deep water conditions. The unit is designed to optimize vessel motions to accommodate steel catenary risers (SCRs)—steel pipes hung in a catenary configuration from a floating vessel in deep water to transmit flow to or from the sea floor. 
     The “christmas tree” (or “tree”) is an assembly of valves at the top of the tubing of a completed well that are used to control the flow of oil and/or gas and to enable certain manipulations. If the christmas tree is at the level of the seabed, the well is described as “subsea completed” or “wet tree.” If the tree is on the deck of a platform, the well is described as “surface completed” or “dry tree.” 
     A dry tree semi (DTS) is a floating facility carrying surface-completed wells, i.e. the christmas trees are located above the surface of the sea, on the semi-submersible, as opposed to the seabed. 
     The rigid pipes (tubing, casing, etc.) that link the trees to the wells require high tension to avoid buckling. The DTS is therefore under constant tension to compensate for the heave motion of the vessel. 
     Generally, a DTS also carries basic drilling equipment to allow down-hole intervention on a tender assist mode. It may also feature full drilling capability. 
     A well bay is an area of an offshore platform where the christmas trees and wellheads are located. It normally consists of two levels, a lower level where the wellheads are accessed and an upper level where the trees are accessed often along with the various well-control panels, which typically have pressure gauges and controls for the hydraulically actuated valves, including downhole safety valve and annular safety valve. On a platform with a drilling package, the well bay will be located directly below it to facilitate access for drilling and well interventions. 
     Spar type platforms have incorporated a conductor and a keel joint centralizer when using air cans for riser tensioning. These conductors are large and part of the air can assembly. Installation or removal requires a heavy-lift vessel for handling. These systems generally have steel-on-steel contact for the keel guide, and therefore impart large axial tension variations to the risers. Alternatively, hydro-pneumatic tensioners have been used to tension the risers. Each known example of these systems has had four cylinders per riser. 
     Tension configuration (hanging cylinders) have been used on six-cylinder configurations on certain tension leg platforms and on deepwater drilling vessels using the N-Line™ direct acting riser tensioning system (National Oilwell Varco, Houston, Tex. 77036). 
     U.S. Pat. No. 6,648,074 to Finn et al. describes a gimbaled table riser support system for a spar type floating platform having risers passing vertically through the center well of a spar hull. The gimbaled table is supported above the top of the spar hull. The table is supported by a plurality of non-linear springs attached to the top of the spar hull. The non-linear springs compliantly constrain the table rotationally so that the table is allowed a limited degree of rotational movement with respect to the spar hull in response to wind- and current-induced environmental loads. Larger capacity non-linear springs are located near the center of the table for supporting the majority of the riser tension, and smaller capacity non-linear springs are located near the perimeter of the table for controlling the rotational stiffness of the table. The riser support table comprises a grid of interconnected beams having openings through which the risers pass. The non-linear springs may take the form of elastomeric load pads or hydraulic cylinders. The upper ends of the risers are supported from the table by riser tensioning hydraulic cylinders that may be individually actuated to adjust the tension in and length of the risers. Elastomeric flex units or ball-in-socket devices are disposed between the riser tensioning hydraulic cylinders and the table to permit rotational movement between the each riser and the table. 
     U.S. Pat. No. 7,013,824 to Otten et al. discloses a riser centralizer for transferring lateral loads from the riser to a platform hull which includes a keel centralizer mounted on a keel joint. The keel centralizer is received within a keel guide sleeve secured in a support mounted at the lower end of the platform hull. The keel centralizer includes a nonmetallic composite bearing ring having a radiused peripheral profile for minimizing contact stresses between the keel centralizer and the keel guide sleeve in extremes of riser and platform motion. The internal surface of the keel guide sleeve is clad with a corrosion resistant alloy and coated with a wear resistant ceramic rich coating. 
     U.S. Pat. No. 7,632,044 to Pallini et al. describes a ram style tensioner with a fixed conductor and a floating frame. The riser tensioner for an offshore floating platform has a frame mounted to the upper portion of the riser. Pistons and cylinders are spaced circumferentially around the riser and connected between the frame and the floating platform. A tubular guide member is mounted to the floating platform for movement in unison in response to waves and currents. The riser extends through the guide member. A guide roller support is mounted to and extends downward from the frame around the guide member. A set of guide rollers is mounted to the guide roller support in rolling engagement with the guide member as the guide member moves in unison with the platform. 
