Abstract:
An offshore riserless drilling system drills a subsea borehole from a platform and through a cased borehole. The system comprises a lightweight drill string suspending a bottomhole assembly and extending from the platform downwardly through a depth of water into the cased borehole; a first limiter limiting the range of motion of the drill string adjacent the platform; and a second limiter limiting the range of motion of the drill string adjacent the cased borehole. The preferred methods include lowering a bottomhole assembly suspended on a lightweight drill string from a platform through a depth of water; limiting the bend radius of the drill string adjacent the platform; guiding the bottomhole assembly into a cased borehole; limiting the bend radius of the drill string adjacent the cased borehole; maintaining the bottomhole assembly in the cased borehole, and drilling the subsea borehole.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
   The present application is related to application Ser. No. 10/265,028, filed Oct. 4, 2002 and entitled Methods and Apparatus for Open Hole Drilling, hereby incorporated herein by reference in its entirety. 
   STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
   Not Applicable. 
   BACKGROUND OF THE INVENTION 
   1. Field of the Invention 
   The present invention relates generally to methods and apparatus for performing riserless drilling from an offshore platform, and more particularly, to methods and apparatus for performing riserless drilling using a lightweight drill string, and still more particularly, to methods and apparatus for drilling an offshore well from a platform using a lightweight, small diameter, continuous drill string thereby enabling the use of comparatively smaller diameter pipe components and a smaller platform versus conventional methods. 
   2. Description of the Related Art 
   Offshore hydrocarbon drilling and producing operations are typically conducted from a drilling rig located either on a bottom-founded offshore platform or on a floating platform. A bottom-founded platform extends from the seafloor upwardly to a deck located above the surface of the water, and at least a portion of the weight of the platform is supported by the seafloor. In contrast, a floating platform is a ship, vessel, or other structure, such as a tension-leg platform, for example, in which the weight of the platform is supported by water buoyancy. 
   In recent years, exploration and production of offshore crude oil and natural gas reservoirs has expanded into ever-deeper waters. Successful drilling operations have been conducted in deep waters of at least 3,000 feet deep, and ultra-deep waters ranging from 5,500 to 10,000 feet deep. With increasing water depths, drilling operations conducted from moored or dynamically positioned floating platforms have become more prevalent since economic and engineering considerations militate against the use of bottom-founded drilling platforms commonly used in shallow water. 
   Regardless of whether a bottom-founded or floating platform is used, conventional methods for drilling an offshore well are similar. In such operations, the platform supports a drilling rig and associated equipment, and must include adequate deck space for pipe storage and handling. The platform is positioned near the wellsite, and a drill string, typically formed of jointed steel pipe that is threaded together one joint at a time, conveys a bottom-hole drilling assembly (BHA) from the platform to the seafloor. A drill bit, disposed at the terminal end of the BHA, drills the well. 
   Riserless Drilling 
   When drilling from a floating platform, the upper portion of the well is drilled by riserless drilling in that no conduit is provided for the returns to flow to the platform. Therefore, in riserless drilling the returns, i.e. the drilling fluid, cuttings, and well fluids, are discharged onto the seafloor and are not conveyed to the surface. To drill the initial upper portion of the well, the drill string typically extends unsupported through the water to the seafloor without a riser. In more detail, first an outer casing, known as “structural casing”, typically having a diameter of 30-inches to 36-inches, is installed in the uppermost section of the well, with a low-pressure wellhead housing connected thereto. In soft formations, the structural casing is typically jetted into place. In this process, an assembly is lowered to the seafloor on a conventional drill string. The assembly includes the structural casing, and typically, a BHA with drill collars, a downhole motor, and a drill bit. The bit is positioned just below the bottom end of the structural casing, and is sized to drill a borehole with a slightly smaller diameter than the diameter of the casing. As the borehole is drilled, the structural casing moves downwardly with the BHA. The weight of the structural casing and BHA drives the casing into the sediments. The structural casing, in its final position, generally extends downwardly to a depth of 150 to 400 feet, depending upon the formation conditions and the final well design. After the structural casing is in place, it is released from the drill string and BHA. The drill string and BHA are then tripped back to the platform, or are, in some cases, lowered to drill below the structural casing. 
   In more competent formations, the structural casing is similar, but it is installed in a two-step process. First, a borehole larger than the structural casing is drilled. Then the structural casing is run into the borehole and cemented into place. Typically, the low-pressure wellhead housing is connected to the upper end of the structural casing and installed at the same time, such that the structural casing extends below the seafloor with the low-pressure wellhead housing above the seafloor. 
   Once the structural casing and the low-pressure wellhead housing are installed, the BHA on the drill string drills downwardly below the structural casing to drill a new borehole section using riserless drilling for an intermediate casing, known as “conductor casing,” which is typically 20-inches in diameter. Thus, the structural casing guides the BHA as it begins to drill the conductor casing interval. During riserless drilling, returns of the drilling fluid and cuttings are discharged onto the seafloor. 
