Patent Publication Number: US-2009223673-A1

Title: Offshore Riser Retrofitting Method and Apparatus

Description:
BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     The present invention generally pertains to offshore platforms, and more particularly to offshore oil or gas platforms in need of being retrofitted with a riser. 
     2. Description Of The Related Art 
     It is known within the oil and gas industry that in certain applications, depending on the characteristics of a given offshore field and the desires of the operator, it may be desirable to retrofit an existing offshore platform with what is known in the industry as a “riser”. A riser is simply a long pipe or conduit that runs from the deck of the platform down to the sea floor, where it is connected to a pipeline. Oil and gas extracted from beneath the sea floor that is produced up to the deck of the platform may then be routed down through the riser and into the pipeline, which transports the oil and gas to another location (e.g., another platform or land) for further processing. 
     The current method of retrofitting a riser to an existing platform is to attach the riser in sections to the outside of the platform jacket. This is done using divers who bolt the pipe sections together to form the riser and attach it to the platform jacket. As shown in  FIG. 1 , a platform  10  generally includes a deck  12  and a jacket  14 . The jacket  14  is the support structure for the deck  12 . The jacket  14  rests on the ocean floor  16 .  FIG. 1  illustrates a riser  18  that has been attached to the exterior of the jacket  14 . The riser  18  is connected to a pipe line  20  running along the ocean floor  16 . 
     One problem with the current approach to retrofitting a riser  18  to an existing platform  10  is that safety concerns require that production be stopped during the time that the riser  18  is being attached to the jacket  14 . One reason for this is because divers are used to bolt and attach the riser  18  to the outside of the jacket  14 . Another reason for shutting down production is the potential for a section of the riser to be dropped on an existing pipeline, thereby rupturing it and creating a hazardous environment. The production downtime is extremely costly to the oil field operator. For example, it would not be uncommon for the operator to lose millions of dollars for each day of downtime. 
     Another problem with the current retrofitting method is that the number of days of downtime depends on site conditions, such as weather and wave activity. For example, these site conditions may require the crew to halt the retrofitting operation until the conditions improve. In these situations, the operator is at the mercy of the weather, for example, until the weather clears. Not only is millions of dollars of production being lost for each day of inactivity, but leased equipment must be paid for while waiting for the site conditions to improve. This equipment lease cost can easily add hundreds of thousands of dollars per day to the retrofitting tab. 
     As explained more fully below, the present invention is directed to a new and improved approach to installing a riser to an offshore platform. The present invention does not require termination of production during the installation operation. As such, it is believed that the use of the present invention will result in millions of dollars of cost savings to the operator. 
     SUMMARY OF THE INVENTION 
     In one aspect, the present invention may be a method of establishing a fluid flow path from a deck of an offshore platform supported by a jacket to a pipeline located in a body of water beneath the deck, comprising: positioning a conduit in the body of water below the deck, the conduit having a first end located within the jacket and a second end located outside of the jacket; constructing a riser having an upper end and a lower end; positioning the riser within the jacket with the upper end located at the deck; and connecting the lower end of the riser to the first end of the conduit. Another feature of this aspect of the invention may be that the method further includes performing each of the steps without ceasing production operations of the platform. Another feature of this aspect of the invention maybe that the method further includes connecting the second end of the conduit to the pipeline. Another feature of this aspect of the invention may be that the method further includes establishing fluid communication between the upper end of the riser and a source of hydrocarbons below the body of water. Another feature of this aspect of the invention may be that the method further includes positioning the riser within a plurality of conductor guides on the jacket. Another feature of this aspect of the invention may be that the method further includes stabilizing the riser within the conductor guides. Another feature of this aspect of the invention may be that the method further includes positioning a pair of generally semi-circular shaped centralizer members in an annulus formed between the riser and each conductor guide. Another feature of this aspect of the invention may be that the method further includes filling an annulus between the riser and each conductor guide with a material and allowing the material to set. Another feature of this aspect of the invention may be that the material is at least one of a grout and an epoxy. Another feature of this aspect of the invention may be that the method further includes electrically isolating the riser from the jacket. Another feature of this aspect of the invention may be that connecting the lower end of the riser to the first end of the conduit is performed without the use of a diver. Another feature of this aspect of the invention may be that connecting the lower end of the riser to the first end of the conduit is performed with a remotely operated vehicle. Another feature of this aspect of the invention maybe that the method further includes connecting at least one inflatable bladder to the conduit and remotely controlling the pressure in the bladder to assist in positioning the first end of the conduit adjacent the lower end of the riser conduit. Another feature of this aspect of the invention may be that the method further includes an enclosure containing the inflatable bladder. Another feature of this aspect of the invention may be that the method further includes using a diverless connector to connect the lower end of the riser to the first end of the conduit. Another feature of this aspect of the invention may be that the method further includes using a light source to align the lower end of the riser with the first end of the conduit. 
     In another aspect, the present invention may be an apparatus for connecting a generally vertical riser within a jacket of an offshore platform to a pipeline located outside of the jacket, comprising: a frame; and a generally L-shaped conduit attached to the frame, the L-shaped conduit having a first end adapted for connection to a lower end of the riser conduit and a second end adapted for connection to the pipeline. Another feature of this aspect of the invention may be that the apparatus further includes at least one remotely-controllable inflatable bladder adapted to assist in positioning the first end of the conduit adjacent the lower end of the riser. Another feature of this aspect of the invention may be that the apparatus further includes a diverless connector connected to the first end of the L-shaped conduit and a mating connector connected to the lower end of the riser. 