     U.S. Pat. No. 8,123,438 to Pallini et al. describes a ram style tensioner that includes a frame configured to be fixedly attached to the riser; plural cylinder assemblies spaced around the riser, each cylinder assembly having a cylinder and a piston configured to slidably move inside the cylinder, the piston being configured to connect to the frame; a guide roller support stationarily mounted to and extending from the frame; at least one bearing fixedly attached to the guide roller support; and a guide member configured to be in rolling engagement with the at least one bearing as the cylinder moves relative to the frame. 
     U.S. Pat. No. 7,588,393 to Shivers et al. describes a method for supporting top-tensioned drilling and production risers on a floating vessel using a tensioner assembly above the waterline of the vessel. The method may include attaching at least one hydraulic cylinder on a first end to a first position on a floating vessel and on a second end to a tension frame below the first position. The next step of the method may be forming a fluid connection between the at least one hydraulic cylinder and at least one primary accumulator. 
     U.S. Pat. No. 7,886,828 to Shivers et al. describes a floating vessel for supporting top tensioned drilling and production risers having a hull and an operation deck disposed on top of the hull. The tensioner assembly moveably carries a conductor that communicates from a wellhead to a piece of well access equipment. The well access equipment is connected to the floating vessel. The tensioner assembly is supported by the floating vessel. 
     For a Dry Tree Semi (DTS) platform, a tensioning system is needed that can provide large strokes (on the order of 30 to 45 feet) and also provide sufficient support and alignment to the risers. Connecting jumpers of production riser christmas trees and drilling riser blowout preventers (BOP&#39;s) must be free to move as required by the platform motions without impacting deck or tensioning system components while preventing riser clashing. In addition, the semi-submersible configuration lends itself to a two-main-deck configuration and, due to the tensioner stroke required and the need for access to the christmas trees, tension joints, and BOP&#39;s, the tensioning system preferably has a ram or push-up type configuration. By using a push-up tensioner, the tensioner cylinder barrel may be located lower on the deck and enable access to critical areas of the system such as the tension ring and surface trees. In addition, the push-up type arrangement allows for a more compact well bay. 
     However, a ram type or push-up configuration is susceptible to buckling failure and high lateral loads. What is needed is a method that provides stability to the riser and tensioner while not adversely affecting the low tensioner spring rate that may be required by the DTS design parameters. A keel guide system for the riser is needed to react lateral riser loads directly to the hull structure rather than supporting high riser lateral loads at the tensioner and deck interface. Reacting riser lateral loads at the pontoon level of a semi-submersible may also improve the overall stability of the platform. 
     BRIEF SUMMARY OF THE INVENTION 
     A riser system according to the invention provides a conductor of sufficient size to support the required lateral loads at the keel and allow the running of drilling and production tieback connectors through the inside. The conductor is mechanically attached to the upper tensioner frame and moves with the tensioner in response to platform motions. The conductor interfaces with a keel guide and the tensioner rollers on the outside of the conductor. On the inside of the conductor, the production or drilling risers may be equipped with one or more centralizers to transmit lateral forces from the risers to the conductor. A conductor head on the top conductor section provides a profile for a spaceout adapter that supports the production riser and allows space out of the riser and tensioner. 
    
    
     
       BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWING(S) 
         FIG. 1  is a schematic side view through the well bay of a dry-tree semi-submersible equipped with a vertical riser tensioning system according to one embodiment of the invention. 
         FIG. 2  is a plan view of the dry-tree semi-submersible illustrated in  FIG. 1 . 
         FIG. 3  is a side view, partially in cross-section, of a vertical riser tensioning system according to the invention. 
         FIG. 3A  is a longitudinal, cross-sectional enlargement of the conductor connector indicated in  FIG. 3 . 
         FIG. 4  is a detail side view, partially in cross-section, of the upper tensioner frame and conductor head of the vertical riser tensioning system illustrated in  FIG. 3 . 
