Patent Publication Number: US-10329852-B2

Title: Offshore well drilling system with nested drilling risers

Description:
BACKGROUND 
     Drilling offshore oil and gas wells includes the use of offshore platforms for the exploitation of undersea petroleum and natural gas deposits. In deep water applications, floating platforms (such as spars, tension leg platforms, extended draft platforms, and semi-submersible platforms) are typically used. One type of offshore platform, a tension leg platform (“TLP”), is a vertically moored floating structure used for offshore oil and gas production. The TLP is permanently moored by groups of tethers, called a tension leg, that eliminate virtually all vertical motion of the TLP. Another type of platform is a spar, which typically consists of a large-diameter, single vertical cylinder extending into the water and supporting a deck. Spars are moored to the seabed like TLPs, but whereas a TLP has vertical tension tethers, a spar has more conventional mooring lines. 
     The offshore platforms typically support risers that extend from one or more wellheads or structures on the seabed to the platform on the sea surface. The risers connect the subsea well with the platform to protect the fluid integrity of the well and to provide a fluid conduit to and from the wellbore. 
     The risers that connect the surface wellhead to the subsea wellhead can be thousands of feet long and extremely heavy. To prevent the risers from buckling under their own weight or placing too much stress on the subsea wellhead, upward tension is applied, or the riser is lifted, to relieve a portion of the weight of the riser. Since offshore platforms are subject to motion due to wind, waves, and currents, the risers must be tensioned so as to permit the platform to move relative to the risers. Accordingly, the tensioning mechanism must exert a substantially continuous tension force to the riser within a well-defined range. 
     An example method of tensioning a riser includes using buoyancy devices to independently support a riser, which allows the platform to move up and down relative to the riser. This isolates the riser from the heave motion of the platform and eliminates any increased riser tension caused by the horizontal offset of the platform in response to the marine environment. This type of riser is referred to as a freestanding riser. 
     Hydro-pneumatic tensioner systems are another example of a riser tensioning mechanism used to support risers. A plurality of active hydraulic cylinders with pneumatic accumulators is connected between the platform and the riser to provide and maintain the necessary riser tension. Platform responses to environmental conditions that cause changes in riser length relative to the platform are compensated by the tensioning cylinders adjusting for the movement. 
     With some floating platforms, the pressure control equipment, such as the blow-out preventer, is dry because it is installed at the surface rather than subsea. However, jurisdiction regulations and other industry practices may require two barriers between the fluids in the wellbore and the sea, a so-called dual barrier requirement. With the production control equipment located at the surface, another system for accomplishing dual barrier protection is needed. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       For a detailed description of the preferred embodiments of the invention, reference will now be made to the accompanying drawings in which: 
         FIG. 1  shows an off-shore sea-based drilling system in accordance with various embodiments; and 
         FIG. 2  shows a riser system including an outer riser with a nested internal riser. 
     
    
    