     In still another aspect, the present invention may be an apparatus for constructing a riser comprising: a support base; a tower rotatably attached to the base and moveable between a lower position and an upper position; a top clamp movably attached to the tower; a bottom clamp attached to the support base, and aligned with the top clamp when the tower is in its upper position; and an enclosure having an open position and closed position, the enclosure being positioned between the bottom clamp and the top clamp when the enclosure is in its closed position. 
     The above summary of the invention is not intended to, nor does it, attempt to summarize all aspects of the present invention. Other features, aspects and advantages of the present invention will become apparent from the following discussion and detailed description. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a side view of a prior art offshore platform showing that a riser that has been retrofitted to the outside of the platform. 
         FIG. 2  is a side view showing one embodiment of the present invention. 
         FIG. 3  is an end view of a specific embodiment of a tube turn skid of the present invention. 
         FIG. 4  is a side view in cross section illustrating how a riser of the present invention may be centrally stabilized in a conductor guide and/or electrically isolated from an offshore platform jacket. 
         FIG. 5  is side view in partial cross-section showing another embodiment of the present invention. 
         FIG. 6  is a side view showing another embodiment of a tube turn skid of the present invention. 
         FIG. 7  is a top view of the tube turn skid shown in  FIG. 6 . 
         FIG. 8  is an end view of the tube turn skid shown in  FIGS. 6 and 7 . 
         FIG. 9  is a side view in partial cross section of an offshore platform with the tube turn skid being lowered into position. 
         FIG. 10  is another view similar to  FIG. 9 , showing the tube turn skid attached to a number of winches and being moved into position. 
         FIG. 11  is another view similar to  FIGS. 9 and 10 , showing additional cables located adjacent a column of conductor guides and connected to the tube turn skid to assist in locating the skid in its desired position for connection to the jacket and the riser. 
         FIG. 12  is a top view showing the tube turn skid in position as illustrated in  FIG. 11 . 
         FIG. 13  is a side view showing a platform crane and a vertical stalking station located on an upper deck of the offshore platform, with the vertical stalking station in its upright position. 
         FIG. 14  is a side view similar to  FIG. 13 , except that the vertical stalking station is shown in a lowered or horizontal position and with the crane being used to load a section of riser pipe or conduit onto the vertical stalking station. 
         FIG. 15  is a side view in partial cross-section of a section of pipe or conduit used to form a riser according to the present invention, such as the conduit illustrated in  FIG. 14 . 
         FIG. 16  is a side view similar to  FIGS. 13 and 14 , showing the crane being used to raise the vertical stalking station from its lowered position to its upright position. 
         FIG. 17  is a side view similar to  FIGS. 13 ,  14  and  16 , showing the vertical stalking station in its upright position and with the section of riser pipe being lowered. 
         FIG. 18  is a side view similar to  FIGS. 13 ,  14 ,  16  and  17 , showing the first section of riser pipe lowered into engagement with a bottom clamp on the vertical stalking station. 
         FIG. 19  is a side view similar to  FIGS. 13 ,  14 ,  16 ,  17  and  18 , showing a next section of riser pipe being held in position by the vertical stalking station above and in aligned contact with the section of riser pipe located in the bottom clamp, and with a welding habitat rotated around the joint formed by the two sections of riser pipe to be welded together. 
         FIG. 20  is a top view of a horizontal joint support on the vertical stalking station and shown in a closed or clamped position. 
         FIG. 21  is a top view of the horizontal joint support shown in  FIG. 20 , only in  FIG. 21  the horizontal joint support is shown in an open position. 
         FIG. 22  is a top view of the welding habitat in a closed position. 
         FIG. 23  is a top view of the welding habitat showing it being rotated to an open position. 
         FIG. 24  is a top view of a specific embodiment of a top clamp on the vertical stalking station, and shown in an open position. 
         FIG. 25  is a top view of the top clamp shown in  FIG. 24 , but shown in  FIG. 25  in a closed or clamped position. 
         FIG. 26  is a top view of a specific embodiment of a bottom clamp on the vertical stalking station, and shown in an open position. 
         FIG. 27  is a top view of the bottom clamp shown in  FIG. 26 , but shown in  FIG. 27  in a closed position. 
         FIG. 28  is a side view showing the top clamp of  FIGS. 24 and 25  being lowered down towards the bottom clamp shown in  FIGS. 26 and 27 . 
         FIG. 29  is a side view similar to  FIG. 28 , but showing the top clamp lowered down to a position adjacent the bottom clamp. 
         FIG. 30  is a top view of the top clamp positioned above the bottom clamp. 
         FIG. 31  is an end view of the top clamp and bottom clamp as shown in  FIG. 28 . 
         FIG. 32  is an end view of the top clamp and bottom clamp as shown in  FIG. 29 . 
         FIG. 33  is a side view showing a pair of centralizer segments shown in spaced apart relation. 
         FIG. 34  is a top view of the centralizer segments shown in  FIG. 33 . 
         FIG. 35  is a side view showing the centralizer segments shown in  FIGS. 33 and 34  disposed within a conductor guide on a platform jacket and with a riser disposed therethrough. 
         FIG. 36  is a top view of the view shown in  FIG. 35 . 
         FIG. 37  is a side view showing an annular bladder being positioned around a riser and within a conductor guide to be used to hold a hardenable material such as grout or epoxy to stabilize the riser within the guide. 
         FIG. 38  is a top view of the configuration shown in  FIG. 37 . 
         FIG. 39  is a side view similar to  FIG. 37 , only showing the bladder after it has been filled. 
         FIG. 40  is a top view of the configuration as shown in  FIG. 39 . 