         FIG. 4A  is a cross-sectional view of the upper tensioner frame and conductor head of a first alternative embodiment of the vertical riser tensioning system illustrated in  FIG. 3 . 
         FIG. 4B  is a cross-sectional view of the upper tensioner frame and conductor head of a second alternative embodiment of the vertical riser tensioning system illustrated in  FIG. 3 . 
         FIG. 5  is a cross-sectional view of the riser keel joint and keel joint centralizer of the vertical riser tensioning system illustrated in  FIG. 3 . 
         FIG. 6  is a side view, partially in cross-section, of the keel guide hull interface of the vertical riser tensioning system illustrated in  FIG. 3 . 
         FIG. 7  is a side cross-sectional view of the keel guide hull interface of the vertical riser tensioning system illustrated in  FIG. 3  shown in relation to a pontoon of the supporting dry-tree semi-submersible. 
         FIG. 8  is a side cross-sectional view of a cellar deck, its supporting structure on a dry-tree semi, and riser tensioners supported from the lower deck. 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     The invention may best be understood by reference to the exemplary embodiments illustrated in the drawing figures wherein the following reference numbers are used:
       10  dry-tree semi-submersible offshore vessel (“DTS”)     12  columns     14  pontoons     15  top surface of pontoon     16  upper deck level     17  well bay     18  lower deck level     19  bottom surface of pontoon     20  tensioners     22  christmas trees     23  tree work platform     24  vertical risers     24 A drilling riser     24 B production riser     26  conductor     28  keel guide     30  keel guide support structure     32  mooring line fairleads     34  drilling rig     36  SCR porches     38  tensioner cylinder rod; tensioner ram     40  high-pressure bottle     42  upper tensioner guide rollers     44  lower tensioner guide rollers     46  conductor connectors     48  riser centralizer     50  riser tension joint     52  conductor flare     54  drilling riser connector     55  riser connector     56  adjustable centralizing dog     58  attachment block     60  anti-friction bearing     62  riser keel joint     64  radial plates     66  anti-friction bearing     68  elastomeric bearing     70  centralizer mount     72  elastomer bearing     74  spaceout adapter     78  conductor head     80  upper tensioner frame     82  conductor annulus sealing plate     84  annulus     86  tension ring     88  flange     90  outer land     92  inner land     94  radial wings     96  keel joint centralizer     98  tensioner upper frame and spaceout adapter     100  concave spherical section of tensioner ring     102  convex spherical section of spaceout adapter     104  spherical section elastomer bearing     106  connector box     108  connector pin     110  locking engagement profile     112  tool engagement profile     114  connector inner wall     116  conductor inner wall     118  lower end of conductor     120  lower end of keel guide     122  drilling rig substructure     124  blowout preventer (“BOP”)     126  cellar deck     128  cellar deck vertical support member     130  cellar deck frame member   

     Referring now to  FIG. 1 , representative semi-submersible vessel  10  has a conventional configuration comprising surface-piercing columns  12  and subsurface pontoons  14  connecting adjacent columns. One or more decks  16  are supported above the water surface on columns  12 . 
     Semi-submersible  10  is equipped with mooring line fairleads  32  for a catenary mooring system. Mooring lines (not shown) extend from anchors in the seafloor through fairleads  32  and up the outer face of columns  12  to mooring line winches mounted on upper deck level  16  (or the upper ends of columns  12 ). 
     A plurality of dry trees  22  are located in well bay  17  on the upper ends of vertical risers  24 . In the illustrated embodiment, the center riser in the group of five risers is a drilling riser and has a blowout preventer on its upper end. This riser is directly below the derrick of drilling rig  34 . In other embodiments, equipment  34  may comprise production equipment, be a workover rig or any other equipment related to offshore drilling and/or production. Tree work platform  23  may be provided in certain embodiments (see  FIG. 4 ). 
     Vertical risers  24  are attached to ram-type (or “push up”) tensioners  20  which are supported on lower deck level  18 . For purposes of illustration only, the outer pair of tensioners in  FIG. 1  are shown “bottomed out”—i.e. fully stroked down; the center tensioner is shown fully stroked up; and, the middle pair of tensioners is shown in their nominal positions. It will be understood by those skilled in the art that, under normal operating conditions, the rams of tensioners  20  will all be extended approximately the same distance in response to a given platform heave (as shown in  FIG. 8 ). 
