Patent Application
20110247827
This invention relates generally to offshore drilling operations.
Offshore drilling operations may be implemented with a variety of different platforms which may be secured to the seabed floor. These platforms may be effective at shallower depths. In greater depths, it is generally desirable to use ships or semi-submersible rigs to conduct such deep water drilling operations.
These ships or rigs may be precisely positioned at a desired location so that the drilling equipment may be operated to precisely drill wells at desired locations. The ship or rig may be maintained in position under dynamic positioning, even in extreme seas. As used herein, a “ship” is a floating platform capable of propulsion on its own or by being pushed, pulled, or towed. It includes semi-submersible rigs and self-propelled vessels.
As a result, a number of exploration wells may be drilled, one after another, in a deep water offshore environment, such as the outer continental shelf of the United States, Africa, Asia, or Western Europe. However, the large number of operations must be performed when successfully drilling a number of exploration wells, even in the same area, may be extremely time consuming because of the complexity of deep water operations.
With a conventional ship having a single drilling platform, it is impossible to perform multiple operations in parallel. Thus, the time periods needed to complete each well may be relatively long. Since, generally, these drilling ships are operated on a rental basis, the longer than it takes to drill the well, the more expensive is the resulting well.
So called dual activity drilling ships are known. In these ships, a pair of derricks may be provided on the ship, which provide a structural support for underlying drilling tubulars. The dual derricks may be operated in some degree in parallel. For example, while one operation is occurring on one derrick, another operation may be implemented on another derrick. However, any in case, only one well may be drilled, one of the drilling centers being used for drilling and the other center being used for supporting a single drilling operation.
Referring to
In some embodiments, a main drilling center 14 and a secondary drilling center 12 may be provided. Each of these drilling centers is capable of running risers. In some embodiments, the main drilling center 14 is used for primary drilling operations. In the event of a failure, the main drilling center can be disconnected, the ship can be moved to position the secondary drilling center 12, and risers may be lowered from the secondary drilling center to drill a relief well in association with the failed drilling operation from the main drill center.
Dual drilling activity drilling ships may have a wide variety of applications. For example, in arctic drilling operations, it is generally desired to have a backup drill ship on site. That way, if the primary drill ship runs into a problem, the secondary drill ship can take over. But given the cost of drilling ships, having two ships on site is extremely expensive. In accordance with some embodiments of the present invention, a single drill ship can perform the same capabilities that required two drilling ships in the past. It should be noted that conventional dual activity drill ships cannot drill from two different centers and do not have the capability of supplying risers for marine drilling from two different centers.
In one embodiment, the main and secondary drilling centers may be implemented by hydraulic RAM devices. In other embodiments, derricks or superstructures may be provided. Such derricks or superstructures may provide structural support for the tubulars hung from such derricks.
In contrast, with hydraulic RAM systems, the tubulars may be supported directly on the ship's deck. This avoids the need for expensive, heavy derricks to support the tubulars. However, in some embodiments, even using a hydraulic system, masts, or guides may be provided to guide the tubulars when they are in their uphauled positions.
Thus, depending on the nature of the centers 12 and 14, different tubular storage facilities may be utilized. For example, when a derrick system is utilized, the derricks are of sufficient strength that tubulars may be stored by simply leaning them against the insides of the derricks. In other cases, tubular storage systems, set back envelopes, and racks may be provided to hold the assembled or partially assembled tubulars.
As shown in
For example, a conventional marine drilling riser may have a nominal 21¼ inches inside diameter, while the risers stored in the racks 30 and 32, associated with the secondary drilling center, may be a smaller diameter, such as 13⅝ inch internal diameter, 10,000 psi risers.
While, in
Conventional equipment may be used for advancing, running, withdrawing, lifting, or rotating the tubulars to the seabed and, ultimately, into the seabed floor. In this regard, waste, top drives, sheaves, draw works, rotary tables, traveling blocks, motion compensators, hydraulic RAMS, or any other known equipment may be utilized. The hydraulic RAM may support tubulars on the deck, but derricks may support tubulars from above the deck. The present invention is in no way limited to any particular equipment.
Referring now to
A lower marine riser package (LMRP) 27 is coupled to the blowout preventer 26 to disconnect the upper components from the underlying subsea shutoff assembly (SSA) 27. In one embodiment, the SSA 27 may have controls that are independent from the controls used for the BOP 26. In one embodiment, the subsea shutoff assembly may be 18¾ inch internal diameter, conventional equipment.
Finally, a subsea wellhead 28 may be cemented into the seabed. The wellhead may be an 18¾ inch inside diameter conventional wellhead, in some embodiments.
Thus, the wellhead 28 may be established from the main drilling center 14 and if no problems develop, the secondary drilling center 12 may not be needed. However, in some embodiments, dual activity may be implemented so that some tubulars may be made up in advance from the secondary drilling center 12 to facilitate drilling from the main drilling center 14. In other embodiments, the drilling center 12 is only held for backup in case a failure occurs in connection with the main drilling center 14.
Referring to
The riser tensioners 38 may be permanently installed on the secondary well center 12. An upper blowout preventer 39 may be provided. In one embodiment, the BOP 39 may be a 13⅜ inch inside diameter blowout preventer. The riser 40 may be a smaller diameter riser that is capable of handling 10,000 psi pressure and having an internal diameter of 13⅜ inch in one embodiment. Because it has a smaller diameter, the riser 40 can be more easily carried on the same ship with the riser 24 without overweighting the ship, in some embodiments.
A lower marine riser package (LMRP) 42a is used for disconnecting the riser 40 from the lower blowout preventer 42. In one embodiment, the lower blowout preventer 42 may be a 13⅜ inch diameter conventional blowout preventer. A subsea wellhead 28 with a slim internal diameter may be cemented into the seabed. In one embodiment, it may have an 18¾ inch inside diameter.
One application for the ship 10 may be the situation where there is an initial, uncontrolled flow of hydrocarbons through the main drilling center 14, including a blowout, with the well finally contained by closing in the well at the RAMS on the independently controlled subsea shutoff assembly 27. In this worse case scenario, the riser 24 cannot be released from the blowout preventer 26 due to the total failure of the controls cable and acoustic release device on the blowout preventer 26 and independent release of the LMRP 27a between the BOP 26 and SSA 27. In this situation, it is necessary to control the release of the riser 24 just above the LMRP 26a by activating the mechanical override riser disconnect 25, as indicated in
Thus, as shown in
In some embodiments, the main drilling center and the secondary drilling center may carry 5000 feet of riser at each center. This is sufficient riser length for drilling in many offshore regions, including the arctic, where the maximum depth is about 3500 feet.
References throughout this specification to “one embodiment” or “an embodiment” mean that a particular feature, structure, or characteristic described in connection with the embodiment is included in at least one implementation encompassed within the present invention. Thus, appearances of the phrase “one embodiment” or “in an embodiment” are not necessarily referring to the same embodiment. Furthermore, the particular features, structures, or characteristics may be instituted in other suitable forms other than the particular embodiment illustrated and all such forms may be encompassed within the claims of the present application.
While the present invention has been described with respect to a limited number of embodiments, those skilled in the art will appreciate numerous modifications and variations therefrom. It is intended that the appended claims cover all such modifications and variations as fall within the true spirit and scope of this present invention.