     
    
    
     While the invention will be described in connection with the preferred embodiments, it will be understood that it is not intended to limit the invention to those embodiments. On the contrary, it is intended to cover all alternatives, modifications, and equivalents as may be included within the spirit and scope of the invention as defined by the appended claims. 
     DETAILED DESCRIPTION OF THE INVENTION 
     First Embodiment 
     Referring to the drawings in detail, wherein like numerals denote identical elements throughout the several views, there is shown in  FIG. 2  an offshore platform  11  and one embodiment of the present invention wherein a riser  19  is installed, without terminating production, inside of or down the interior of a jacket  21  of the platform  11  utilizing an existing unused drilling conductor “slot”.  FIG. 2  further shows a pipeline connection assembly or tube turn skid  22  (see dashed lines) that is provided to connect the bottom of the riser  19  (located inside the jacket  14 ) to a pipe line  23  (located outside the jacket  21 ). 
     In one embodiment, the present invention may rely on or make use of existing structure located on the platform  11 . As is well known to those of skill in the industry, drilling and production platforms are typically constructed with a number of “routes” or “channels” through which drilling string and production tubing (not shown) may be directed down inside the jacket  21  and into the ocean floor  17 . If it is desired to use one of the routes in a drilling or production operation, a “conductor” (which is a pipe, not shown) is fed from a deck  13  of the platform  11  (in sections) down through conductor guides  24  (which are sometimes like funnels) corresponding to the particular slot selected. The conductor (not shown) is fed (in sections) down to and driven into the ocean floor  17 . Drilling string (not shown) is then passed down through the conductor to drill the well. After the well has been drilled and the drilling string is removed, production tubing (not shown) is installed through the conductor to complete the well and produce the hydrocarbons to the platform  11 . This background on conductors is merely provided for a background understanding of the purpose of the conductor guides  24 . 
     In one aspect of the present invention, the guides  24  maybe utilized for a different purpose. With reference to  FIG. 2 , it can be seen that the riser  19  is fed down through the guides  24 , and then connected to the tube turn skid  22  via a connection  26 . As will be discussed further below, the connection  26  may be any type of connection in which two sections of pipe or conduit may be remotely connected through the use of a Remotely Operated Vehicle (“ROV”). One example of an industry-standard connection, which has been used in ultra-deepwater diverless applications, may be a collet connection assembly of the type available from Cameron International Corporation, of Houston, Tex. Other known connectors may be of the type available from FMC Corporation, of Houston, Tex., or Oil States Industries, of Arlington, Tex., for ultra-deepwater/ROV applications. 
     The tube turn skid  22  is preferably placed into its position before the riser  19  is lowered down through the guides  24 . The skid  22  can be lowered into position through the use of a platform crane and winches (not shown), as more fully discussed below. The tube turn skid  22  may include a generally L-shaped section of pipe  28  mounted to a support frame  30 . The L-shaped section  28  preferably includes a bend of sufficient diameter to allow traditional pigging equipment to pass therethrough, as will be understood by those of skill in the art. Part of the connection  26  (denoted as  26   a ) may be connected to the upstanding vertical portion of the L-shaped member  28 . The other end of the L-shaped member (i.e., the end of the horizontal section of the L-shaped member  28 ) may be provided with a flange  36  and positioned outside of the jacket  21 . The flange  36  is of any known type used for connecting a riser to the pipe line  23 . Attached to the frame  30  maybe a downwardly extending stabbing connector  32  adapted for engagement with a lowermost guide  34  on the jacket  21  at the mudline level, if available. The stabbing connector  32  may be a pipe that is disposed in co-axial relationship with the vertical end (i.e., where the connection part  26   a  is located) of the L-shaped member  28 . 
     As best seen in  FIG. 3 , which is an end view of one sample embodiment of the tube turn skid  22 , it can be seen that the frame  30  may include upstanding side members  38  adapted to contain inflatable balloons or bladders  40  that may be secured to the side members  38 . As more fully discussed below in connection with another embodiment of the present invention, a mesh covering may be provided to contain the balloons  40  to control their volume and assist in controlling the buoyancy of the skid  22 , as more fully discussed below. 
     The installation process is preferably commenced by lowering the tube turn skid  22  from the deck  13  down to or near the ocean floor  17 . At that point, the balloons  40  are inflated, through the use of an ROV, until neutral buoyancy is achieved. (In actuality, as is known in the industry, neutral buoyancy actually means slightly negative buoyancy, so the part to which the balloons are attached will not rise to the water surface.) Rigging cables (not shown in  FIG. 2 ) are also preferably passed downwardly and connected to the top of the curved portion of the L-shaped member  28 . The ROV (not shown) can then grasp the tube turn skid  22  and maneuver it, assisted by the rigging cables, from outside the jacket  21 , through an opening in the jacket  21 , to its desired position inside the jacket  21 . As shown in  FIG. 2 , the stabbing connector  32  on the bottom of the frame  30  when available may be stabbed into engagement with the lowermost guide  34 . It is noted that if the site conditions worsen (e.g., unexpected strong water currents) during the process of moving the tube turn skid  22  from outside the jacket  21  to inside the jacket  21 , the balloons  40  may be deflated to lower the skid  22  to the ocean floor  17  until conditions improve. As more fully discussed below in connection with another embodiment, an umbilical containing various hoses and cables is provided to remotely operate various items of equipment preferably provided to connect the riser  19  to the skid  22  (e.g., sonar, video, hydraulic, load cells, green laser fan alignment lights, etc.). 