   After the borehole section for the conductor casing is drilled, the BHA is tripped to the surface. Then conductor casing, with a high-pressure wellhead housing connected to its upper end, and a float valve disposed in its lower end, is run into the drilled conductor borehole section extending below the structural casing. The conductor casing is cemented into place in a well known manner, with the float valve preventing cement from flowing upwardly into the conductor casing after cement placement. The conductor casing generally extends downwardly to a depth of 1,000 to 3,000 feet below the seafloor, depending on the formation conditions and the final well design. The high-pressure wellhead housing engages the low-pressure wellhead housing to form the subsea wellhead, thereby completing the riserless portion of the drilling operations. A subsea blowout preventer (BOP) stack is typically conveyed down to the seafloor by a riser and latched onto the subsea wellhead housing. The riser is thereby installed with its lower end connected to the subsea wellhead via the BOP stack and the riser extending to the platform at the surface. Subsequent casing strings are hung, and well operations are conducted through the subsea wellhead. 
   Riserless drilling, as described above for drilling the conductor casing borehole, is conventionally performed using a drill string formed of steel pipe joints having a size and weight sufficient to withstand the lateral forces imposed by water currents. However, this conventional method of riserless drilling has a number of disadvantages, especially when drilling from a floating platform in deep or ultra-deep waters. 
   Drilling with a Riser 
   Once the well reaches a certain depth, further drilling requires the use of a weighted drilling fluid to maintain control of downhole pressures, and such drilling fluids are costly enough to warrant returning the drilling fluid to the platform for cleaning so that the same drilling fluid may be recirculated for further drilling. Thus, after the riserless drilling portion of the well has been drilled and cased, a low-pressure riser, formed by joining sections of casing or pipe that is typically 21-inches in diameter, is deployed between the floating platform and the wellhead equipment. The riser is provided to guide the drill string to the wellhead equipment for conducting further well drilling operations, and to provide a conduit for returning drilling fluid from the well to the floating platform. 
   Once the riser is in place, the drill string and BHA are lowered through the riser, the subsea wellhead, and the conductor casing to drill through the float valve into the seafloor to form another borehole section for another string of casing. The next casing, known as “surface casing,” which is typically 13⅜ to 16 inches in diameter, is lowered into the drilled borehole and cemented into place via conventional procedures. The surface casing generally extends to a depth of 2,500 to 5,000 feet below the seafloor, depending on the formation characteristics and final well design. Subsequent, smaller diameter, intermediate casing strings may be installed below the surface casing. 
   This conventional method of drilling with a riser from a platform has a number of disadvantages, especially when drilling from a floating platform in deep or ultra-deep waters. First, the required size and capacity of the platform is largely based on the depth of water, and the corresponding amount of pipe required to drill the well. The larger the pipe, and the more pipe required to form the riser, the greater the weight and space requirements of the drilling rig and floating platform. To handle the weight of a large and long drill string, and a large and long riser, the floating platform must be equipped with a conventional drilling rig and must have significant deck space for storing and handling the large amount of pipe required for the drilling operation. 
   Thus, as water depth increases, larger floating platforms are required for larger drilling rigs to handle and support the added weight of the pipe due to the greater depth and to store the additional pipe, thereby significantly increasing the costs of drilling as water depth increases. Further, tripping into and out of the well with jointed pipe is very time-consuming since each joint of pipe must be threaded and/or unthreaded to the pipe string extending through the water and into the well. 
   Various improvements may be made to overcome the deficiencies of conventional drilling operations. It would be advantageous to reduce the size of the platform, particularly floating platforms required for deep water. One way to enable the use of a smaller platform would be to reduce the capacity requirement of the hoisting system, which would allow reduction of the drilling rig size, or would allow replacement of the drilling rig with a smaller capacity hoisting system. Further, the diameter and therefore the weight of the pipe, such as drill pipe, casing, and risers, could be reduced, thereby no longer requiring a large drilling rig to handle the pipe, and no longer requiring large storage space on the platform for the pipe. To achieve these objectives, it would be preferred to eliminate large risers and to use smaller risers. This will reduce the required drilling rig size and the amount of storage space required. When the riser diameter is reduced to the preferred smaller diameter, a conventionally sized drill string is too large to extend through the riser. For this reason, a smaller diameter drill string must be used when drilling through the preferred smaller diameter riser. A reduction in drill string diameter typically results in a proportional reduction in the weight of the drill string. Thus, in order to maximize efficiency, it would be preferable to use the same, smaller diameter, lighter drill string for conducting the riserless drilling operations described above. In addition to enabling the use of a smaller riser, the use of a smaller, lighter drill string is preferable because its lighter weight directly reduces the vessel size requirement. 