     Conductors  26  surround each riser  24  proximate the upper end thereof. Conductors  26  extend through keel guides  28  which are mounted on keel guide support structure  30 . As may be best seen in the plan view of  FIG. 2 , keel guide support structure  30  in the illustrated example extends between one or more opposing pairs of pontoons  14 . Also shown in  FIG. 2  are porches  36  on the outboard surfaces of pontoons  14  for supporting the upper end of steel catenary risers (SCR&#39;s) which may be used to connect equipment on semi-submersible  10  to flow lines, pipelines or wellheads on the seafloor. 
       FIG. 3  shows the upper end of an isolated, vertical riser  24  within a conductor  26  according to an embodiment of the invention. Riser  24  extends substantially vertically from a wellhead on the seafloor. An upper portion of riser  24  is surrounded by conductor  26  which may comprise a plurality of segments joined together by mechanical connectors  46 . This permits conductor  26  to be assembled and installed offshore without the assistance of a heavy-lift crane vessel. In other embodiments, conductor  26  is a single piece of pipe. In yet other embodiments, conductor  26  may comprise welded or threaded connectors between segments. In certain preferred embodiments, conductor  26  has a smooth, contiguous, substantially cylindrical outer surface at least in the vicinity of tensioner rollers  42  and  44  and keel guide  28 . 
     One particular preferred mechanical connector  46  is illustrated in  FIG. 3A . Connector  46  comprises pin section  108  attached to an upper end of conductor  26  and box section  106  attached to the lower end of an adjoining section of conductor  26 . An assembly tool (not shown) which may be a hydraulically-actuated tool, may engage box section  106  at profile  112  and pin section  108  at profile  112 ′. The assembly tool may urge sections  106  and  108  axially together until they lock together at locking profile  110 . Connector  46  may have an inside diameter  114  that is substantially the same as inner diameter  116  of conductor  26  so as to provide a substantially smooth inner bore. This may facilitate the running of riser  24  (together with its associated tieback connectors and centralizers) in and out of conductor  26 . 
     One or more riser centralizers  48  may be attached to riser  24  to position riser  24  centrally within conductor  26 . Proximate the lower end of conductor  26 , keel joint centralizer  96  may act as a load bearing or “load reactor” to transfer side loads on riser  24  to conductor  26  and thence through keel guide  28  to keel guide support structure  30  thereby reducing side loads imposed on tensioner  20 . One particular, suitable keel joint centralizer design is that described in U.S. Pat. No. 7,013,824 to Otten et al., the disclosure of which is hereby incorporated by reference in its entirety. Side loads are imposed on vertical riser  24  whenever semi-submersible  10  drifts from its nominal position due to winds and/or currents. Even when semi-submersible  10  is located at its nominal position directly above the seafloor wellheads, subsurface currents can displace risers  24  from a straight line, vertical orientation. 
     At the upper end of riser  24 , a space out adapter  98  connects riser  24  and conductor  26  and provides a bearing surface for rods  38  of tensioner  20 . Conductor  26  is positioned within tensioner  20  by upper tensioner rollers  42  and lower tensioner rollers  44 . In other embodiments, a single set of rollers may be employed at  42  and lower tensioner rollers  44  may be omitted. 
     Tensioner cylinder rods  38  are urged upward, out of their associated cylinders under the influence of fluid pressure within high-pressure bottles  40  which may have a gas-over-liquid configuration or have pressurized gas applied directly to the piston or rod of the cylinders. 
     As shown in the detailed view of  FIG. 4 , the upper ends of tensioner rods  38  may bear on the undersurface of upper tensioner frame  80  which may be connected to tension ring  86  via elastomer bearing  72 . Reinforcing plates or “radial wings”  94  may connect tension ring  86  to spaceout adapter  74 . Spaceout adapter  74  may connect to riser tension joint  50  by engaging threads or grooves on at least a portion of the outer surface of riser tension joint  50  (shown as dashed lines in  FIG. 4 ). In this way, the vertical position of tensioner  20  relative to riser  24  may be adjusted. 