     Next, after the skid  22  is properly positioned, the rigging cables are removed, and the riser sections are then serially welded and lowered downwardly through the use of an assembly station  42  located on the deck  12 . The station  42  may include, for example, structure similar to a J-Lay tower of the type that has been proven for use on barges, and a positive-pressure welding station or habitat. The riser sections are serially held in place by the station  42  and welded inside the welding habitat to the riser  19 , which is gradually lowered downwardly through the guides  24 . The lower end of the riser  19  may include a part  26   b  of the connection  26 , which may be remotely engaged, through the use of the ROV and various video and sonar feeds with the umbilical, to the part  26   a  of the connection  26 , which is attached to the top of the L-shaped pipe  28 . The flange  36  on the end of the horizontal portion of the L-shaped member  28  may then be connected to the pipe line  23  in a known manner. 
     It is also preferable that the riser  19  be stabilized within the conductor slots  24  and/or electrically isolated from the jacket  21 . As shown, for example, in  FIG. 4 , this may be accomplished by positioning arcuate wedge sections  44  in the annulus formed between the riser  19  and the guides  24 . It is noted that the size of the annulus will depend on the size of the pipe used for the riser  19  and the size of the conductor slots  24 . The wedge sections  44  are preferably provided with a suitable material  46  (e.g., neoprene) to engage the riser  19  to electrically isolate the riser from the jacket  21 . In another embodiment, as more fully discussed below, a hardenable filler material, such as grout or epoxy, for example, may be positioned through the use of an annular bladder in each annulus between the riser  19  and the guides  24 . 
     Second Embodiment 
     Another embodiment of the present invention will now be described with reference to  FIGS. 5-40 . Referring to  FIG. 5 , an offshore platform  50  includes a jacket  52  resting on the ocean floor  54 . The platform  50  may further include an upper deck  56  and a lower deck  58 , both positioned above the ocean water surface  60 . The platform  50  is provided with a platform crane  62 . A vertical stalking station  64  is shown mounted on the upper deck  56 , which will be described in more detail below in connection with  FIGS. 9-16 . The platform  50  may be provided with one or more conductors  66  positioned within guides  67  for use in drilling a well in and/or producing hydrocarbons from beneath the ocean floor  54 . 
     The platform  50  further includes a welded vertical riser string (or riser)  68  that has been installed through the use of the vertical stalking station  64 . The riser  68  is positioned down through the interior of the jacket  52 , as opposed to on the outside of the jacket  52 . Again, the riser  68  may be installed without ceasing production in order to eliminate downtime costs. Attached to the lower end of the riser  68  is a tube turn skid  70 , which will be described in more detail below in connection with  FIGS. 6-8 . The tube turn skid  70  is shown connected to the lower end of the riser  68  via a diverless connection  106  (e.g., a proven industry-standard collet connector of the type discussed above). The platform  50  is preferably provided with segmented centralizers  74  within each guide  67  through which the riser  68  is passed to centrally stabilize the riser  68  within the guides  67  and/or electrically isolate the riser  68  from the jacket  52 . The centralizers  74  are more discussed below in connection with  FIGS. 33-36 . Alternatively, as explained above and discussed more fully below in connection with  FIGS. 37-40 , the riser  68  may be stabilized and electrically isolated within the guides  67  through use of an annular bladder filled with a material such as grout or epoxy, for example. 
     The platform  50  is also preferably provided with a fusion bonded epoxy (FBE) application habitat  76  below the vertical stalking station  64  (e.g., between the upper deck  56  and lower deck  58 ) to apply FBE or any other suitable field joint corrosion coating to the welded joints of the riser  68 . After the riser  68  has been welded and installed into position, the upper end of the riser  68  is preferably engaged with a temporary support friction clamp  78  of a type known in the industry to hold the riser  68  in place after it is disconnected from the stalking station  64  until it can be tied-in to a production manifold by a mechanical contractor. 
     The platform  50  may also be provided with a number of winches  82  (e.g., air and/or hydraulic winches), each having a cable  84  that may be used in positioning the tube turn skid  70 . A platform-based work-class remotely-operated vehicle (ROV)  86  of the type known in the industry (e.g., a 100 horsepower ROV) is also provided to assist in positioning the tube turn skid  70  and make the necessary connections at the skid  70 . The size of the ROV  86  should be selected in light of the capacity of the crane  62  so that the crane  62  is able to lift the ROV  86  to deck level from a supply boat. The platform  50  may also be provided with a sonar/video system  88  to enable surveillance of the positioning and connecting of the skid  70 . The skid  70  is also provided with an umbilical  90  running from the upper or lower deck  56  or  58  to the skid  70 . The umbilical  90  may include a variety of cables or conductors, such as for air, hydraulics, light power, load cell and video feeds, for example. The umbilical  90  is preferably connected to a control panel located, for example, on one of the decks  56  or  58 , to enable an operator, such as at deck level, to remotely operate the necessary equipment to position and make the necessary connections to the skid  70 . 
     The Tube Turn Skid 
     The tube turn skid  70  shown in  FIG. 5  will now be described in more detail in connection with  FIGS. 6-8 . Referring to  FIG. 6 , the tube turn skid  70  may include a support frame  92  and a conduit  94  having a riser end  96  and a flange end  98 . The skid frame  92  is preferably configured to rest on bracing at the bottom of the jacket  52 . Depending on the desired placement of the skid  70  on the jacket bracing, it may be necessary to use the ROV  86  to remove anodes attached to the jacket bracing for later relocation by pipeline divers. The frame  92  may be secured to structural members  93  on the jacket  52  through the use of any appropriate connecting mechanism, such as U-clamps  95 , for example, as shown in  FIG. 6 . The skid frame  92  is preferably clamped to the jacket bracing  93  by pipeline divers when the skid  70  is connected to the pipeline. The conduit  94  may be a section of pipe having a generally straight or horizontal section  100  and a curved section  102 . In a specific embodiment, the conduit  94  may be a  3 D or  5 D induction bend. The particular curvature and dimensions of the conduit  94  will be dictated by the specific design and configuration of the platform  50  and jacket structure (e.g., grid layout of conductor slots  67 ), and may, for example, bend only in one plane. In a specific embodiment, the induction bend may be configured for three-dimensional reach to the desired conductor slot  67 . The flange end  98  may include a flange  104  suitable for connection to a pipe line (not shown here) as will be understood by those of ordinary skill in the art. The riser end  96  of the conduit  94  is preferably provided with a diverless connector  106 . 