   For these reasons, it would be preferable to use a lighter weight drill string. It would be more preferable to use a non-jointed, continuous lighter weight drill string such as coiled tubing stored on a reel, thereby reducing the deck space required to store the drill string. Further, because a coiled tubing drill string is a continuous, single length of tubing that may be continuously fed from the reel into the water and down into the well, the time required to connect and disconnect the joints of a conventional drill string is eliminated, thereby significantly reducing the overall time required to conduct drilling operations. It would be still more preferable to use a non-metal coiled tubing drill string, such as the composite coiled tubing disclosed in U.S. Pat. No. 6,296,066 to Terry et al., hereby incorporated herein by reference for all purposes. Composite coiled tubing is preferable to metal pipe or metal coiled tubing because it weighs substantially less and is substantially less subject to fatigue-inducing stress variations due to trips into and out of the well and movement of the floating platform. 
   Drill string weight may be reduced by reducing the wall thickness of the drill string, or by altering the material that forms the drill string, such as by using a lightweight metal like titanium, or by using a lightweight composite material. A composite coiled tubing drill string may be formed of helically wound or braided fiber reinforced thermoplastic or fiber reinforced thermosetting polymer or epoxy, for example. It should be appreciated that one or more of these concepts may be combined to reduce drill string weight, resulting in a lightweight drill string. However, as the drill string is made lighter, it becomes more susceptible to the effects of water currents. The lighter the drill string, the more severe the effects. Because water currents vary with depth and with time, and because the variability of the currents increases with increasing water depth, it is difficult to precisely predict deepwater currents and thus to design for their adverse effects. In particular, water currents have various impacts on a lightweight drill string and BHA during riserless drilling. As used herein, a lightweight drill string is defined as a drill string, which is lighter than that used in conventional drilling, and which requires alternative systems and methods to conduct riserless drilling due to factors associated with its light weight, such as its response to water currents. 
   Conventional riserless drilling systems and methods cannot be used with a lightweight drill string due to the conventional systems&#39; inability to counteract the effects of the water currents on the lightweight drillstring. Because the drill string is laterally constrained at the platform and at the point of entry into the borehole at the seafloor, the drill string will bow as the water currents impose lateral forces against it. As the weight of the drill string is reduced, it becomes less resistant to these undesirable effects of the water current, which can lead to unacceptably large bowing deflections and stresses in the drill string. As water depth increases, the bowing effect of the drill string increases because there is a greater length of the drill string upon which the water currents act. The bowing of the drill string exerts an upward force on the BHA, tending to pull the BHA out of the borehole. This upward force reduces weight-on-bit (WOB) and possibly lifts the bit off bottom, thereby preventing successful drilling. 
   Furthermore, as the weight of the drill strength is reduced and the water depth increases, the tendency of the drill string to kink increases, particularly at the floating platform and at the seafloor where the drill string is laterally constrained. Thus, if the drill string bends too sharply, it will kink, and ultimately fail. Therefore, to achieve successful riserless drilling with a lightweight drill string, a minimum bend radius must be maintained to prevent the drill string from ultimately failing. Devices used to restrict bending, such as conventional bend limiters, are commonly used to limit the range of motion of flexible risers to prevent overbending that could lead to kinking and failing. Thus, a bend limiter is any device that restricts bending of a tube and includes bellmouths and bend restrictors. A bellmouth is a flared, funnel-shaped device. The radius of curvature of the flare is designed based on the minimum allowable bend radius of a tube disposed through the bellmouth. A conventional bend restrictor is a mechanical device comprising a number of interlocking half-ring segments, each of which provides a mechanical stop to resist further bending once a minimum radius of curvature is reached. These bend limiter devices are further defined and described in the American Petroleum Institute (API), Specification 17J and Recommended Practice (RP) 17B, Sections 4.5 and 7.6, entitled “Ancillary Components.” 
   Therefore, it would be advantageous to provide methods and apparatus to counteract the effects of water currents such that successful riserless drilling of the conductor casing borehole can be achieved using a lightweight drill string. 
   The present invention overcomes the deficiencies of the prior art. 
   SUMMARY OF THE INVENTION 
   The present invention features improved methods and apparatus for the riserless drilling of a subsea wellbore. The preferred embodiments comprise a system for riserless drilling of a subsea borehole from a platform and through a cased borehole, the system comprising a lightweight drill string suspending a bottomhole assembly and extending from the platform downwardly through a depth of water into the cased borehole; a first limiter limiting the range of motion of the drill string adjacent the platform; and a second limiter limiting the range of motion of the drill string adjacent the cased borehole. In one embodiment, the bottomhole assembly includes a tension/compression sensor, and the system includes an injector that adjusts tension in the drill string in response to measurements made by the tension/compression sensor. 
   The preferred embodiments further comprise a method of drilling a subsea borehole from a platform and through a cased borehole, the method comprising lowering a bottomhole assembly suspended on a lightweight drill string from the platform through a depth of water; limiting the bend radius of the drill string adjacent the platform; guiding the bottomhole assembly into the cased borehole; limiting the bend radius of the drill string adjacent the cased borehole; maintaining the bottomhole assembly in the cased borehole; and drilling the subsea borehole. In one embodiment, the method further comprises measuring tension in the drill string; and adjusting the tension in the drill string at the platform in response to the measured tension. In another embodiment, the method further comprises measuring an entry angle of the drill string adjacent the cased borehole; and adjusting the position of the platform in response to the entry angle measurement. In another embodiment, the method further comprises adjusting the tension in the drill string in response to the entry angle measurement. 