     Conductor head  78  may be provided with profiled flange  88  which may be engaged between outer land  90  and inner land  92 . Upward force applied by tensioner rods  38  is transmitted through upper tensioner frame  80  to elastomer bearing  72  and thence through radial wings  94  to outer land  90  resulting in a tensile force being applied to conductor  26  via flange  88 . 
     Also shown in  FIG. 4  is optional conductor sealing plate  82  which may provide a gas-tight seal between the inner surface of conductor  26  and the outer surface of riser  24 . This permits annulus  84  to be pressurized with air (or other gas) thereby making conductor  26  positively buoyant (or at least have a lower effective weight). Such buoyancy may act to supplement the tension applied by tensioner  20  which may be particularly advantageous when a cylinder or ram  38  must be removed for maintenance or repair. Examples of means for pressurizing annulus  84  include valves through sealing plate  82 , valves through the side wall of conductor  26  and piping entering the open, lower end of conductor  26 . 
       FIG. 4A  shows an alternative embodiment wherein top tension ring  80  is equipped with a plurality of attachment blocks  58  on the underside thereof. Attachment blocks  58  may have an internally-threaded, radial through hole with an adjustable centralizer dog  56  in threaded engagement. The outer ends of adjustable centralizer dogs  56  may be provided with wrench flats, hex sockets or other tool-engagement means for adjusting the radial extent thereof. 
     In one particular, preferred embodiment three adjustable centralizer dogs are provided, each 120° from an adjacent centralizer. Centralizer dogs  58  may be adjusted radially in or out to aid in positioning upper tensioner ring  80  relative to conductor  26 . In so doing, the inner ends of centralizer dogs  58  will contact the outer surface of conductor  26  (as shown on the right half of  FIG. 4A ). Following installation of upper tensioner ring  80 , dogs  56  may be retracted by positioning them radially outward (as shown in the left half of  FIG. 4A ). 
     Yet another embodiment is illustrated in  FIG. 4B . In this embodiment, upper tensioner frame  80 ′ has concave spherical section  100  and tension ring  86 ′ has opposing, convex spherical surface  102 . Spherical section elastomer bearing  104  is positioned between surfaces  100  and  102 . This configuration may lessen shear loads applied to bearing  104  when side loads are applied to conductor  26  and/or riser  24 . Bearing  104  may be a composite bearing comprised of alternating layers of metal and elastomer. 
       FIG. 5  is a detailed view of the lower portion of a conductor  26  according to the invention. Conductor  26  may have flare  52  at its lower end to facilitate the installation of riser  24  and its associated centralizers such as keel joint centralizer  96 . Centralizer  96  may differ in design from centralizer  48  (see  FIG. 3 ) inasmuch as centralizer  48  may be subjected to lesser lateral loads than keel joint centralizer  96 . Riser  24  may include riser keel joint  62  which may have a thicker wall section for added strength and/or a profiled section for securing keel joint centralizer  96  in place. 
     Keel joint centralizer  96  may comprise centralizer mount  70  which may have a profiled inner surface that engages a corresponding profiled surface on riser  24 . Radial spacer plates  64  may be arrayed around mount  70  and support anti-friction bearing  66  on annular elastomeric ring  68 . In certain preferred embodiments, anti-friction bearing  66  is fabricated from a polymer selected from the group consisting of nylon, Delrin, polytetrafluoroethylene (PTFE) and polyetheretherketone (PEEK). Other anti-friction materials (which may be composites or metals) suitable for the subsea environment may also be used. 
     Keel joint centralizer  96  reacts side loads on riser  24  to conductor  26  which is restrained at the keel of semi-submersible vessel  10  by keel guide  28 . 
       FIG. 6  shows drilling riser  24 A on the left and production riser  24 B on the right passing through keel guides  28 . Keel guides  28  may have an upper funnel portion for guiding conductor  26  during installation and a lower funnel portion for accommodating bending of conductor  26  in a sideways direction. A portion of keel guide support structure  30  is shown relative to pontoon upper surface  15 . Drilling riser  24 A includes drilling riser segment connector  54 . Production riser  24 B includes riser segment connector  55  of differing style. 