     The connector  106  may be any type of diverless connector known in the art that can be used to remotely connect two sections of conduit located underwater through the use of an ROV, some examples of which were previously provided above. In a specific embodiment, the connector  106  may be a collet connector that includes hydraulic activation cylinders  108  that are connected to one or more hydraulic fluid conduits  110  contained within the umbilical  90 . A video camera  112  may also be mounted adjacent the connector  106  (and/or on the skid  70  and/or jacket  52 ) and connected to a video cable  114  contained within the umbilical  90 . The connector  106  may also be provided with a green fan laser  116 , as will be understood by those of skill in the industry, atop the connector  106  to assist in coaxial alignment of the connector  106  with the conductor guides  67  through which the riser  68  is to be positioned, as more fully discussed below. In a specific embodiment, the green fan laser  116  may be of the type available from Imenco AG of Haugesund, Norway, known as The Imenco Underwater Green Laser. 
     In this specific embodiment, the skid  70  is further preferably provided with at least one air bladder or balloon, such as a first air bladder or balloon  118  and a second air bladder or balloon  120 . The first bladder  118  is preferably contained within a first enclosure  122  and the second bladder  120  is preferably contained within a second enclosure  124 . In a specific embodiment, the enclosures  122  and  124  may be cages made with rigid or flexible steel mesh. The use of the enclosures  122 / 124  is preferred to assist in avoiding the possibility of uncontrolled positive buoyancy, as discussed above and as will be readily understood by those of skill in the art. The air bladders  118 / 120  may be remotely inflated via an air hose  126  contained within the umbilical  90 . This allows for remote control from the deck of the in-water weight of the skid  70  to maintain negative buoyancy (i.e., avoid the possibility of run-away positive buoyancy). In a specific embodiment, for example, the in-water weight of the skid  70  maybe adjusted to approximately  500  pounds or determined to correspond to the ROV capacity. 
     The skid  70  is also preferably provided with a cable assembly  128  having a load cell  130  and a ring eye  132 . The load cell  132  is connected to an electrical cable  134  contained within the umbilical  90  to provide a reading to an operator at the deck of the in-water weight of the skid  70  so that appropriate negative buoyancy can be maintained. The manner in which the skid  70  may be positioned will now be explained with reference to  FIGS. 9-11 . 
     Positioning of the Tube Turn Skid 
     Referring now to  FIG. 9 , a cable  87  from a winch  89  maybe connected to the ring eye  132  on the cable assembly  128  on the skid  70 . The winch  89  maybe connected to and supported by a platform crane  63  on the upper deck  56  until the skid  70  is positioned near the point through which the skid  70  is to be passed through the platform jacket  52 . As shown in  FIG. 10 , the skid  70  is then transferred from the crane  63  to a number of winch lines  84  connected to winches  82 . The winch lines  84  may be routed through the use of pulleys (e.g., pulley  85 ) mounted to the jacket  52  and/or routed around jacket members. These lines are used to position the connector  106  on the tube turn skid  70  beneath the column of conductor guides  67  through which the riser  68  is to be positioned. The ROV  86  may also be used to grasp the skid  70  and assist in locating it in its desired position relative to the jacket  52 . With reference to  FIGS. 11 and 12 , additional winch lines  97  may be routed downwardly adjacent to the selected column of conductor guides  67  and attached to the riser end  96  of the conduit  94  on the skid  70  to assist in positioning the skid  70 . The green fan laser  116  (see, e.g.,  FIG. 6 ) on top of the diverless connector  106  is then used in a known manner to shine a beam of visible light upwardly through the column of conductor slots  67  through which the riser  68  is to be positioned. In this manner, the exact desired location of the skid  70  may be established and the skid  70  can be precisely positioned so that the skid  70  can be leveled and the connector  106  can be engaged with the riser  68 . In a specific embodiment, two circular plates (not shown) may be provided to assist in use of the green fan laser  116 . The plates are provided with a diameter to permit them to be placed by the ROV in the two conductor guides  67  located immediately above the connector  106 . The plates are preferably painted white. The plate to be positioned in the guide  67  immediately above the connector  106  preferably has a hole cutout (e.g., having a diameter of approximately three inches) in the center of the plate. The plate to be positioned above the lower plate is preferably provided with a black or dark-colored crosshair marking. These plates thus cooperate to assist in using the green fan laser  116  to align the connector  106  beneath the guides  67  for engagement with the riser  68 . 
     Once the tube turn skid  70  is properly positioned, the next step is to construct and lower the riser  68  into position so that it can be attached to the tube turn skid  70  by the diverless connector  106 . This is done through the use of the vertical stalking station  64 , as will now be explained in connection with  FIGS. 13-32 . It is noted that, at this time, the ROV  86  and/or winches  82  may be used to temporarily hang the centralizers  74 , for later installation, on the jacket bracing adjacent the conductor slots  67  through which the riser string  68  is to be located. 