   Thus, the preferred embodiments of the present invention comprise a combination of features and advantages that overcome various problems of prior methods and apparatus. The various characteristics described above, as well as other features, will be readily apparent to those skilled in the art upon reading the following detailed description of the preferred embodiments of the invention, and by referring to the accompanying drawings. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
     For a more detailed description of the preferred embodiments of the present invention, reference will now be made to the accompanying drawings, in which like elements have been given like numerals, wherein: 
       FIG. 1  is a schematic elevational view of one embodiment of an offshore drilling system comprising a floating vessel with a crane and a coiled tubing system situated over a subsea wellsite; 
       FIG. 2  is a schematic elevational view of the drilling system of  FIG. 1  depicting a coiled tubing drill string extending from the floating vessel through the water to the seafloor, and a BHA disposed on the end of the drill string drilling a borehole for a conductor casing; 
       FIG. 2A  is a schematic elevational view of the drilling system of  FIG. 2  depicting an inclination measurement means and a remotely operated vehicle; 
       FIG. 3  is an enlarged view of the BHA of  FIG. 2 ; 
       FIG. 4  is an enlarged schematic view of the drilling operation of  FIG. 2 , depicting the coiled tubing drill string extending through a moonpool in the floating vessel; 
       FIG. 4A  is an enlarged schematic view of the drilling operation of  FIG. 4 , depicting a segmented bend restricter with a tube therethrough; 
       FIG. 4B  is an enlarged schematic view of the drilling operation of  FIG. 4 , depicting a segmented bend restricter with rollers; 
       FIG. 4C  is an enlarged schematic view of the drilling operation of  FIG. 4 , depicting a sheave engaging the coiled tubing drill string; and 
       FIG. 4D  is an enlarged schematic view of the drilling operation of  FIG. 4 , depicting a pivotal injector. 
   

   DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS 
   The present invention is susceptible to embodiments of different forms. There are shown in the drawings, and herein will be described in detail, specific embodiments of the present invention with the understanding that the present disclosure is to be considered only an exemplification of the principles of the invention, and is not intended to limit the invention to that illustrated and described. 
   The apparatus and methods of the present invention comprise offshore drilling from a platform using a lightweight drill string suspending a BHA. Various embodiments of the present invention provide a number of different configurations of the drill string, the BHA, the type of platform from which drilling operations occur (i.e. bottom-founded or floating), the depth of the water, and the sizes of pipe components, such as risers and casings. It should be appreciated that the embodiments of the present invention, therefore, provide a plurality of methods for offshore drilling from a platform. Thus, it is to be filly recognized that the different teachings of the embodiments discussed herein may be employed separately or in any suitable combination to produce desired results. In particular, the present system may be used in practically any type of offshore drilling operation utilizing a lightweight drill string. 
   Referring initially to  FIG. 1 , there is shown a schematic elevational view of one exemplary operating environment for the preferred embodiments of the present invention in a deepwater application. Although the present invention is applicable in any water depth, the deeper the water, the greater the advantages. A preferred embodiment of a drilling system  175 , best shown in  FIG. 2 , includes a light weight drill string  135 , such as metal or composite coiled tubing, and a bottom hole assembly  400  for drilling a borehole. An offshore platform  100  comprises a floating vessel  110  and a coiled tubing system  120  having a power supply  122 , a surface processor  124 , and a coiled tubing spool  126 . An injector  128  advances the coiled tubing  135  from the spool  126  through the water  140  towards the seafloor  150 , or retracts the coiled tubing  135  from the water  140  to be reeled back onto the spool  126 , or holds the coiled tubing  135  stationary. Further, the injector  128  applies to the coiled tubing  135  the forces necessary for these operations. In preferred embodiments, the floating vessel  110  is not equipped with a conventional sized drilling rig because the weight of the required drilling equipment and pipe can be supported by a lower capacity hoisting system. Preferably, the required hoisting system on the floating platform  110  comprises a crane  190 , or a smaller than conventional derrick (not shown), or a specially designed tower system (not shown). 
   In  FIG. 1 , the offshore floating platform  100  is shown situated adjacent a subsea wellsite  160  in which structural casing  170 , a low-pressure wellhead housing  180 , and a bellmouth  185  have previously been installed. Due to the preferably smaller diameter, light weight drill string  135 , the structural casing  170  is preferably smaller in diameter than structural casing for conventional wells, and most preferably, the structural casing  170  has a diameter less than 30-inches to 36-inches, such as, for example, 7⅝-inches. 