     The central, cylindrical portion of keel guides  28  may have anti-friction bearings  60  for contacting the outer surface of conductor  26  inasmuch as conductor  26  slides axially relative to keel guide  28  as rams  38  of tensioner  20  (not shown in  FIG. 6 ) extend and retract. Anti-friction bearings  60  may be made of any suitable material. Examples of suitable materials include, but are not limited to, nylon, Delrin, polytetrafluoroethylene (PTFE), polyetheretherketone (PEEK), and composites. Anti-friction bearings  60  may be radially segmented for removal and replacement by divers or ROVs. 
     It will be appreciated by those skilled in the art that the load path for side loads imposed on riser  24 A (or  24 B) is through keel joint centralizer  96  to conductor  26  and thence through anti-friction bearing  60  to keel guide  28 , keel guide support structure  30  and thence to pontoons  14 —i.e., the hull of semi-submersible  10 . In this way, side loads on risers  24  are substantially reacted to the vessel&#39;s hull rather than to the riser tensioners  20 . This may simplify the design of tensioners  20  and reduce the wear and stresses imposed thereon. Rather than requiring a gimbaled riser tensioner, one may employ a push-up tensioner having only an elastomer bearing  72  (or  104 ) for accommodating minor misalignments and to reduce bending moments. 
       FIG. 7  shows keel guide support structure  30  relative to a pontoon  14  having top surface  15  and bottom surface  19 . As illustrated in  FIG. 7 , keel joint centralizers  96  may be located within conductors  26  below lower end  120  of keel guides  28 . This may act to take advantage of the flexibility of that portion of conductor  26  which extends below keel guide  28  to further absorb side loads imposed on riser  24 —i.e., conductor  26  may bend or flex at keel guide  28  in response to side loading via keel joint centralizer  96 . 
     It should also be noted in  FIG. 7  that the lower ends  118  of conductors  26  may be located above the elevation of pontoon bottom surface  19  when their associated tensioners are in their nominal positions. This feature permits conductors  26  to be installed quayside even if the dry-tree semi is ballasted such that pontoon bottom surfaces  19  are resting on the seafloor of the harbor. 
     In one particular preferred embodiment, mechanical connectors are used to assemble the length of conductor required by the specific platform draft and deck heights. These connectors allow the conductor to be installed or removed offshore using conventional drilling rig operations. This is a significant improvement over the conductors used on spar type platforms that require a heavy-lift vessel crane to be installed or removed. Using the configuration disclosed herein, the conductor may be installed quayside or may be installed offshore. 
     In one preferred configuration the conductor may be assembled from four sections. The connectors used may be similar to TLP tendon connectors, being fully reversible in connection and disconnection without rotation. The connectors may utilize hydraulic pressure to collapse the pin and expand the box, in conjunction with a hydraulic clamp tool to make up the connections. In one particular preferred embodiment, the conductor connectors have an inside diameter substantially equal to the inside diameter of the conductor pipe to ease the running of the riser and riser centralizers inside the conductor. The pipe sections for the conductor may be similar to tendon pipe, utilizing high quality rolled and welded pipe of high strength. 
     In order to improve the life and minimize the impact on the tensioning system stiffness from friction, the conductor may be supported by rollers  42  and  44  at the tensioner structure and a keel guide  28  at the pontoon level. The keel guide structure may utilize a low friction composite material to react riser load to the hull. The composite material  60  may be in segments, permitting individual segment removal and replacement without removal of the conductor  26 . 
     Due to the long tensioner strokes required for a DTS, the variability of wave, wind, and currant forces, and the need to minimize overall height of the system, it is possible that the tensioning system may bottom out on rare occasions—i.e., the rams of the tensioner may reach the limit of their downward stroke. The forces generated during these conditions are large, as the riser quickly changes from the relatively soft spring rate of the tensioner to the stiffer spring rate of the steel pipe that forms the riser. To reduce the possibility of damage to the components and the deck or hull structures, an elastomeric pad  72  may be provided at the top of the conductor. This elastomer may provide a bumper function and minimize the impact force. In addition an elastomer ring  68  may be included in the keel joint so that any impact of the production riser at the keel is also minimized. 