     The Stalking Station 
     Referring to  FIG. 13 , in a specific embodiment, the stalking station  64  may include a support base  136  attached to drilling deck skid beams  138  on the upper or drill deck  56 . As will be described more fully below, the support base  136  may comprise a pair of generally parallel I-beams positioned on the deck skid-beams  138 . The station  64  is positioned over the empty column of conductor slots  67  through which the riser  68  is to be lowered. The station  64  also includes a tower  140  that is hingedly connected to the support base  136  at a pivot point  142 . The tower  140  is moveable between a vertical position (as shown in  FIG. 13 ) and a horizontal position (as shown in  FIG. 14 ). A hinged support arm  144  is connected to the support base  136  and tower  140  to hold the tower in its vertical position, and is collapsible to allow the tower  140  to move to its horizontal position. The tower  140  also includes a winch  146  (e.g., a hydraulic winch) that controls a cable  148  that runs to the top of the tower  140  and over a pulley  150  and then down to a top clamp  152 . The top clamp  152  includes rollers  186  and  187  to facilitate movement of the top clamp  152  up and down along the tower  140 , as more fully discussed below in connection with  FIG. 28 . The structure and operation of the top clamp  152  is more fully described below in connection with  FIGS. 24-25  and  28 - 32 . The tower  140  also includes a horizontal joint support  154 , the structure and operation of which is described more fully below in connection with  FIGS. 20 and 21 . The station  64  also includes a bottom clamp  156  disposed on the support base  136 . The structure and operation of the bottom clamp  156  will be described more fully below in connection with  FIGS. 26-32 . 
     The station  64  also includes a positive pressure welding habitat  158  connected to a vertical support member  160  that is connected to the support base  136  and adapted for rotatable movement, as will be further discussed below, including in connection with  FIGS. 22-23 . The use of pressurized enclosures and rooms is well known and customary on offshore platforms for safety reasons. The welding habitat  158  is supplied with a positive pressure air flow via an air duct connected to a remotely-located ventilator fan positioned a safe distance from any areas where a potential leak or hazard might arise on the platform. Attached to the top of the tower  140  is an x-ray spider davit  141  that is provided to lower an x-ray source inside the riser  68  to inspect each weld as the riser sections  162  are welded together within the welding habitat  158 . As mentioned above in connection with the size of the ROV  86 , the various components of the stalking station  64  should be designed and sized within the capacity of the crane  62  so that the crane  62  will be able to lift the components to the deck surface from a supply boat for assembly. 
     Assembling the Riser String 
     The vertical stalking station  64  is used to create the welded vertical riser string  68  (see  FIG. 5 ) by welding together sections of riser pipe or conduit  162 , such as shown in  FIG. 15 . The riser pipe sections  162  are preferably coated with FBE or other suitable corrosion inhibiting coating before the riser string  68  is constructed. With reference to  FIG. 15 , the conduit is depicted with a mating member  164  that corresponds to the diverless connector  106  on the tube turn skid  70  (see, e.g.,  FIG. 6 ). Again, the present invention is not limited to any particular brand or style of diverless connector. Thus, the section of conduit  162  shown in  FIG. 15 , with the mating member  164 , is the lowermost section of the riser  68 . This first, or lowermost, riser section shall be referred to by the numeral  162   a.  All subsequent conduit sections  162  will be as shown in  FIG. 15  except without the mating member  164 , and referred to by the numeral  162   b,  etc. The upper end of each conduit section  162  is provided with a collar  166  adapted for mating engagement with the top clamp  152  on the tower  140  and the bottom clamp  156 , as will be more fully discussed below. The lower end of the bottom riser section  162   a  is temporarily capped so as to prevent ocean water from flowing up into the riser  68  as it is being lowered into position, thereby eliminating the possibility of air flow at the welding habitat  158  that could be caused by water surge or wave action. Temporarily capping the bottom of the riser string  68  also allows the riser string  68  to be partially filled with water from the deck level in order to ballast the riser string  68  during the installation process, which may be more desirable with larger riser pipe diameters. The lower cap will be removed at a later stage after the riser  68  is positioned, preferably just prior to making the connection between the riser  68  and the diverless connector  106 . 
     As shown in  FIG. 14 , the tower  140  is shown in a lowered or generally horizontal position. The crane  62  is being used to position a section of riser conduit  162  on the tower  140 . The collar  166  on the riser pipe  162  is engaged with the top clamp  152  and the horizontal joint support  154  on the tower  140  is engaged with an opposite end of the riser pipe  162 .  FIG. 16  illustrates the crane  62  being used to lift the tower  140  from its lowered position to its upright or generally vertical position.  FIG. 17  illustrates the tower in its upright position and the top clamp  152  being lowered by the winch  146  to lower the riser pipe section  162  relative to the bottom clamp  156 . Note that after the lower end of the riser pipe  162  has passed through and is laterally supported by the bottom clamp  156 , the horizontal joint support  154  is disengaged from the riser pipe  162  and moved out of the way into an open or retracted position so as to allow the top clamp  152  to move downwardly past the joint support  154 .  FIG. 20  illustrates the horizontal joint support  154  in its closed or clamped position, and  FIG. 21  illustrates the horizontal joint support  154  in its open or retracted position.  FIG. 18  shows the top clamp  152  lowered all the way down adjacent the bottom clamp  156 . The top clamp  152  is unclamped from the riser pipe  162   a  and moved back to the top of the tower  140  once the collar  166  on the section of riserpipe  162   a  is resting on the bottom clamp  156  in a mechanically fail-safe position, as will be discussed and shown in more detail below. 