   Referring now to  FIG. 2 , the preferred embodiments of the present invention comprise apparatus and methods for conducting riserless drilling with a lightweight drill string  135 . According to conventional drilling methods, riserless drilling is performed to drill a borehole for conductor casing below the structural casing  170  using a heavy drill string with a BHA disposed on its lower end. Riserless drilling is successful when using conventional drill pipe because it is large and heavy enough to withstand the lateral forces imposed by water currents  230 . In contrast, the preferred drilling system  175  of the present invention utilizes a drill string  135  formed of a lightweight tubing, such as coiled tubing. The lightweight drill string  135  may be formed of composite coiled tubing, or metal coiled tubing, or any lightweight tubing. If coiled tubing is used, composite is preferred over metal because of the desirable characteristics of composite, including: lighter weight, superior fatigue resistance, and the ability to contain data and power transmission conductors within the tubing wall. The lighter the weight of the drill string  135 , however, the greater the effect of the water current  230  on the drill string  135 . At some point, the drill string  135  becomes too light, such that the current  230  adversely impacts the drill string  135  and prevents successful conventional riserless drilling. 
   In one preferred embodiment, the coiled tubing  135  is formed of a composite material, such as the coiled tubing disclosed in U.S. Pat. No. 6,296,066 to Terry et al., hereby incorporated herein for all purposes, which is lighter than conventional drill pipe, and has an outer diameter (OD), such as for example 3⅛ inches, which is smaller than conventional drill pipe. By using the lighter weight, smaller diameter coiled tubing  135 , which is stored on a spool  126 , a smaller diameter and therefore lighter weight riser pipe can be used, which significantly reduces the load capacity requirements and space requirements for the platform  100 . Accordingly, a smaller than conventional floating platform  100  can be utilized. When drilling the well, prior to drilling the deeper interval of the well using a drilling riser, a shallower interval is drilled riserless. By utilizing the same lightweight drill string  135  for the riserless interval as will be used in the subsequent interval drilled using a riser, the platform capacity requirements and space requirements can be further reduced, while also improving operational efficiency by minimizing drill string transfers and handling. 
   Drill string  135 , preferably formed of composite coiled tubing, extends from the floating platform  100 , through the water  140 , and into the bellmouth  185  at the seafloor  150 . The upper end of the drill string  135  passes through and is supported by a rigid extension  210  and a bend limiter, such as a bellmouth  220  or a bend restrictor (not shown), as it exits the injector  128  and extends through the moonpool  115  of the floating platform  100 . A BHA  400  is disposed on the lower end of the drill string  135  to drill a borehole  155  below the structural casing  170  for the conductor casing. 
     FIG. 3  provides, by way of example, an enlarged view of a preferred BHA  400  of  FIG. 2 . Preferably the BHA  400  is suspended on the end of the composite coiled tubing drill string  135  and a bit is disposed at the lowermost end of the BHA  400 . In one embodiment, the bit may be a conventional drill bit. Alternatively, to perform slimhole drilling, the bit may be a bi-center bit  410  capable of passing through a smaller diameter structural casing  170  to drill a borehole  155  that is larger than the diameter of the conductor casing, thereby providing adequate annular space for cementing the conductor casing into place. Alternately, a conventional drill bit and underreamer combination, or a conventional drill bit and winged reamer combination, may be provided instead of a bi-center bit  410  to perform the same slimhole drilling function. 
   The BHA  400  preferably further comprises a downhole motor  415  for rotating the bi-center bit  410 , upper and lower circulation subs  425 ,  435 , a tractor  430  with borehole retention devices  432 ,  434 , and upper and lower tension/compression subs  455 ,  465 . One exemplary tractor  430  is described in U.S. Pat. No. 6,003,606, hereby incorporated herein by reference for all purposes. The BHA  400  may also include tools for steering the BHA  400 , such as a three dimensional steering tool  420 , and various detectors and sensors, such as, for example, a resistivity sensor  440 , a gamma ray sensor  445 , a directional sensor  450 , a pressure/temperature sub  460 , a casing collar locator  470 , and/or a voltage-converter sub  475 . The BHA  400  may further include various disconnects, such as an electrical disconnect  480  and a ball drop disconnect  485 . Accordingly,  FIG. 3  depicts one representative grouping of components that may comprise the BHA  400 . However, one of ordinary skill in the art will readily appreciate that the BHA  400  may be configured to include a variety of different components, and may include additional or fewer components than those depicted in  FIG. 3 , depending on the well plan. 
   Referring again to  FIG. 2 , if no water currents  230  were acting on the drill string  135 , and if the floating vessel  110  was stationary, then the drill string  135  would extend vertically downwardly from the floating vessel  110  in a straight line into the bellmouth  185 . However, the water currents  230  impose lateral forces on the lightweight drill string  135 , thereby causing the drill string  135  to be deflected horizontally in the direction of the water currents  230  as the drill string  135  extends from the floating vessel  110  towards the bellmouth  185 . Therefore, the BHA  400  is preferably physically guided, such as by remotely operated vehicles (ROVs)  320  shown in  FIG. 2A , through the water  140  to enter the bellmouth  185 , thereby allowing for the floating vessel  110  to be positioned directly over the wellsite  160 . Remote cameras may also be provided to help direct the BHA  400  into the bellmouth  185 . Due to the water currents  230 , if the BHA  400  is not physically guided through the water  140 , the floating vessel  110  must be horizontally displaced from the wellsite  160  so that the drill string  135  extends at an angle through the water  140  to reach the bellmouth  185 . Dynamic positioning devices enable accurate placement of the floating platform  100  that is horizontally offset from the wellsite  160 . The objective is to locate the floating platform  100  to achieve the best performance by the drilling system  175 . 
