You are an expert at summarizing long articles. Proceed to summarize the following text:

You are an expert at summarizing long articles. Proceed to summarize the following text: 
CROSS-REFERENCE TO RELATED APPLICATIONS 
     Not Applicable. 
     STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
     Not Applicable. 
     BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     The present invention generally relates to systems and methods for the economical management of hydrocarbon reserves located beneath the ocean floor. More particularly, the present invention relates to a general service vessel adapted to perform all well servicing operations and a floating buoy connected to a composite riser extending to one or more subsea well heads. In a different aspect, the present invention relates to methods for servicing deepwater hydrocarbon fields. 
     2. Description of the Related Art 
     Programs for recovering hydrocarbon reserves from beneath the ocean floor are now commonplace. Like their land-based counterparts, an offshore oilfield may have one or more wells extending into a subterranean formation. Additional equipment and facilities, however, are required to conduct offshore well operations because these wells are beneath hundreds or perhaps thousand of feet of water. A typical prior art offshore drilling and production system suitable for recovering subsea hydrocarbon reservoirs in an ocean environment is illustrated in FIG.  1 . 
     Generally, a conventional offshore drilling and production system includes an operations facility  10  at the ocean&#39;s surface  12  and production equipment  14  located at the mudline  16  on the ocean floor. In a deepwater field, i.e., where the water is too deep to establish a foundation on the ocean floor for a platform, a floating facility  10 , such as a floating rig or semi-submersible vessel, is used to conduct drilling and intervention operations. Equipment at the mudline  16  can include a subsea wellhead system  18  for supporting concentric tubular pipe strings, such as casing and tubing  22 , within a subsea wellhead  24  with the casing  20  and tubing extending into the well bore  26 . A steel marine riser  28  extends from to the subsea wellhead  24  to the floating platform  10 . 
     In prior art systems, the floating platform  10  is towed to a location generally above a subsea field. Thereafter, the floating platform is used as a base to drill, complete, produce and possibly workover one or more wells. Typically, the floating platform remains at this location for the duration of the productive life of the subsea field. This floating platform continues to be used for later well servicing operations, such as well stimulation, intervention, workover and drilling of lateral bores. Floating platforms are generally massive structures that are designed to withstand decades of service in a harsh ocean environment. Often, these floating platforms must meet rigid safety codes imposed by the controlling governmental authority. Thus, as is well known, it is not uncommon for floating platforms to cost upwards of one billion dollars to construct and bring into service. 
     Because of the enormous capital cost associated with a floating platform, well owners must be selective in planning and developing deepwater fields. Often, only those fields that have the potential to produce hydrocarbons in sufficient quantity to offset this capital outlay can be targeted for exploitation. This substantial capital outlay not only reduces the number of eligible fields, but also reduces the profitability of each field ultimately selected. 
     As is also well known, well operators typically optimize the floating platform to perform particular well operations such as drilling and logging efforts associated with the early phases of well construction and completion. After one or more well bores are drilled and completed, the general configuration of the floating platform remains largely unchanged even though later completion, intervention, and workover operations for the wells may be more easily performed by a different configuration. 
     These prior art well construction and management systems have several drawbacks. For example, because each deepwater field must be individually capable of hydrocarbon production rates sufficient to support at least one dedicated floating platform, many fields, incapable of meeting this threshold profitability requirement, are left undeveloped. Additionally, platforms are usually designed for well construction, a phase taking up only a handful of years in the production life of the well that may last for decades. Thus, for much of the service life of a well, these expensive platforms are less than optimal for well production, workover, intervention and other servicing operations. For example, the lifting and handling equipment and layout of a floating platform may be well suited to drill, case and cement a well bore, but ill suited to carry out frac or stimulation operations or specialized drilling operations. 
     Another drawback is that well intervention and servicing operations can be performed only after personnel, equipment, and material have been transported to the floating platform. The preparations for initiating these operations often includes contacting a land-based supply center, ordering the needed equipment and materials, having these items packed and shipped to the well site, unpacking these items at the offshore well site, and stowing these items until they are needed. Thus, the logistics for well servicing operations on a distant offshore floating platform are complex and require an additional expense. 
     The present invention overcomes the deficiencies of the prior art. 
     BRIEF SUMMARY OF THE INVENTION 
     The present invention optimizes the configuration of the support structures used in each phase of the hydrocarbon recovery process, including well construction, production, intervention and work over. A exemplary deepwater field may include one or more wells having a wellhead and a well telemetry system that receives electrical signals from sensors and equipment in the well. A preferred embodiment of the present invention features a riser, a floating buoy and a service vessel. 