     Previous concepts for DTS tensioning systems have utilized ram tensioning systems based on applications from spar-type vessels. Spars have deep hulls thereby inherently providing guiding means and support for the risers over a long length. For a DTS, the distance between the deck and the pontoons is substantially less. Typical tensioning system design parameters require sufficient remaining capacity in a “one cylinder removed” case. Inasmuch as the riser tensions for dual-string production risers are high, the load capacity lost in a four-cylinder configuration is high. With three remaining cylinders, the moment that must be supported equals one quarter of the nominal load times the radius. By using a six-cylinder configuration, the lost load is only one sixth of the total load. This results in a 33% reduction in the bending moment that must be supported, thereby enhancing system reliability. Moreover, the minimum tension required can be provided by five cylinders instead of three, effectively reducing the nominal tension factor from 4/3 (1.33) to 6/5 (1.2) which provides the possibility to reduce the nominal tension by 11%. With a lower tension factor, the unbalanced moment is also further reduced for a total of 40% less than that of a comparable four-cylinder system. 
     Referring now to  FIG. 8 , one particular preferred deck configuration comprises drilling rig substructure  122  above upper deck level  16  and cellar deck  126  below lower deck level  18  of DTS  10 . Tensioners  20  are supported on cellar deck  126 . Cellar deck vertical support members  128  are attached to the deck framework proximate lower deck level  18  at a first end and to cellar deck frame member  130  at a second end. Having tensioners  20  mounted on cellar deck  126  allows greater access to christmas trees  22  on production risers  24 B and BOP  124  on drilling riser  24 A and increases the clearance between trees  22  (and BOP  124 ) and drilling rig substructure  122  when the tensioners are fully stroked up. Cellar deck  126  also provides deck access to the bottom portions of tensioners  20  for inspection and maintenance in mild metocean conditions and the structure of cellar deck  126  may at least partially shield tensioners  20  from wave slamming in severe metocean conditions. Cellar deck  126  may be sufficiently small that the hydrodynamic behavior of the DTS in storm conditions is not adversely affected. The lower extent of cellar deck  126  may be at an elevation that provides no air gap in a 100-year storm. 
     In a riser system according to the invention, riser conductor  26  may span from the tensioner deck to below the pontoon keel guide on the DTS which protects the riser through the splash zone and also from potential boat or debris impacts. Conductor  26  may be made from multiple sections so as to be field installable or quayside installable. Conductor  26  may have a flush inside surface, with connectors using the “snap together” style Merlin® TLP tendon connectors (Oil States Industries, Inc. Arlington, Tex. 76001) that may be assembled or disassembled on the vessel. The inside diameter of conductor  26  may be selected to permit running drilling and production riser tieback connectors through the inside. 
     Conductor  26  may be made from thicker wall pipe at the top and bottom, and thinner wall pipe in the middle to reduce weight and increase flexibility.
         The riser keel joint centralizer  96  may be located below the keel guide  28  in order to take full advantage of the conductor flexibility.   The outside diameter of the conductor  26  interfaces with a keel guide  28  to react side loads from the riser  24 .   The inside surface of the conductor  26  interfaces with a keel joint  62  having a keel centralizer  96 .   The inside of the conductor  26  may be pressurized with air, nitrogen or other suitable gas to increase the tension on the riser  24  by buoyancy of the conductor pie  26 .       

     A bumper system for minimizing impact in the hull, deck, and riser may comprise an elastomeric element  68  as part of the keel joint centralizer  96 . An elastomeric element  72  between the conductor head and the upper tensioner frame absorbs shock from axial load of bottoming out and reduces lateral loads. 
     An example of a suitable tensioner system uses six cylinders with piggy back style composite high-pressure bottles  40  for decreased load variation. Double acting cylinders with fluid contained only on the rod side for seal lubrication may be used. 
     The tensioner  20  may have a compression cylinder configuration where fluid is contained at the bottom of the cylinder to provide damping at cylinder full down stroke. 
     A tension joint may be connected to the outer riser to enable space out of the tensioner stroke relative to the riser length. 
     A keel guide  28  acts to lower the riser lateral load reaction point and overturning moment, thereby improving platform stability. 