   For the case where the BHA  400  is just above the seafloor  150  at the wellsite  160  and is not physically guided through the water  140 , the horizontal displacement of the floating vessel  110  from the wellsite  160 , for a given current profile, is approximately inversely proportional to the weight of the drill string  135 . For example, if the drill string  135  is formed of steel tubing that weighs approximately 24 pounds per foot and the vessel  110  must be horizontally displaced from the wellsite  160  by approximately 100 feet, then the horizontal displacement of the vessel  110  would be approximately 800 feet for a drill string  135  formed of composite coiled tubing that weighs approximately 3 pounds per foot. 
   Similarly, weight also affects the variation in tension on the drill string  135  as a result of the water currents  230 . For example, if the tension in a drill string  135  formed of steel tubing varies from approximately 20 kips at the seafloor  150  to approximately 230 kips at the floating vessel  110  when the BHA  400  is just entering the bellmouth  185 , then the tension in a composite coiled tubing drill string  135  under the same conditions would vary from approximately 5 kips to 18 kips. Thus, a composite coiled tubing drill string  135  has a relatively small tension variation from the seafloor  150  to the floating vessel  110  due to its comparatively lighter weight. This small tension variation is well within the capabilities of preferred embodiments of the present invention, which utilize a composite coiled tubing drill string  135  capable of withstanding a tension up to 40 kips, with a working tension of 30 kips. 
   The water currents  230  have various adverse impacts on the lightweight drill string  135  and BHA  400  during riserless drilling. First, as the water currents  230  impose lateral forces against the drill string  135  causing it to bow as shown in  FIG. 2 , an upward force is imposed on the BHA  400 , tending to pull the BHA  400  out of the borehole. This upward force negatively impacts drilling progress because the weight-on-bit is reduced, and the bi-center bit  410  on the lower end of the BHA  400  may no longer remain on the bottom  157  of the borehole  155  being drilled. Further, the lightweight drill string  135  is inherently more susceptible to kinking at the floating vessel  110  and at the seafloor  150 . In particular, there will be a tendency for the lightweight drill string  135  to kink below the coiled tubing injector  128  and at the point of entry at the seafloor  150 . Additionally, as a result of the forces imposed by the water currents  230 , the lightweight drill string  135  may experience vortex induced vibrations, which have the potential to damage the drill string  135 . Each of these effects can be managed by maintaining the BHA  400  in the borehole  155  and ensuring that proper tension is maintained in the drill string  135 . 
   In particular, to counteract the upward force on the BHA  400 , the preferred embodiments of the present invention includes maintenance means for ensuring that the BHA  400  is maintained or anchored in the borehole  155 . One preferred maintenance means is a tractor  430  that engages the borehole wall and advances the BHA  400  downwardly in the borehole  155 . Another preferred means of maintaining the BHA  400  in the borehole  155  is to provide a BHA  400  with a predetermined weight such that the water currents  230  can not lift the BHA  400  out of the borehole  155 . The weight must be adequate to result in tension in the drill string  135  while maintaining a suitably constant weight on bit. Either of these means would be utilized in combination with tension/compression sensor subs  455 ,  465  and the coiled tubing injector  128 , as further described below. 
   With respect to drilling with a tractor  430 , the borehole retention devices  432 ,  434  grippingly engage and maintain continuous contact with the borehole wall  153  to anchor the BHA  400 . Once drilling has begun, it is desirable to keep the drill string  135  in tension between the tractor  430  and the injector  128  to prevent the drill string  135  from excessively bowing or drifting in the currents  230 . The more tension on the drill string  135  (i.e. the tighter the drill string  135 ), the less quantity of drill string  135  is spooled out between the floating vessel  110  and the seafloor  150 . Thus, greater tension provides less length of drill string  135  exposed to the water currents  230 , thereby limiting drag. Further, greater tension limits bowing of the drill string  135 , and limits the bend radius of the drill string  135  at the floating vessel  110  and at the seafloor  150 . In addition, if vortex induced vibrations are experienced, the drill string tension may be increased or decreased in order to minimize the vibrations. Thus, it is desirable to maintain tension along the entire drill string  135 , which is axially controlled at the floating vessel  110  via the injector  128  and at the seafloor  150  via the maintenance means on the BHA  400 . 