     The next step is to load the next section of riser pipe  162   b  onto the tower  140 , in the manner explained above. The top of each section of riser pipe  162   b  etc. is preferably temporarily capped so as to prevent the loss of positive pressure in the welding habitat  158  during the welding process, as more fully discussed below. Referring now to  FIG. 19 , once the tower  140  is loaded with the next section of riser pipe  162   b  and moved into its upright position, the lower end of the riser section  162   b  is positioned into coaxial alignment and contact with the upper end of the riser section  162   a  being held by the bottom clamp  156  to form a joint to be welded together. The manner in which the riser sections  162   a  and  162   b  are coaxially aligned by the bottom clamp  156  will be discussed and illustrated in more detail below. The welding habitat  158  is then rotated into a closed position so as to form a positive-pressure enclosure around the joint so that the two sections of riser pipe  162   a  and  162   b  can be safely welded in a known manner. A top view of the welding habitat  158  in its closed position is shown in  FIG. 22 . Once the field weld is completed, the welding habitat is moved into an open position (see, e.g.,  FIGS. 18 and 23 ), and the x-ray spider davit  141  is used to inspect the welded joint. Assuming the weld passes inspection, the bottom clamp  156  is released, and the top clamp  152  is lowered as explained above to lower the riser string  68  until the collar  166  on the riser section  162   b  is positioned into engagement with the bottom clamp  156 . This process is repeated until the entire riser string  68  has been constructed and the lowermost riser section  162   a  is positioned with the diverless mating connector  164  (see  FIG. 15 ) positioned adjacent the diverless connector  106  on the skid  70  for engagement thereto through the use of the ROV and above-described surveillance equipment. As the riser string  68  is gradually constructed and lowered down through the conductor slots  67 , it is preferred that temporary wooden centralizers be positioned in the annulus between the riser  68  and at least some of the conductor guides  67  (preferably at least the guides  67  just above and below the water line  60 ) to maintain stability of the riser string  68  during the installation process, and to especially avoid excessive movement of the riser string  68  due to wave action during the welding process. 
     Once the riser string  68  is connected to the connector  106 , the next step is to conduct an industry standard hydrotest of the riser assembly while the riser string  68  is still being held in by the stalking station  64 . The top of the riser string  68  is capped and the riser is filled with water and pressurized by a pump to a hydrostatic test pressure to confirm no leaks in the assembly of the riser  68  and the skid  70 . The centralizers  74  or hardenable filler material is then installed at each conductor guide  67  using the ROV  86 . The temporary friction clamp  78  is then clamped to the riser  68  at the lower or production deck level  58  to secure the riser  68  until a mechanical contractor executes the final tie-in to the production manifold. At a later time, pipeline installation divers may secure the skid  70  to the jacket  52 , such as with U-clamps  95 , as shown in  FIG. 6 , and reinstall any jacket anodes at the same time the flange  104  on the skid  70  is attached to the pipeline on the ocean floor  54 . 
     The Top and Bottom Clamps 
     Specific embodiments of the top clamp  152  and the bottom clamp  156  on the vertical stalking station will now be described. Referring to  FIG. 24 , a specific embodiment of the top clamp  152  is shown in an open position. The top clamp  152  may include a frame  170  with a pair of clamping arms  172  and  174  hingedly attached thereto. Each clamping arm  172 / 174  includes a curved clamping surface  176 / 178  sized for mating engagement with the riser pipe  162 . The top clamp  152  further includes any suitable mechanism for moving the arms  172 / 174  between open and closed positions. For example, in the specific embodiment shown in  FIG. 24 , the top clamp  152  may be provided with a jack screw  180  attached to the arms  172 / 174  via threaded flange members  182  and  184 , in a known manner. The top clamp  152  is also preferably configured for rolling engagement with the tower  140  of the vertical stalking station  64 . As shown in  FIG. 24 , the tower  140  may be an I-beam. The top clamp  152  may include an outer roller  186  disposed between the frame  170  and the tower  140 . The top clamp  152  may further include one or more inner rollers  188  positioned to engage an inner surface of the tower  140  such that the top clamp  152  is engaged with or connected to the tower  140  to permit rolling movement of the top clamp  152  up and down the tower  140 . As shown in  FIG. 28 , discussed further below, the top clamp  152  is preferably provided with a set of upper rollers  186 / 188  and a set of lower rollers  187 / 189 .  FIG. 25  is similar to  FIG. 24 , except that  FIG. 25  shows the top clamp  152  in its closed or clamped position, with the clamping surfaces  176 / 178  clamped around the riser pipe  162 . 
     Referring now to  FIG. 26 , the bottom clamp  156  may include a pair of clamping arms  190  and  192  configured for slidable engagement with the support base  136  of the stalking station  64 . With reference to  FIG. 31 , the clamping arm  190  is shown in cross-section, and it can be seen from this view that the support base  136  may comprise a pair of generally parallel I-beams  194  and  196 . It can further be seen from  FIG. 31  that the clamping arms  190 / 192  each includes a lower lip  198  that defines a slot  200  to allow for sliding engagement of the arms  190 / 192  with the I-beams  194  and  196 . The slots  200  are further preferably sized to allow for sufficient lateral movement of the arms  190 / 192  relative to the beams  194 / 196  for purposes of co-axial alignment of sections of riser pipe  162  to be welded together, as discussed in more detail below. 