     The riser is formed of fatigue-resistant composite material and preferably includes embedded wiring that connects with the well telemetry system. The riser has a first end connected to a wellhead and a second end connected to the buoy. The buoy has a floating or semi-submersible hull that includes a hatch covering a moonpool. The riser passes through the moonpool and connects to the hull generally below the buoy hatch. In the preferred embodiment, the buoy includes telecommunication hardware and computer systems in communication with the well telemetry system via the riser embedded wiring. The service vessel has a bay in which the buoy docks during servicing operations. The service vessel is preferably a self-contained facility having all the personnel, equipment and materials necessary to carry out any number of well servicing operations. Service vessel personnel deploy the equipment and material into the riser via the buoy hatch. 
     A preferred method of the present invention includes towing a floating drilling rig buoy into a deepwater field to support initial well construction activity. After a well has been drilled and mudline equipment, such as a wellhead and the like, has been installed, the floating drilling rig platform is towed away to support well operations elsewhere. In its place, the floating buoy is stationed at the water&#39;s surface generally above the wellhead. The well environment can be remotely monitored using the buoy communication system. When desired, the service vessel is dispatched to the deepwater field to perform one or more servicing operations. The service vessel docks with the buoy and draws the buoy into the bay of the vessel. Thereafter, service personnel deploy the necessary equipment and material into the riser via the buoy hatch. Once servicing operations are complete, the service vessel casts off the buoy and sails to the next buoy or field. 
     Thus, the present invention presents a number of advantages over the prior art. For example, a deepwater field no longer requires a dedicated floating rig; thus, the floating drilling rig can be utilized for a number of offshore oilfields saving cost. Moreover, because the buoy is mechanically and structurally less complex than the floating rig, expenditures on upkeep and maintenance are minimized. Furthermore, because the buoy is much less expensive than a floating rig, the financial loss of a buoy due to weather or accident is not as severe. Even further, the self-contained service vessel eliminates the need to pack, unpack, ship, and stow equipment and material. 
     Other objects and advantages will be apparent from the following description and claims. 
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS 
     For a more detailed description of the preferred embodiment of the present invention, reference will now be made to the accompanying drawings, wherein: 
     FIG. 1 illustrates a side-view of a prior art offshore platform in a deepwater environment; 
     FIG. 2 illustrates side-view of a preferred embodiment of a well management and completion system; 
     FIG. 3A illustrates a side-view a preferred embodiment of a riser connection; 
     FIG. 3B illustrates a side-view of an exemplary slip joint for a riser connection; 
     FIG. 3C illustrates a cross-sectional view of a preferred embodiment of a riser and production tubing; 
     FIG. 3D illustrates a cross-sectional view of a riser and production tubing and their respective embedded wires; 
     FIG. 4A illustrates a plan view of a preferred embodiment of a buoy; 
     FIG. 4B illustrates a side view of a preferred embodiment of a buoy; 
     FIG. 5A illustrates a plan view of a buoy, in phantom, moored to a preferred bay in a service vessel; and 
     FIG. 5B illustrates a side view of a buoy moored to a service vessel having hydraulic arms engaging the buoy. 
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT 
     The systems and methods of the present invention enable the efficient and economical management of deepwater oilfields throughout the life of the underlying hydrocarbon reservoirs  34 . Referring now to FIG. 2, there is shown a field management and completion system (hereinafter “management system”)  30  deployed in a deepwater field  32  for producing hydrocarbons from reservoirs  34  through a well  36  at the mudline  16 . Well  36  can include a wellhead  38  that is used to support casing and tubing, collectively referred to  10  with numeral  40 , in a wellbore  42 . For simplicity, structures such as production trees, underground piping, and subsea storage tanks are not shown as their use and placement would be apparent to one of ordinary skill in the art. A preferred management system implemented in this exemplary environment includes a riser  50 , a buoy  80  floating on the ocean surface and a service vessel  100 . 
     Riser  50  provides a conduit for guiding well equipment, such as bottomhole assemblies, and a work string from the water surface to well head  38 . Additionally, in instances where a drill or work string (not shown) disposed within riser  50  conveys fluids, such as drilling mud, into wellbore  42 , those fluids can return to the surface via the annular space between the inner drill or work string and outer riser  50 . Moreover, riser  50  may be used to bring produced formation fluids to the ocean surface. The aforementioned purposes as well as the design of marine risers are well known in the art. Accordingly, the present discussion is directed to advantageous features of riser  50  as utilized in a preferred embodiment of the present invention. 
     Riser  50  is preferably tubular and includes a surface end  52 , a medial span  54  and a subsea end  56 . Surface end  52  connects to buoy  80  and subsea end  56  connects to wellhead  38 . Both connections are preferably watertight and also include an emergency quick disconnect feature in the event that either of the connections must be severed. Such connections are well known in the art and will not be described in detail. 
     Riser  50  is also preferably formed mostly of composite material. As can be appreciated, buoy  80  will rise and fall cyclically due to ocean waves (heave seas). Because riser  50  is connected to buoy  80 , riser  50  will encounter cyclical tension as buoy  80  rises and falls with the seas. While cyclical tension can quickly lead to fatigue failure in metal, composite materials are largely immune to the stresses imposed by cyclical tension. The use of composite materials for tubulars utilized in hydrocarbon recovery applications is discussed in co-pending U.S. application Ser. No. 09/081,961, titled “Well System,” filed on May 20, 1998, which is hereby incorporated by reference for all purposes. It should be understood, however, that other materials providing similar resistance to fatigue failure may also be used. Utilizing fatigue resistant materials, such as composites, extends the service life of riser—as compared to a metal riser—and thereby enables long term planning for well intervention, completion, and construction activities. 
     Riser  50  may be a single continuous tubular or a series of joint segments of tubulars. A single continuous riser eliminates the need to have watertight connections. Making up riser  50  using a plurality of tubular segments allows these segments to be fabricated in more manageable lengths. However, care must be taken in making up the connections between adjoining segments to prevent sea water incursion into riser  50 . These design considerations as well as other factors inherent to design of risers for deepwater applications will be apparent to one of ordinary skill in the art. For example, the inner diameter of riser  50  must be large enough to accommodate the well tools required for the necessary well operations for well  36 . 
     Referring now to FIG. 3A, there is shown a exemplary connector  58  for making up adjacent composite tubular segments  60  and  62 . Generally, a connector body having electrical conductors and terminals is interposed between segments  60  and  62 . The details of a connector adapted for use with composite coiled tubing segments are disclosed in U.S. application Ser. No. 09/534,685, filed Mar. 24, 2000, which is hereby incorporated herein by reference. An alternate connection is shown in FIG. 3B wherein adjacent tubular segments  70  and  72  are connected using a well known slip joint  73 . 
     Referring now to FIGS. 3C and 3D, riser  50  may be optionally provided with embedded electrical conductors  74 . Similarly, production tubing  75 , or other tubing, disposed within riser  50  may also be provided with embedded electrical conductors  76 . Composite tubulars with embedded conductors are described in U.S. Pat. Nos. 6,004,639, 5,921, 285, and co-pending U.S. application Ser. No. 09/081,961 all hereby incorporated herein by reference in their entirety. As will be described in detail below, these electrical conductors can markedly enhance a well operator&#39;s ability to monitor and manage hydrocarbon production activities. 
     Referring now to FIGS. 4A and B, buoy  80  is preferably a floating or semisubmersible base for accessing the riser surface end  52  (FIG. 2) of riser  50 . Buoy  80  is preferably compact in size and not fitted with provisions or facilities for long term personnel occupation. Nonetheless, as will be apparent, buoy  80  may be as simple or sophisticated as required to efficiently manage a deepwater field. A preferred buoy includes a hull  82  and ballast tanks  84 . 
     Hull  82  is provided with a moonpool  86 , a deck  88 , and a hatch  90 . Deck  88  is preferably a topside reinforced flat surface adapted to safely support well servicing equipment and personnel. Moonpool  86  is an opening in hull  82  that allows access to the water below. Riser surface end  52  (FIG. 2) is received into moonpool  86  and is secured to hull  82  using a flange or collar (not shown). Hatch  90  is disposed generally above moonpool  86  and is formed into deck  88 . Hatch  90  includes a removable lid  91  that, when lifted, permits access to moonpool  86  and riser  50 . When closed, hatch  90  prevents sea water and other contaminants from entering riser  50  below. While platform  80  is shown with one moonpool for simplicity, it should be understood that two or more moonpools can be utilized. Moreover, buoy  80  may be of any geometric shape, including cylindrical, spherical or rectangular. In accordance with well known methods, hull  82  is formed from high-strength corrosion resistant materials in order to withstand an extended service life in a high seas environment. 
     Referring now to FIG. 4B, ballast tanks  84  disposed about the perimeter of hull  82  provide the buoyancy for buoy  80 , and thus the draft of buoy  80 . Preferably, ballast tanks  84  are air tight compartments that can be selectively filled with fluid such as sea water. As is well known in the art, controlled flooding of ballast tanks  84  will tend to submerge buoy  80  and evacuation of ballast tanks  84  will tend to lift buoy  80 . Well known methods and devices such as one-way check valves and high-pressure air may be used to carry out the controlled flooding and evacuation of ballast tanks  84 . It should be understood that ballast tanks  84  are merely one means of providing controlled floatation of buoy  80  and that the present invention is not limited to any particular form of ballast tanks. Indeed, it may be that selective buoyancy is not required and that hull  82  itself may be configured to provide the desired draft. 
     As can be appreciated, buoy  80  is amenable to many design variations that enhance the utility of buoy  80 . For example, hatch  90  may be configured to have a generic engagement face that allows for a quick engagement with the equipment on service vessel  100 . As will be discussed below, buoy  80  docks with service vessel  100  prior to the initiation of well servicing operations. For some operations, service vessel personnel may simply lift the hatch lid  91  and introduce equipment into the moonpool  86  and riser  50 . Other operations may require entering moonpool  86  through a stack that may include snubbers, blowout preventers, an injector, valve assemblies and other such equipment. Thus, hatch  90  is preferably provided with a means for releasably engaging well equipment such as a stack. For example, hatch  90  may include a threaded portion or an annular lip having holes for received fasteners. Alternatively, an annular collar or sliding sleeve (not shown) may be used to lock hatch  90  with well equipment. Moreover, hydraulically actuated locks may be used in lieu of threaded ends or fasteners. It is preferable, however, that the design of hatch  90  be relatively simple in order to minimize the number of parts exposed to the elements, and thus the number of parts susceptible to corrosion and failure. 
     Buoy  80  may also be optionally fitted with cables (not shown) to anchor buoy  80  to the ocean floor. Alternatively, well known dynamic positioning systems may be used to keep buoy  80  generally stationed over the wellhead  38 . Dynamic positioning systems, as well as emergency disconnect features, are discussed in U.S. Pat. Nos. 5,978,739 and 4,205,379, all of which are hereby incorporated by reference. 
     Buoy  80  may also be optionally provided with electronics such as microprocessors and telecommunication systems. Referring now to FIGS. 2 and 3D, microprocessors (not shown) may be linked to the embedded wiring  74  and  76  of riser  50  and production tubing  75 , respectively. Embedded wiring  74  and  76  enable the exchange of electrical signals between the microprocessors and sensors (not shown) and devices along riser  50 , at the subsea well head  38  and within the well  36 . Exemplary signals include those transmitted by sensors that monitor the integrity of riser  50  and subterranean formation fluid pressure. Exemplary signals also include indications of the position of valves, gates, and also the chemical composition of produced fluids. Microprocessors can collect, process and store the data received. Additionally, the data received may be transmitted by a telecommunication systems, such as a satellite transmitter  110 , to a remote station (not shown) for real-time analysis. Electrical power for buoy  80  may be provided by any number of means, such as battery power, or through generators such as those run on tidal motion. Tidal generators are discussed in U.S. Pat. No. 5,872,406, hereby incorporated herein by reference. 
     Referring again to FIG. 2, service vessel  100  is adapted to carry out well servicing operations using buoy  80 . Acid washing, frac operations, sand control, fishing operations, perforations, branch bore drilling operations, formation sampling, well logging are illustrative of the services and operations that may supported by service vessel  100 . Accordingly, the service vessel  100  is preferably fitted with general purpose computers, hydraulic pumps, wireline logging equipment, nitrogen tanks, bottomhole assemblies (BHA) and support equipment, storage tanks, cement, drilling mud, frac fluids, reservoir description equipment and other like systems that enable the evaluation and workover of a deepwater well. Also provided in service vessel are living quarters for personnel, communication systems, electrical power generators and other well know utilities and systems that permit service vessel to make extended service campaigns in deepwater fields. 
     Referring now to FIG. 5A, service vessel  100  includes an aft portion  122  provided with a bay  124  for docking with buoy  80  (shown in phantom). Bay  124  includes a rig deck  126  and a recess  128  having a profile that is generally complementary to the shape of buoy  80 . It is preferred to effectively integrate buoy  80  into service vessel  100  such that platform deck  88  and rig deck  126  are substantially on the same plane and relative motion between buoy  80  and service vessel  100  is minimized. Mooring buoy  80  with service vessel  100  in this manner enables service vessel personnel to safely and quickly introduce vessel-based equipment into riser  50  (not shown) via the hatch  90  in buoy  80 . Referring now to FIG. 5B, alternatively, service vessel  100  may include a pair of hydraulic arms  130  that engage buoy  80  and draw buoy  80  against side of service vessel  100 . 
     The completion system may be deployed, as discussed below, to cost-effectively service deepwater fields. An exemplary use may include a plurality of deepwater subsea wells having been drilled by a floating rig. During this well construction, one or more surface-actuatable flow control devices are installed in the well  36 . Such devices are described in U.S. application Ser. No. 09/396,406, titled “Well Management System,” hereby incorporated herein by reference. Other devices adapted to transmit electrical signals may also have been provided in well  36  to sense well conditions. Well known telemetry systems may be used to process and relay the electrical signals. After this initial well construction phase, the floating rig is towed to another field and, if noncomposite riser was used, then this riser is replaced with a composite riser  50 . The embedded wiring of the composite risers and the embedded wiring of the production tubing (if used) are connected to the well telemetry system. 
     Thereafter, the composite riser  50  for each well  36  is joined to a buoy  80 . Depending on the particular circumstances, one buoy  80  may connect with several composite risers  50  or each riser  50  may have a dedicated buoy  80 . A satellite communication system and microprocessors on board buoy are connected to the embedded wiring of riser  50  and production tubing  75  and thereby establish a surface link with the well telemetry system. As well devices feed signals into the well telemetry system, these signals are received by the satellite communication system and relayed to a remote location. Personnel at the remote location can monitor well conditions via the satellite relay. Additionally, personnel can transmit signals that actuate the well devices also via the satellite system. Thus, well personnel are provided with a two-way real time well monitoring system. Moreover, microprocessors on board buoy  80  can either perform preliminary processing of well device signals or may simply store the data for later retrieval. Therefore, while buoy  80  is simply floating or in a semi-submersible state above the deepwater subsea field, it nonetheless can be fitted with instrumentation that enhances its overall utility. 
     A well operator may decide that production rates for the deepwater field may be improved through intervention or workover. This intervention or workover may include drilling a lateral well from the main well bore  36  in a first zone and a frac operation at a second zone. Service vessel is dispatched to the deepwater field. The service vessel is steered toward the first buoy  80  and is maneuvered such that the bay  124  is oriented toward the buoy  80 . Grappling hooks can then be cast and tethered to the buoy  80 . Buoy ballast tanks  84  may be either flooded or evacuated in order to generally align buoy deck  88  to service deck  126  of the vessel  100 . Once buoy  80  is generally aligned with bay  124 , the buoy  80  is drawn in, docked and moored to the vessel  100 . To access the riser  50 , the hatch lid  91  is removed from the buoy opening and an adapter is secured onto the moonpool  86 . For an exemplary drilling operation, a BHA adapted to drill a lateral bore may be run in after equipment such as BOP&#39;s and injector have been installed on buoy  80 . Similarly, coiled tubing handling equipment may also be used to convey frac equipment downhole. Once all the required operations are done, the equipment is extracted from the well  36  and stowed on the service vessel  100 . After the buoy hatch  90  is secured, the buoy  80  is released from the bay  124 . Thereafter, the service vessel  100  moves to the next buoy. 
     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 embodiments described generally utilize a buoy floating at or near the ocean&#39;s surface. However, a buoy may be submerged to a predetermined depth below the ocean surface. Such buoy placement may be preferable in instances where there is a risk that surface vessels may collide with a buoy. Floating and submerged buoys, and connections thereto, are discussed in U.S. Pat. No. 4,650,431, which is hereby incorporated by reference. Accordingly, the embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the system 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 which follow, the scope of which shall include all equivalents of the subject matter of the claims.

Summary:
An offshore field management system which includes a composite riser, a floating buoy and a service vessel. The riser is extended from a subsea well head to the buoy. Conductors, preferably provided in the riser, are connected with a well telemetry system. The buoy has a floating or semi-submersible hull that includes a hatch covering a moonpool for receiving the riser. The buoy preferably includes satellite communication hardware and computer systems in communication with the well telemetry system via riser embedded conductors. The well environment can be remotely monitored using the buoy communication system. Servicing of the oilfield well is accomplished using the service vessel by docking the buoy in a bay formed in the service vessel. The service vessel is preferably a self-contained facility fitted with the equipment and materials necessary to carry out pre-determined well servicing operations. Service vessel personnel deploy the equipment and material into the riser via the buoy hatch after the buoy has been docked in a bay formed in the service vessel.