   However, a compression force is required on the bi-center bit  410  to drill the borehole  155 . The compression is generated by the force or thrust applied by the tractor  430 . Thus, in operation, the lower tension/compression sensor  455  is used to optimize drilling by facilitating correction of the weight on bi-center bit  410 , whereas the upper tension/compression sensor  465  is monitored for changes in tension on the drill string  135  imposed by variations in the water current  230 . These sensors  455 ,  465  are preferably connected to conductors (not shown) disposed within the wall of the composite coiled tubing drill string  135  such that tension and compression data is sent real-time to the surface processor  124  via a signal  250 , shown in dashed lines. Alternatively, a drill string  135  formed of lightweight metal tubing with an electric line extending through the flowbore of the metal tubing could be utilized. Other methods of transmitting data are via a mud pulse telemetry or electro-magnetic telemetry signal  275 , for example, shown in dashed lines. Thus, when a change in the water currents  230  causes a variation in the tension on the drill string  135 , the tension/compression sensors  455 ,  465  will immediately sense the change and provide the tension/compression data to the surface processor  124 , preferably via signal  250 . 
   The tension of the drill string  135  is controlled at the floating vessel  110  by the tubing injector  128 , which acts as a lifting/tension device. Other types of tension apparatus are also available as is well known in the art. Thus, the top of the drill string  135  may be moved up or down by the injector  128  or other tension apparatus to maintain a suitable level of tension on the drill string  135  as conditions change. Preferably, the coiled tubing injector  128  is automatically controlled by a signal  260  from the surface processor  124  that responds to the tension/compression data signals  250  or  275 . Alternatively, the data can be used by an operator to control the level of tension in the drill string  135 . Thus, regardless of the telemetry method, the speed of data transmission must be fast enough to enable compensation in the tension of the drill string  135  so that drilling progresses. 
   The water currents  230  also cause a bending effect on the drill string  135 . If the coiled tubing drill string  135  bends too sharply, then it will kink or collapse. Thus, a minimum bending radius must be maintained to prevent the drill string  135  from buckling or kinking, which would occur prior to the drill string  135  yielding. To counteract the tendency for the lightweight drill string  135  to kink below the coiled tubing injector  128  and at the point of entry at the seafloor  150 , various devices are preferably provided as shown in  FIGS. 2 and 4 . In particular, a bend limiter, such as a bellmouth  185 , is provided subsea to prevent the drill string  135  from bending beyond its allowable minimum bend radius as it enters the structural casing  170 . At the floating vessel  110 , a variety of means may be used to maintain the minimum bend radius of the drill string  135 . For example, a rigid extension  210  and a bend limiter, such as a bellmouth  220 , may be provided to restrict the drill string  135  from bending beyond its allowable minimum bend radius as it exits the injector  128 . 
   Referring to  FIG. 4 , a moonpool  115  is disposed through the floating vessel  110 . The injector  128  is disposed above the inlet to the moonpool  115 , and the coiled tubing drill string  135  extends downwardly from the injector  128  through the moonpool  115 . At some point near the water surface  145 , the lightweight drill string  135  passes through the bellmouth  220 , which may be internally coated with a low friction coating to reduce the sliding friction on the drill string  135  as it is raised and lowered through the bellmouth  200 . In another embodiment, the bellmouth  220  may be replaced with a bend restrictor  330  shown in  FIG. 4A , which is preferably a segmented device. One type of bend restrictor  330  comprises segments  332  of interlocking half rings. Each segment of the bend restrictor is designed to bend only to a predetermined angle. Each segment will lock up, i.e. prevent further bending, when the bend in the segment reaches a predetermined angle, such that the bend restrictor establishes a minimum bend radius. The coiled tubing drill string  135  extends through the bend restrictor  330 , which is preferably lined internally with a flexible tube  334  to provide a smooth, low friction surface against which the coiled tubing  135  slides. Accordingly, the half-ring segments of the bend restrictor  330  fit around the flexible tube  334  to establish a minimum bend radius of the flexible tube  334  through which the drill string  135  extends. Another type of bend restrictor is a segmented sleeve  340  shown in  FIG. 4B  with rollers  342  mounted internally of each segment  344 . The drill string  135  extends through the sleeve  340  and is engaged by the rollers  342 . Each segment  344  of the sleeve  340  is designed to bend only to a predetermined angle, thereby establishing a minimum bend radius for the drill string  135 . 
   The bellmouth  220  or bend restrictor  330 ,  340  must extend into the moonpool  115  a pre-determined distance to avoid engagement between the drill string  135  and the floating platform  100  adjacent the lower end of the moonpool  115 . Thus, a rigid extension or tubular  210  extends from the bottom of the injector  128  to a point within the moonpool  115  such that when the bellmouth  220  or bend restrictor is mounted below the extension  210 , the lightweight drill string  135  will extend below the moonpool  115  and will not engage the vessel  110  as it extends through the water surface  145  and downwardly to the seafloor  150 . Although conventional bend limiters have been depicted and described, one of ordinary skill in the art will readily appreciate that various other devices may be provided instead of bend limiters to maintain a minimum bend radius. For example, the drill string  135  could extend around a pivotal sheave  330  shown in  FIG. 4C . 