     DETAILED DESCRIPTION 
     The following discussion is directed to various embodiments of the invention. The drawing figures are not necessarily to scale. Certain features of the embodiments may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in the interest of clarity and conciseness. Although one or more of these embodiments may be preferred, the embodiments disclosed should not be interpreted, or otherwise used, as limiting the scope of the disclosure, including the claims. It is to be fully recognized that the different teachings of the embodiments discussed below may be employed separately or in any suitable combination to produce desired results. In addition, one skilled in the art will understand that the following description has broad application, and the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to intimate that the scope of the disclosure, including the claims, is limited to that embodiment. 
     Certain terms are used throughout the following description and claims to refer to particular features or components. As one skilled in the art will appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name but not function. The drawing figures are not necessarily to scale. Certain features and components herein may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in interest of clarity and conciseness. 
     In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . .” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect connection via other devices, components, and connections. In addition, as used herein, the terms “axial” and “axially” generally mean along or parallel to a central axis (e.g., central axis of a body or a port), while the terms “radial” and “radially” generally mean perpendicular to the central axis. For instance, an axial distance refers to a distance measured along or parallel to the central axis, and a radial distance means a distance measured perpendicular to the central axis. 
     Referring now to  FIG. 1 , a schematic view of an offshore drilling system  10  is shown. The drilling system  10  is a dry BOP system and includes a floating platform  11  equipped with a drilling module  12  that supports a hoist  12 . Drilling of oil and gas wells is carried out by a string of drill pipes connected together by tool joints  14  so as to form a drill string  15  extending subsea from platform  11 . The hoist  12  suspends a kelly  16  used to lower the drill string  15 . Connected to the lower end of the drill string  15  is a drill bit  17 . The bit  17  is rotated by rotating the drill string  15  and/or a downhole motor (e.g., downhole mud motor). Drilling fluid, also referred to as drilling mud, is pumped by mud recirculation equipment  18  (e.g., mud pumps, shakers, etc.) disposed on the platform  11 . The drilling mud is pumped at a relatively high pressure and volume through the drilling kelly  16  and down the drill string  15  to the drill bit  17 . The drilling mud exits the drill bit  17  through nozzles or jets in face of the drill bit  17 . The mud then returns to the platform  11  at the sea surface  21  via an annulus  22  between the drill string  15  and the borehole  23 , through subsea wellhead  19  at the sea floor  24 , and up an annulus  25  between the drill string  15  and a riser system  26  extending through the sea  27  from the subsea wellhead  19  to the platform  11 . At the sea surface  21 , the drilling mud is cleaned and then recirculated by the recirculation equipment  18 . The drilling mud is used to cool the drill bit  17 , to carry cuttings from the base of the borehole to the platform  11 , and to balance the hydrostatic pressure in the rock formations. Pressure control equipment such as blow-out preventer (“BOP”)  20  is located on the floating platform  11  and connected to the riser system  26 , making the system a dry BOP system because there is no subsea BOP located at the subsea wellhead  19 . 
     As shown in  FIG. 2 , with the pressure control equipment at the platform  11 , the dual barrier requirement may be met by the riser system  26  including a freestanding external riser  30  with a nested internal riser  32 . As shown, the external riser  30  surrounds at least a portion of the internal riser  32 . The riser system  26  is shown broken up to be able to include detail on specific sections but it should be appreciated that the riser system  26  maintains fluid integrity from the subsea wellhead  19  to the platform  11 . 
     A nested riser system requires both the external riser  30  and the internal riser  32  to be held in tension to prevent buckling. Complications may occur in high temperature, deep water environments because different thermal expansion is realized by the external riser  30  and the internal riser  32  due to different temperature exposures—higher temperature drilling fluid versus seawater. To accommodate different tensioning requirements, independent tension devices are provided to tension the external riser  30  and the internal riser  32  at least somewhat or completely independently. 
     In this embodiment, the external riser  30  is attached at its lower end to the subsea wellhead  19  (shown in  FIG. 1 ) using an appropriate connection. For example, the external riser  30  may include a wellhead connector  34  with an integral stress joint as shown. As an example, the wellhead connector  34  may be an external tie back connector. Alternatively, the stress joint may be separate from the wellhead connector  34 . The external riser  30  may or may not include other specific riser joints, such as riser joints  36  with strakes or fairings and splash zone joints  38 . The upper end of the external riser  30  terminates in a diverter  40  that directs fluid to a solids management system of the drilling module  12  as indicated by the arrow  42  for recirculation into the drilling system. 
     Also included on the external riser  30  is a tension device  44  in the form of at least one buoyancy system that provides tension on the external riser  30  independent of the platform  11 . The external riser tension device  44  may be any suitable configuration for providing buoyancy such as air cans, balloons, or foam sections, or any combination of these configurations. The external riser tension device  44  may also be located at another location along the external riser  30  than shown in  FIG. 2 . The external riser tension device  44  may also be located along or at more than one location along the external riser  30 . The external riser tension device  44  provides the external riser  30  with its own tension and thus enables the external riser  30  to be a freestanding riser. 
     In this embodiment, the internal riser  32  is nested within the external riser  30  and is attached at its lower end to the subsea wellhead  19  ( FIG. 1 ) or to a casing or casing hanger landed in the subsea wellhead  19  using an appropriate connection. For example, the internal riser  32  may stab into a connection in the wellhead  19  with or without rotating to lock in place. The internal riser  32  may also connect inside the external tieback connector  34 . The internal riser  32  extends to the platform  11  within the external riser  30 , forming an annulus between the external riser  30  and the internal riser  32 . The internal riser  32  extends past the upper end of the external riser  30  to the platform  11 . On the platform  11 , the pressure control equipment (not shown in  FIG. 2 ) is connected to the top of the internal riser  32  to provide well pressure integrity. An internal riser tension device  46  is attached to the internal riser  32  at the portion of the internal riser  32  extending from the upper end of the external riser  30 . The internal riser tension device  46  is supported on a tensioner deck  48  of the platform  11  and dynamically tensions the internal riser  32 . This allows the tension device  46  to adjust for the movement of the platform  11  while maintaining the internal riser  32  under proper tension. The internal riser tension device  46  may be any appropriate system, such as a hydro-pneumatic tensioner system as shown. 
     Other appropriate equipment for installation or removal of the external riser  30  and the internal riser  32 , such as a riser running tool  50  and spider  52  may also be located on the platform  11 . 
     The riser system  26  is installed by first running the internal riser  32  and locking its lower end in place. Then, the external riser  30  is installed surrounding the internal riser  32 . In use, the internal riser  32  provides a return path to the platform  11  for the drilling fluid. Typically, the external riser  30  is filled with seawater unless drilling or other fluids enter the external riser  30 . 
     In this embodiment, when installed, the internal riser  32  is free to move within the external riser  30  and is tensioned completely independently of the external riser  30 . Alternatively, the internal riser  32  may be placed in tension and locked to the external riser  30  such that the external riser tension device  44  supports some of the needed tension for the internal riser  32 . Also alternatively, the external riser  30  may be tensioned and then locked to the internal riser  32  such that the internal riser tension device  46  supports at least some of the needed tension for the external riser  30 . 
     Although the present invention has been described with respect to specific details, it is not intended that such details should be regarded as limitations on the scope of the invention, except to the extent that they are included in the accompanying claims.