Patent Grant
8960307
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 legs or tendons, that eliminate virtually all vertical motion of the TLP due to wind, waves, and currents. The tendons are maintained in tension at all times by ensuring net positive TLP buoyancy under all environmental conditions. The tendons stiffly restrain the TLP against vertical offset, essentially preventing heave, pitch, and roll, yet they compliantly restrain the TLP against lateral offset, allowing limited surge, sway, and yaw. 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.
These offshore platforms typically support risers that extend from one or more wellheads or structures on the seabed to a surface wellhead on 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 to compensate for the motion of the platform.
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 and a drilling wellhead, is dry because it is installed at the surface rather than subsea. In some such cases, a nested, dual-riser system may be required where one riser is installed inside another riser. The riser or one of the two risers connecting the subsea wellhead with the surface wellhead may also be held in tension by pulling the riser in tension and then landing the riser in the surface wellhead supported by the platform. The outside of the riser is sealed against the inner diameter of the wellhead using an annular seal. These annular seals however are subject to relative motion between the riser and the wellhead due to the movement of the platform as well as the movement of the equipment above the wellhead. This relative movement presents a potential source of wear on the seal and the seal surfaces.
For a detailed description of the preferred embodiments of the invention, reference will now be made to the accompanying drawings in which:
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
Below the wellhead system 30, the riser system 32 extends below the sea level 15 and connects with the subsea well. The riser system 32 maintains fluid integrity from a subsea wellhead (not shown) to the surface wellhead system 30 and is attached at its lower end to the subsea wellhead using an appropriate connection. For example, the riser system 32 may include a wellhead connector with an integral stress joint. As an example, the wellhead connector may be an external tie back connector. Alternatively, the stress joint may be separate from the wellhead connector. Appropriate equipment for installation or removal of the riser system 32, such as a riser running tool and spider, may also be located on the platform. The riser system 32 shown is a dual-barrier, nested riser system 32 including an internal riser installed inside an external riser, the external riser terminating at the wellhead system 30 with the internal riser extending into the wellhead system 30. However, it should be appreciated that the riser system 32 need not be a dual-barrier system and may instead include only a single riser.
Drilling of the subsea well is carried out by a string of drill pipes connected together by tool joints so as to form a drill string extending subsea from the platform. Connected to the lower end of the drill string is a drill bit. The bit is rotated by rotating the drill string and/or a downhole motor (e.g., downhole mud motor). Drilling fluid, also referred to as drilling mud, is pumped by mud recirculation equipment (e.g., mud pumps, shakers, etc.) disposed on the platform. The drilling mud is pumped at a relatively high pressure and volume down the drill string to the drill bit. The drilling mud exits the drill bit through nozzles or jets in face of the drill bit. The mud then returns to the platform at the sea surface via an annulus between the drill string and the borehole, through the subsea wellhead at the sea floor, and up an annulus between the drill string and the riser system 32. At the platform, the drilling mud is cleaned and then recirculated by the recirculation equipment. The drilling mud is used to cool the drill bit, to carry cuttings from the base of the borehole to the platform, and to balance the hydrostatic pressure in the rock formations. Pressure control equipment such as the BOP unit 26 is located on the floating platform and connected to the riser system 32.
As shown, the riser system 32 includes a tension joint 34, a transition joint 36, and the external riser string 38 that extends to the subsea wellhead. To maintain the riser system 32 under appropriate tension, a riser tension system 40 is attached to the tension joint 34 by a tensioner ring 42 on the external riser. The riser tension system 40 is supported on the tensioner deck 13 of the platform and dynamically tensions the riser system 32. This allows the tension system 40 to adjust for the movement of the platform while maintaining the external riser under proper tension. The riser tension system 40 may be any appropriate system, such as a hydro-pneumatic tensioner system as shown. Also, it should be appreciated that in a single riser system, the external riser and associated tensioning equipment may not be necessary. Also, although not shown, the gasket seal discussed above may also be used with a production riser terminating in a surface wellhead/production tree.
As more clearly shown in
The wellhead 50 includes a load shoulder 51 for landing the internal riser 80 in tension. Before the remaining portions of the wellhead system 30 are installed onto the wellhead 50, the internal riser 80 is pulled into tension to prevent buckling. The final height of the internal riser 80 relative to the wellhead 50 once the riser 80 is pulled into tension may vary depending on the dimensions and design of the overall drilling system 10. To accommodate for different heights, the internal riser 80 includes annular grooves 82 spaced along the length of a portion of the internal riser 80. The landing shoulder 51 and the grooves 82 cooperate by accepting a load ring that allows the internal riser 80 to land on the load shoulder 51 and remain in tension. The load shoulder 51 supports the load of the internal riser 80 in tension and transfers that load to the platform. As shown, the load ring may be in multiple sections, such as a split ring and false bowl. The load ring may be designed for other configurations as well.
Also included in the wellhead 50 is at least one port 55 extending through the wall of the wellhead from the bore inside the wellhead 50 to outside the wellhead 50. The port(s) 55 allow access to the annulus between the wellhead 50 and the internal riser 80 and, in a dual-barrier riser system as shown, the annulus between the inner and external riser. The port(s) 55 may be angled as shown to allow insertion of a fluid line into the annulus for injecting gas to evacuate liquid in the annulus or other annulus control operations.
With the riser 80 in tension and supported by the wellhead 50, the spool 52 is then installed by placing it over the riser 80 and connecting it with the wellhead 50 using connectors 53. The connectors 53 may be designed to run in on threads such as FASTLOCK™ connectors by Cameron International Corporation or may be designed as any other suitable type connector.
On top of the spool 52, one or more spacer spools 56 are installed to accommodate the final height of the internal riser 80. As shown in
On top of the spacer spool(s) 56 is a collet 60 and a flange assembly 64, which are more clearly shown in
As shown more clearly in the insert
As shown in
As shown most clearly in
On top of the flange sleeve 70 is an upper flange, such as a API flange, for connection with the BOP spool 28 and the BOP unit 26.
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.
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| Entry |
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| International Search Report and Written Opinion for PCT Application No. PCT/US2013/029095 filed Mar. 5, 2013. |
| Number | Date | Country | |
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| 20130228340 A1 | Sep 2013 | US |
| Number | Date | Country | |
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| 61606807 | Mar 2012 | US |