     Segmented composite bearings  60  in keel guide interface with the outer surface of the conductor  26  and may be replaced individually by divers or by a remotely operated vehicle (ROV). 
     The outside surface of the conductor  26  may be clad with Inconel or similar corrosion resistant material to eliminate potential corrosion damage and reduce friction forces applied to the tensioner  20  and riser  24 . 
     Advantages and benefits of the invention over the existing systems include the following: 
     a) The conductor  26  extends from the top tensioner frame to the keel joint. The large diameter of the conductor provides guidance for the production riser completely through the hull with full bore. 
     b) The outside diameter of the conductor reacts on the keel guide  28  and the riser pipe  24  moves with the conductor  26  so there is no relative motion, and hence no wear occurs on the pressure-containing riser pipe  24 . 
     c) The conductor is pre-installable at the shipyard or may be removed or installed offshore. 
     d) The conductor shields the production risers from splash, surface currents and potential boat impact. 
     e) The conductor reduces drag loads on the production risers due to surface currents during installation while also reducing the potential for riser clashing. 
     f) The top of the conductor may incorporate an elastomeric bumper element, for reducing potential impact as a result of bottoming out the tensioning system. 
     g) The keel guide may incorporate an elastomeric bumper element, that reduces potential impact damage at the riser and keel interface. 
     h) The keel joint centralizer is spaced to react the lateral riser loads below the keel guide interface. This provides additional flexibility and minimizes potential for clashing between the riser and keel guide. 
     Benefits to the tensioning system include the following: 
     a) The large diameter of the conductor  26  reduces bearing stresses at the guide rollers  42  and  44  and on the cylinders to enhance reliability and provide long life. 
     b) The conductor  26  may comprise sections with reversible connectors based on proven TLP connector technology. This allows installation of additional tensioners in the field and permits removal for maintenance if required. 
     c) The elastomeric bearing  72  in the upper tensioner frame allows small deflections which reduces lateral load on the cylinder rods  38  thereby enhancing seal life and cylinder durability. 
     d) One particular preferred arrangement uses tensioners having six cylinders and gas volume attached to the cylinder with composite high-pressure bottles  40 . With six cylinders, the volume per cylinder is sufficiently small that the entire gas volume required may be attached to the cylinder, thus minimizing flow losses and enhancing system safety and reliability. In addition, the applied moment is reduced to a more acceptable level should a cylinder need to be removed for maintenance. 
     e) The tensioner cylinder configuration may use gas only below a piston with fluid on a reduced rod side area to provide lubrication to seals and bearings. The system may use nitrogen as the operating gas to minimize corrosion and enable the use of synthetic, mineral-type fluids. 
     f) The conductor may be filled with nitrogen, air, or other suitable gas to provide additional riser tension from the resulting buoyancy. This additional tension may supplement the riser hydraulic tension for heavy riser conditions or for hydraulic system maintenance. 
     Benefits of the system to hull/keel guide include the following: 
     a) Roller supports  42  and  44  at the tensioner  20  used in conjunction with the keel guide  28  virtually eliminates surface equipment lateral movement, and therefore reduces the well bay spacing requirement. 
     b) The keel guide wear components may be removed for replacement if required without conductor and riser removal. 
     Benefits of the invention to the global layout of the platform include the following: 
     a) Roller supports  42  and  44  at the tensioner  20  in conjunction with the keel guide  28  virtually eliminates surface equipment lateral movement, and therefore reduces the well bay spacing requirement. 
     b) The conductor  26  is pre-installable at the shipyard, or may be installed offshore. In addition, the conductor  26  may be removed and re-installed offshore. 
     c) Elimination of large-diameter, high-pressure piping from cylinders to active gas bottles, also known as applied pressure vessels (APV&#39;s), which are located away from the tensioner unit and connected by a long run of piping. 
     d) Riser lateral loads are reacted low on the semi-submersible&#39;s hull, thereby improving platform stability for a given draft. 
     The foregoing presents a particular embodiment of a system embodying the principles of the invention. Those skilled in the art will be able to devise alternatives and variations which, even if not explicitly disclosed herein, embody those principles and are thus within the scope of the present invention as literally and equivalently covered by the following claims.