     Referring again to  FIG. 26 , corresponding opposed ends of the arms  190 / 192  are connected to screw jacks  202 / 204  and configured to move between an open position (as shown in  FIG. 26 ) and a closed position (as shown in  FIG. 27 ). Each arm  190 / 192  further includes an arcuate ledge  206 / 208 . In operation, as shown in  FIG. 29 , when the top clamp  152  lowers a section of riser pipe  162  down through the bottom clamp  156 , the arms  190 / 192  are moved towards each other by the screws jacks  202 / 204  into a position such that the collar  166  on the riser pipe section  162  will rest on the arcuate ledges  206 / 208 . The purpose of the clamping arms is not to clamp and hold the riser string  68 , but instead to position the arcuate ledges  206 / 208  so as to support the collar  166 . In this way, a mechanical fail safe connection is provided to hold the riser string  68 . In other words, the riser string  68  is not susceptible to being dropped due to failure of a transverse clamping mechanism. Once the riser pipe collar  166  is securely resting on the arcuate ledges  206 / 208 , and the top clamp  152  has been withdrawn to retrieve another section of riser pipe  162 , the riser pipe  162  hanging in the arms  190 / 192  can be moved around as needed to position it in co-axial alignment with the next section of riser pipe to which it is to be welded. Side-to-side, or lateral, movement is accomplished through the use of a lateral positioning mechanism, such as a lateral hydraulic cylinder  210  that may be connected to the support base  136  and the arm  192 . The bottom clamp  156  may further be provided with one or more transverse or rotational positioning mechanisms, such as hydraulic cylinders  212  and  214 , which are connected to the support base  136  and the arms  192  and  190 , respectively. If both cylinders  212  and  214  are actuated in unison, then both arms  190 / 192  will move transversely together along with the pipe  162 . But if only one of the cylinders  212 / 214  is actuated or if they are actuated in different directions then rotational movement will be imparted to the riser pipe  162 . 
     Stabilizing the Riser in the Guides 
     Details of a specific embodiment of the centralizers  74  will now be described with reference to  FIGS. 33-36 . Referring to  FIG. 33 , a side view of a pair of centralizer segments  74   a  and  74   b  is shown in a spaced apart position.  FIG. 34  is a top view of the segments  74   a / 74   b  as shown in  FIG. 33 . Each segment  74   a / 74   b  includes a curved surface  216   a / 216   b  adapted for engagement around the riser string  68 . Each curved surface  216   a / 216   b  is preferably lined with a suitable material (e.g., neoprene) to electrically isolate the riser  68  from the jacket  52 .  FIGS. 35 and 36  illustrate the centralizer segments  74   a  and  74   b  installed in a conductor slot  67  with the riser  68  positioned therethrough. It can be seen from the side profile shown for example in  FIG. 36  that the segments  74   a / 74   b  may form a funnel and be adapted for mating engagement with the conductor slot  67 . 
     An alternative approach to stabilizing the riser  68  in the guides  67  and/or electrically isolating the riser  68  from the platform  52  will now be discussed in connection with  FIGS. 37-40 . Referring initially to  FIGS. 37 and 38 , an annular bladder  218 , such as an elastic latex bladder, shown here in an empty or collapsed form, maybe attached to a metal deployment ring  220 . The ring  220  should be of sufficient weight to pull the bladder  218  down through the water. The annular bladder  218  is sized to fit around the riser  68 . A pair of polypropylene ropes  222  are attached to the ring  220  and used to lower the bladder  218  into position adjacent the conductor guide  67 . The ROV  86  is used to monitor proper positioning of the bladder  218  relative to the guide  67 . Once in position, an injection hose  224  running from deck level is inserted into an aperture  219  in the bladder  218  and used to inject a hardenable or settable material into the bladder  218  so as to fill up with annulus between the guide  67  and the riser  68 , as shown in  FIGS. 39 and 40 . The filler material may be of any type (e.g., grout, epoxy, etc.) that could be used to fill the bladder and stabilize the riser  68  within the guides  67 . At least the inner diameter of the ring  220  is preferably covered with an insulating material (e.g., neoprene) so that the riser  68  is electrically isolated from the guides  67 . The bladder  218  is also preferably made of a material (e.g., latex) that will electrically isolate the riser  68  from the guides  67 . Once the bladder  218  is filled to the desired level, the ROV  86  may be used to cut the ropes  222  and hose  224 , the loose ends of which may then be retrieved to deck level. A bladder  218  for each guide  67  is preferably positioned over the riser string  68  just before the uppermost riser section  162  is welded to the riser string  68 , and then the bladders  218  are preferably lowered into position and filled after the hydrostatic pressure test is successfully completed. 
     From the above description it can be seen that by employing the present invention a riser can be installed on an existing operational offshore platform without terminating production, thereby avoiding economic loss associated with production downtime. Use of the present invention further eliminates expensive delays with marine equipment and diver operations due to unpredictable strong ocean currents and rough sea states. Use of the present invention further results in better control of interfacing schedules of offshore contractors, and expensive mobilization of marine equipment is also avoided. In addition, with the present invention, the riser can be installed and tested before pipeline installation equipment is mobilized. There are also safety benefits provided by the present invention insofar as it is not necessary to unduly subject divers and marine support vessels to potentially adverse currents or sea states. It can also be seen that the present invention is implemented pursuant to industry standard safe and high quality procedures for hydrocarbon producing environments. Another advantage of the present invention is that the riser sections are welded, as opposed to bolted, together, thereby resulting in better connections between the riser sections such that the joints are less susceptible to leakage. 
     It is to be understood that the invention is not limited to the exact details of construction, operation, exact materials or embodiments shown and described, as obvious modifications and equivalents will be apparent to one skilled in the art. It is also noted that although one benefit of the invention is the ability to install a riser to a platform without ceasing production, the invention is not limited to riser installations where production is not terminated during the installation process. Accordingly, the invention is therefore to be limited only by the scope of the appended claims.