   Alternatively, due to the use of a lightweight drill string  135 , it would be possible to maintain a minimum bend radius of the drill string  135  by providing pivotal support means  350  shown in  FIG. 4D  for the coiled tubing injector  128  instead of bend limiters and other such devices. The pivotal support means  350  would enable the injector  128  itself to pivot at an angle from vertical as necessary to prevent overbending of the drill string  135 . For example, the pivotal support means could comprise a gimbaled table flexibly attached to the platform  100 , such as by non-linear springs. One such gimbaled table is depicted and described in U.S. Pat. No. 6,431,284 to Finn et al., hereby incorporated herein by reference. However, the gimbaled table exemplifies only one possible pivotal support means, and is not intended to be limiting. As one of ordinary skill in the art will understand, a number of alternate means may be utilized for pivotally supporting the injector  128 . Accordingly, at the platform  100 , a variety of means may be employed to prevent overbending of the drill string  135 . 
   At the seafloor  150 , it is preferable to include an inclination measurement means  300  shown in  FIG. 2A  to monitor the angle from vertical that the drill string  135  enters at the structural casing  170 , to ensure that the drill string  135  is not kinking. The inclination measurement means  300  would preferably measure the angle at the bellmouth  185 . However, a bend restrictor may also be added subsea such that a gauge or sensor could measure the angle of the bend restrictor. Alternatively, a bend restrictor could be used instead of a bellmouth  185  at the seafloor  150 . An inclination sensor may be mounted at the upper end of the bend restrictor to measure the angle of the bend restrictor segments corresponding to the angle of the drill string  135  exiting the bend restrictor. Another inclination measurement means  300  may include photocells arranged around the mouth or the opening of the bellmouth  185 . Still another inclination measurement means  300  might include an acoustic device to determine the angle of the drill string  135 . It also may be possible to determine the direction that the drill string  135  extends from the bellmouth  185 . Regardless of how the angle of the drill string  135  is measured, the data is transmitted at  310  to the floating platform  100 . Then the injector  128  modifies the tension in the drill string  135  to change the angle of entry, or the platform  100  may be moved to change the angle of entry, if necessary. Thus, the bend radius or angle of entry of the drill string  135  is monitored such that real-time adjustments can be made to correct any problems detected. 
   Once the borehole  155  has been drilled, the drill string  135  and BHA  400  are tripped to the floating platform  100 , and the remainder of the drilling operation is conducted in a conventional manner. Thus, the conductor casing is set and cemented in the borehole  155 , and a subsea blowout preventer is installed. Then a riser is run down for the drilling of subsequent boreholes and to provide a means for taking returns to the floating platform  100 . 
   However, in preferred embodiments, the remainder of the drilling operation is conducted utilizing the same drill string  135  and BHA  400  as used during riserless drilling, and preferably slimhole drilling is performed. Accordingly, because the preferred embodiments comprise using a lightweight drill string  135  and structural casing  170  that are preferably smaller diameter components, the same lightweight drill string  135  can be used with riser pipe and subsequent casing strings that are also preferably smaller diameter components, further reducing the size requirements of the floating platform  100 . If the riser pipe is a high-pressure riser, a surface BOP at the platform may be utilized instead of utilizing a subsea BOP stack at the seafloor. 
   Accordingly, the preferred embodiments of the present invention provide improved methods and apparatus for conducting drilling operations from a bottom-founded or floating platform using a lightweight drill string in any water depth, and especially for conducting drilling operations in deep or ultra-deep water from a floating platform  100 . In particular, a lightweight and preferably continuous drill string  135  is utilized for riserless drilling such that the required size and capacity of the platform is significantly reduced. The lightweight drill string is laterally constrained at each end, while also being axially controlled, and the drill string is unsupported by a riser as it extends through the water during drilling. The tension in the drill string is monitored, preferably via sensors in the BHA, and the drill string tension is adjusted at the platform. In preferred embodiments, the same lightweight drill string and BHA are used for the entire drilling operation, thereby enabling the use of smaller diameter riser pipe and casings, such as structural casing  170 , to reduce the required size and capacity of the platform. As an example, these efficiencies are expected to reduce the live load requirement of the floating vessel by 50 percent or more when conducting drilling operations in 10,000 feet of water. 
   While preferred embodiments of this invention have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit or teaching of this invention. For example, the present invention is not limited to drilling in deep water from a floating platform, and it is equally applicable to riserless drilling with a lightweight drill string from a bottom-founded platform in shallow water. Further, the dimensions provided are exemplary only and not limiting, such that the present invention is not limited to drilling slim boreholes, and it is equally applicable to riserless drilling for any size borehole and any size conductor casing. As another example, lightweight jointed drill pipe may be utilized instead of coiled tubing to make up the drill string. Thus, the embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the methods and apparatus are possible and are within the scope of the invention. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims.