WO2011067353A2 - Assembly and method for subsea well drilling and intervention - Google Patents
Assembly and method for subsea well drilling and intervention Download PDFInfo
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- WO2011067353A2 WO2011067353A2 PCT/EP2010/068771 EP2010068771W WO2011067353A2 WO 2011067353 A2 WO2011067353 A2 WO 2011067353A2 EP 2010068771 W EP2010068771 W EP 2010068771W WO 2011067353 A2 WO2011067353 A2 WO 2011067353A2
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- Prior art keywords
- assembly
- located beneath
- riser string
- lbop
- providing
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Classifications
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- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/02—Surface sealing or packing
- E21B33/03—Well heads; Setting-up thereof
- E21B33/035—Well heads; Setting-up thereof specially adapted for underwater installations
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
- E21B17/01—Risers
- E21B17/017—Bend restrictors for limiting stress on risers
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B19/00—Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrick; Apparatus for feeding the rods or cables
- E21B19/002—Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrick; Apparatus for feeding the rods or cables specially adapted for underwater drilling
- E21B19/004—Handling rods, casings, tubes or the like outside the borehole, e.g. in the derrick; Apparatus for feeding the rods or cables specially adapted for underwater drilling supporting a riser from a drilling or production platform
Definitions
- the invention relates to subsea assemblies used in offshore deepwater operations and the production of hydrocarbons.
- floatable support structures have become larger due to the amount of pipe required to drill at such depths.
- the physical size and height of the drilling derrick or other type of hoisting tower of the ship also limits the locations in which it can travel. For example, large drillships may not be able to travel through such waterways as the Suez or Panama Canals due to height constraints across the canals, and likewise may not be able to travel under the bridge in the Bosphorous (mouth of the Black sea) due to the height of their drilling derricks or hoisting tower on the drillship. It is often necessary to travel around such waterways, which greatly increases the travel costs and time.
- MWD Managed Pressure Drilling
- UPD Underbalanced Drilling
- Limited MPD is also performed where a rotating control head (“RCH”) is installed on to a collapsed telescopic joint; however, costly pressurized mud cap drilling technology is required.
- RCH rotating control head
- the floatable structure includes a dual BOP system comprising an upper blow out preventer ("UBOP") and a lower blow out preventer (“LBOP").
- UOP upper blow out preventer
- LBOP lower blow out preventer
- the UBOP is located between a drill floor and above a riser string, while the LBOP is located below the riser string and above a wellhead.
- the riser utilizes a slim design adapted to withstand a high pressure environment.
- the UBOP, LBOP, and riser combine to form a riser system that has the same high pressure integrity from top to bottom, essentially forming an extension of the wellbore.
- an expandable intermediate liner may be tripped down the riser and installed below a slim surface casing, thus saving a casing string size.
- the present invention allows the well to be designed to effectively reduce the number of casing strings by using MPD or UBD drilling technology.
- FIG. 1 is a diagram of a dual BOP system made in accordance with an exemplary embodiment of the present invention.
- FIG. 2 is a diagram of an expandable casing string as run in accordance with an exemplary methodology of the present invention.
- a floatable structure includes a vessel (not shown), such as a drill ship, and a dual BOP/riser system 5 coupled beneath the floor of the vessel.
- Dual BOP/riser system 5 comprises an upper blow out preventer (“UBOP") 10 and a lower blow out preventer (“LBOP") 20.
- the drill ship may be a DrillSLIMTM or SLIMDRILLTM drill ship designed by Stena Drilling Ltd. of Scotland, U.K., which is the Assignee of the present invention.
- the UBOP 10 is located below drill floor 35 and above riser string 40.
- LBOP 20 is located below riser string 40 and above a wellhead (not shown).
- a bag preventer (not shown) may also be located above UBOP 10.
- Extending below drill floor 35 is a diverter assembly 12 having a flex joint 14 coupled beneath it. Diverter assembly 12 may include, for example, 16 inch overboard lines to the port and starboard sides of the ship.
- Flex joint 14 connects to slip joint assembly 16, which can be a triple barrel slip joint assembly having a 50ft stroke.
- Assembly 18 is coupled beneath slip joint assembly 16 and includes a high pressure spacer joint with a load ring and blafro flange.
- This exemplary embodiment also includes a rotating control head (“RCH”) in assembly 18, which is installed above the high pressure spacer joint to enable MPD or UBD.
- RCH rotating control head
- a flexible line 21 is tied into an independent choke manifold 23, which may be located in the substructure of the drill ship, to facilitate the application of MPD or UBD drilling technology and is totally independent from the main rig kill and choke lines.
- UBOP 10 is coupled beneath assembly 18 and includes at least three sets of rams, 25a, 25b, 25c, wherein at least two of the three sets of rams comprise variable bore rams ("VBR") rated at 10 psi.
- VBR variable bore rams
- rams 25a, 25b, and 25c include one 9% inch casing ram and two 23 ⁇ 4-5.5 inch VBR.
- UBOP 10 can also include, for example, a 13 /s inch annular preventer rated at 5K psi.
- Upper stress joint 22 is coupled beneath UBOP 10 and connects to riser string 40, and may be a 133 ⁇ 4 inch triple barreled telescopic joint with up to a 50ft stroke.
- UBOP 10 also includes a choke/kill manifold with inlets from below the rotating elements of the RCH and an independent choke manifold with self-adjusting chokes for MPD and UBD.
- Riser string 40 may be a 13% inch inner diameter ("ID"), high pressure 10K riser, having kill and choke lines from the seabed to the surface.
- ID 13% inch inner diameter
- Conventional drilling marine risers (generally utilized with a subsea BOP on the seabed) are designed to control drilling fluid flow and have sufficient burst pressure strength at the seabed to hold the pressure differential between the heaviest drilling mud inside the riser against seawater pressure outside the riser.
- a high pressure riser can also withstand these physical properties, but it can also be sealed up at the top of the riser and be subjected to up to 10,000 psi additional pressure in the event that an activity may require the riser to be pressured.
- Riser string 40 may also include a design that includes a 10,000 psi burst rating, and also be able to comply with stringent dimensional requirements for handling and storage on the deck of the drill ship to keep the ship size to a minimum.
- the riser can be approximately 7,500 ft of 13% inch ID x 10 (120 joints) with two choke/kill lines which would allow for high pressure pumping outside riser string 40.
- the joints can be 65 ft long with high strength connectors, weigh +/-21T (dry), and have a 45 inch outer diameter ("OD”) with buoyancy.
- Riser string 40 is kept in tension by a substructure mounted tensioner system, rated to 2.4 million lbs with 14.0 ppg (1.68 specific gravity (SG)) fluid inside the riser.
- the riser system also has 10,000 psi kill and choke line (generally associated with subsea BOP control systems) to facilitate conventional seabed well control techniques or to monitor and control pressures below a sealed LBOP if the riser system is used as a lubricator while using MPD or UBD drilling technologies.
- 10,000 psi kill and choke line generally associated with subsea BOP control systems
- lower stress joint 24 is coupled beneath riser string 40 and connects to high pressure ball valve 26 to contain the mud when emergency disconnect is initiated.
- LBOP 20 includes at least three sets of rams 30a, 30b, 30c, which can include, for example, one pipe ram to hang-off the drill pipe and two blind shear rams with fail safe closed connections to monitor pressure build up in the event the well is closed in on the blind rams.
- LBOP also includes an emergency disconnect and a wellhead connector.
- LBOP 20 may be comprised of super shear blind/shear rams in order to shear and seal on the 9.5/8 inch casing and heavier drill pipe.
- LBOP 20 and the lower riser package enable the well to be closed in at seabed level, and the high pressure riser string 40 to be disconnected.
- LBOP 20 and the lower riser package are controlled by a multiplex system with acoustic backup including: duplicate umbilical control reels for approximately 7500 ft water depth and a modular emergency subsea accumulator pack (set on seabed) that is connected using a remotely operated vehicle (ROV).
- UBOP 10 can be controlled by a pilot hydraulic control system.
- the controls for both UBOP 10 and LBOP 20 can be adjacent to each other on the same panels.
- the hydraulic disconnect package or lower riser package can include an inverted connector with acoustic control back up.
- riser string 40 and UBOP 10 act as an extension of the wellbore for drilling operations facilitating MPD and UBD operations.
- the riser system between UBOP 10 and LBOP 20 holds the same pressure as UBOP 10 and LBOP 20, thereby creating a deepwater drilling BOP and riser system that has the same high pressure integrity from top to bottom.
- riser string 40 can act as a very long lubricator for pressurized well interventions by also using LBOP 20 and UBOP 10 together with an RCH for MPD, UBD, and TTRD well intervention applications.
- the present invention provides the ability to drill a slimmed down (top hole) well design where an expandable intermediate liner is installed below slim surface casing, thus saving a casing string size.
- An exemplary method of the present invention will now be described. Expandable liners, as understood in the art, are utilized in this exemplary methodology.
- the well of FIG. 2 is located at a water depth of approximately 7,500 ft, having a total depth ("TD") of approximately 22,500 ft.
- TD total depth
- Surface casing 42 and intermediate casing 44 are run and cemented prior to running the 13.5/8 inch x 10,000 psi dual BOP/riser system 5.
- intermediate casing 44 will be one API size smaller than the typical casing run before the placing of a BOP in a conventional well design.
- intermediate casing 44 may be a 13 3/8 inch casing string, while such casing would typically be a 20 inch casing string in a conventional well design.
- dual BOP/riser system 5 is run. Thereafter, if required, the next hole section is drilled with a bi-centered bit or under-reamed to 16 inches/17 1 ⁇ 2 inches. Then, solid expandable liner 48 is run and expanded to seal at the junction of shoe 46.
- expandable liner 48 is an 11 3 ⁇ 4 inch OD solid expandable liner that when expanded has the same drift diameter as the previously set 13 3/8 inch casing. This now makes the casing shoe depth of the present invention equivalent to that of a conventional casing design.
- the expansion system and method in order to secure the 121 ⁇ 4 inch drift for expanded casing/liner, the expansion system and method must be taken into account to determine the necessary surface casing size, as would be understood by one skilled in the art having the benefit of this disclosure.
- the well can then be drilled with a 121 ⁇ 4 inch bit for a 93 ⁇ 4 inch casing string 50 or a 9% inch liner string (subject to well design criteria) at approximately 17,500 ft, for example, and finished using a 81 ⁇ 2 inch hole and 7 inch production liner 52 at approximately 22,500 ft, for example.
- the sizes and methods used herein are exemplary in nature as would be understood by one skilled in the art having the benefit of this disclosure.
- the systems and methods described herein can be used in water depths less than or greater than approximately 7,500 ft. Accordingly, the present invention allows the well to be designed to effectively reduce the number of casing strings by using MPD or UBD drilling technology to continually monitor subsurface pore pressures and set casing in the appropriate subsurface pressure regime.
- the drill ship or drilling semi-submersible with identical drilling technology functionality utilized with the present invention will now be described.
- the drill ship may include various types of equipment useful in deep water drilling.
- an exemplary drill ship is the 145-8 x 29-3 lm DrillSLIMTM.
- DrillSLIMTM or similar designs, allows efficient movement around the world by the most direct routes (e.g., through the Suez and Panama Canals and under the Bosporus Bridge), which substantially reduces transit times and costs.
- the ship's hoisting tower arrangement mounted to a deck of the drill ship is specifically designed to telescope inward to ensure when collapsed the top of the hoist sheaves can pass under the bridges on the Panama and Suez canals and under the Bosphorous bridge into the Black Sea while the drill ship is in transit draft.
- the hoisting tower would include sufficient racking capacity for a full drill string for water depths of at least about approximately 7,500 ft. As an example using approximately 7,500 ft water depth as a basis, the heaviest load of 355 tons (T) occurs when the approximately 7,500 ft of riser, two sets of BOP's, ancillary and travelling equipment are run. A 500 ton hoist rating can be used to allow some margin of safety.
- the hoisting tower would further include hoisting capacity to hoist double drill pipe joints for use in drilling wells in water depths of at least approximately 7,500 ft; a hoisting capacity to hoist casing for use in drilling wells in water depths of at least approximately 7,500 ft; or combinations thereof.
- the drill ship can also include active pit tank capacity to fully displace a largest hole volume over to another mud or brine system for use in drilling wells in water depths of at least approximately 7,500 ft; full mud treatment and cuttings containment, with the ability to mix new mud and brine simultaneously, for use in drilling wells in water depths of at least approximately 7,500 ft; liquid and dry bulk storage for use in drilling wells in water depths of at least approximately 7,500 ft; deck space and services for electric and slick line, cementing, well testing, well simulation, coiled tubing, MPD/UBD operations, drill cutting operations, or combinations thereof for use in drilling wells in water depths of at least approximately 7,500 ft; or combinations thereof.
- the floatable structure may further include various combinations of the types of equipment described herein.
- the active pit system can be 6,460 bbls (1027 m 3 ) plus five treatment tanks of 60 bbls (9.5 m 3 ) each.
- the active pits can be split in half for two independent mud/brine systems with two independent automated mud/brine mixing facilities for concurrent operations.
- Liquid storage can include 9,749 bbls (1,550 m 3 ) of drill water, 2,139 bbls (340 m 3 ) of base oil, and 1,572 bbls (250 m 3 ) of brine.
- Three conventional triplex pumps with approximately 7,500 psi fluid ends can provide for all downhole pumping operations.
- Solids control can be provided by four linear motion shale shakers, a desander, a desilter, a degasser, and space for two contractor supplied centrifuges. Solids disposal can be via one double self cleaning screw conveyor feeding into a big bag turntable station. Dry bulk storage can include six x 60 m 3 tanks, (one bentonite, three barite and two cement) with three x 6 m 3 surge tanks.
- the cement unit can be contractor supplied and also provide pressure testing and emergency pumping services. Those ordinarily skilled in the art having the benefit of this disclosure realize other types of equipment can be used with the present invention, such as those used in controlling mud and solids, as well as cement systems.
- the exemplary drill ship may further include hoisting and handling equipment.
- a single hoisting tower with a ram type hoist having a clear working height of 120 ft for drilling, along with a top drive and double joints of range two drill pipe, can be included.
- Dead line compensation can be included for drill string motion compensation.
- the hoisting tower can further include a hydraulic racking system with setback for 22,500 ft of 5 inch drill pipe and drill collars.
- a remote operated iron roughneck can be provided on the drill floor 35 for tubular make-up and break-out.
- a skidding and trolley system below the substructure can be provided for handling and storing the two x 133 ⁇ 4 inch BOP stacks and up to two subsea Xmas trees. Additionally, at moon pool level, there can be a retractable dummy riser spider trolley to hang off the BOP while the load ring and telescopic joints are installed.
- the exemplary drill ship described herein can further include three hydraulic knuckle boom cranes: a compensated crane rated to 120 T in port / 60 T offshore for handling BOP equipment, Xmas trees, and for construction activities; a 20 T rated crane to serve the aft deck and mud treatment deckhouse; and a 25 T rated crane for loading tubulars from the quay to the riser racks.
- the systems and methods described herein can also include two horizontal catwalks, one forward for riser transport and one aft for drill pipe/casing both at drill floor 35 elevation.
- One gantry crane can be installed on the riser storage area and one gantry crane over the aft pipe storage area.
- a tubular handling overhead crane and a vertical pipe elevator can be installed in the pipe hold in the hull.
- Other types of hoisting and handling equipment that can be used in the present invention will be apparent to those of skill in the art having the benefit of this disclosure.
- the exemplary drill ship described herein further includes drilling tools.
- drilling tools for example, approximately 22,500 ft each of 5 inch and 31 ⁇ 2 inch high grade drill pipe, and ten each of 8 inch, 61 ⁇ 2 inch and 43 ⁇ 4 inch drill collars, all with handling and fishing tools can be included.
- the types and amounts of drilling tools included will vary depending upon the needs of each system as will be apparent to those of skill in the art having the benefit of this disclosure.
- the exemplary drill ship also includes utility systems.
- the electrical power system can include variable speed AC drives for the mud pumps and top drive, with a normal drilling load of 3.0 Megawatts (MW).
- the hoisting system can be hydraulically powered through a central HPU.
- the types and amounts of utility systems included in embodiments of the present invention will vary depending upon the needs of each system as will be apparent to those of skill in the art having the benefit of this disclosure.
- the exemplary drill ship can be powered by six 4.7 MW main diesel electric alternator sets with propulsion from five fixed pitch, variable speed thrusters with a combined power of 17.3 MW.
- the thrusters can be configured for independent and integrated operation with the dynamically positioned vessel to IMO class 3. All systems can be designed and installed to ensure that adequate redundancy is maintained and that no single failure will result in loss of positional keeping or operational performance.
- the exemplary drill ship can also have an endurance of sixty days (typically thirty days transit and thirty days dynamically positioned), and operations can be designed to be carried out without assistance from other vessels.
- the ship's service speed can be around fourteen knots.
- the heli-deck can be rated for S61, S92, EC225 & Super Puma helicopters.
- One 25m burner boom can be mounted on the port stern for flaring operations.
- the all up day spread rate (including services and fuel) for the large drill ship are expected to be in the region of $750 - $800,000/day, while the expectation for use of the systems and methods described herein is expected to be one-half to two-thirds that spread rate.
- An exemplary embodiment of the present invention provides a subsea assembly for use in subsea operations, the assembly comprising a slip joint assembly located beneath a vessel floor; a rotating control head located beneath the slip joint assembly; an upper blow out preventer (“UBOP") located beneath the rotating control head; an upper stress joint located beneath the UBOP; a riser string located beneath the upper stress joint; a lower stress joint located beneath the riser string; a lower blow out preventer (“LBOP”) located beneath the lower stress joint; and a wellhead located beneath the LBOP.
- the riser string has a pressure rating that is the same as a pressure rating of the UBOP and LBOP.
- the assembly is used in an offshore deepwater environment.
- the assembly is adapted to perform at least one of a Managed Pressure Drilling, Underbalanced Drilling, or Through Tubing Rotary Drilling operation.
- the riser string is sized for running casing having an API size less than or equal to 133 ⁇ 4".
- the vessel may also have a length of no more than 148 meters and a width of no more than 28 meters.
- the vessel is adapted to drill wells in water depths of at least 7,500 ft.
- An exemplary methodology of the present invention provides a method for use in a subsea operation, the method comprising the steps of (a) providing a slip joint assembly located beneath a vessel floor; (b) providing a rotating control head located beneath the slip joint assembly; (c) providing an upper blow out preventer (“UBOP") located beneath the rotating control head; (d) providing an upper stress joint located beneath the UBOP; (e) providing a riser string located beneath the upper stress joint; (f) providing a lower stress joint located beneath the riser string; (g) a lower blow out preventer (“LBOP”) located beneath the lower stress joint; and (f) providing a wellhead located beneath the LBOP.
- UBOP upper blow out preventer
- step (e) further comprises the step of providing the riser string with a pressure rating that is the same as a pressure rating of the UBOP and LBOP.
- the method further comprises the step of performing the subsea operation in an offshore deepwater environment.
- the method further comprises the step of performing at least one of a Managed Pressure Drilling, Underbalanced Drilling, or Through Tubing Rotary Drilling operation.
- the method further comprises the step of tripping a liner having an API size less than or equal to 133 ⁇ 4" through the riser string.
- the method further comprises the step of providing the vessel with a length of no more than 148 meters and a width of no more than 28 meters.
- Another exemplary embodiment of the present invention provides a subsea assembly for use in subsea operations, the assembly comprising an upper blow out preventer (“UBOP") located beneath a vessel floor; a riser string located beneath the UBOP; and a lower blow out preventer (“LBOP") located beneath the riser string and operatively coupled to a wellhead.
- the riser string has a pressure rating that is the same as a pressure rating of the UBOP and LBOP.
- a pressure rating of the UBOP, riser string, and LBOP is at least 10,000 psi.
- the assembly is used in an offshore deepwater environment.
- the assembly is adapted to perform at least one of a Managed Pressure Drilling, Underbalanced Drilling, or Through Tubing Rotary Drilling operation.
- the riser string is sized for running casing having an API size less than or equal to 133 ⁇ 4".
- An exemplary embodiment may also comprise a rotating control head.
- the vessel has a length of no more than 148 meters and a width of no more than 28 meters.
- the vessel is adapted to drill wells in water depths of at least 7,500 ft.
- Another exemplary methodology of the present invention provides a method for use in subsea operations, the method comprising the steps of (a) providing a vessel having a floor; (b) providing an upper blow out preventer (“UBOP") located beneath the floor; (c) providing a riser string located beneath the UBOP; (d) providing a lower blow out preventer (“LBOP”) located beneath the riser assembly; and (e) connecting the LBOP to a wellhead beneath the LBOP.
- the method further comprises the step of providing the riser string with a pressure rating that is the same as a pressure rating of the UBOP and LBOP.
- the method further comprises the step of providing the UBOP, riser string, and LBOP with a pressure rating of at least 10,000 psi.
- the method further comprises the step of performing the subsea operations in an offshore deepwater environment.
- the method further comprises the step of performing at least one of a Managed Pressure Drilling, Underbalanced Drilling, or Through Tubing Rotary Drilling operation.
- the method further comprises the step of tripping liner down the riser string, the liner having an API size less than or equal to 13 3 /s".
- the method further comprises the step of locating a rotating control head beneath the UBOP.
- step (a) further comprises the step of providing the vessel with dimensions of no more than 148 meters in length and no more than 28 meters in width.
- the method further comprises the step of drilling a well at a water depth of at least 7,500 ft.
- Another exemplary embodiment of the present invention provides a subsea assembly for use in subsea operations, the assembly comprising a vessel having a floor; and a riser string located beneath the floor, wherein the assembly is adapted to perform at least one of a Managed Pressure Drilling, Underbalanced Drilling, or Through Tubing Rotary Drilling operation.
- the assembly further comprises an upper blow out preventer ("UBOP") located above the riser string; a lower blow out preventer (“LBOP”) located below the riser string; and a wellhead located beneath the LBOP.
- the riser string is adapted to withstand at least 10,000 psi.
- Another exemplary methodology of the present invention provides a method for use in subsea operations, the method comprising the steps of (a) providing a vessel having a floor; (b) providing a riser string located beneath the floor; and (c) performing at least one of a Managed Pressure Drilling, Underbalanced Drilling, or Through Tubing Rotary Drilling operation.
- the method further comprises the steps of providing an upper blow out preventer ("UBOP") located above the riser string; providing a lower blow out preventer (“LBOP”) located beneath the riser string; and providing a wellhead located beneath the LBOP.
- the method further comprises the step of adapting the riser string to withstand at least 10,000 psi.
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Abstract
Description
Claims
Priority Applications (4)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
AU2010326576A AU2010326576A1 (en) | 2009-12-02 | 2010-12-02 | Assembly and method for subsea well drilling and intervention |
EP10784556A EP2507468A2 (en) | 2009-12-02 | 2010-12-02 | Assembly and method for subsea well drilling and intervention |
BR112012013247A BR112012013247A2 (en) | 2009-12-02 | 2010-12-02 | subsea set and method for use in subsea operations " |
CA2782168A CA2782168A1 (en) | 2009-12-02 | 2010-12-02 | Assembly and method for subsea well drilling and intervention |
Applications Claiming Priority (2)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US26580509P | 2009-12-02 | 2009-12-02 | |
US61/265,805 | 2009-12-02 |
Publications (2)
Publication Number | Publication Date |
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WO2011067353A2 true WO2011067353A2 (en) | 2011-06-09 |
WO2011067353A3 WO2011067353A3 (en) | 2011-10-13 |
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EP (1) | EP2507468A2 (en) |
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Cited By (1)
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US10435980B2 (en) | 2015-09-10 | 2019-10-08 | Halliburton Energy Services, Inc. | Integrated rotating control device and gas handling system for a marine drilling system |
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WO2011106004A1 (en) * | 2010-02-25 | 2011-09-01 | Halliburton Energy Services, Inc. | Pressure control device with remote orientation relative to a rig |
US8739863B2 (en) | 2010-11-20 | 2014-06-03 | Halliburton Energy Services, Inc. | Remote operation of a rotating control device bearing clamp |
US9260934B2 (en) | 2010-11-20 | 2016-02-16 | Halliburton Energy Services, Inc. | Remote operation of a rotating control device bearing clamp |
US9163473B2 (en) | 2010-11-20 | 2015-10-20 | Halliburton Energy Services, Inc. | Remote operation of a rotating control device bearing clamp and safety latch |
US10060207B2 (en) * | 2011-10-05 | 2018-08-28 | Helix Energy Solutions Group, Inc. | Riser system and method of use |
US10113378B2 (en) | 2012-12-28 | 2018-10-30 | Halliburton Energy Services, Inc. | System and method for managing pressure when drilling |
WO2014120130A1 (en) * | 2013-01-29 | 2014-08-07 | Martin Tindle | Riser fluid handling system |
US9109420B2 (en) * | 2013-01-30 | 2015-08-18 | Rowan Deepwater Drilling (Gibraltar) Ltd. | Riser fluid handling system |
WO2014140367A2 (en) * | 2013-03-15 | 2014-09-18 | A.P. Møller-Mærsk A/S | An offshore drilling rig and a method of operating the same |
US10570672B2 (en) | 2013-03-15 | 2020-02-25 | Maersk Drilling A/S | Offshore drilling rig and a method of operating the same |
US10294746B2 (en) | 2013-03-15 | 2019-05-21 | Cameron International Corporation | Riser gas handling system |
ITMI20131733A1 (en) * | 2013-10-17 | 2015-04-18 | Eni Spa | PROCEDURE FOR REALIZING A WELL TO EXPLOIT A FIELD UNDER A MARINE OR OCEANIC BOTTOM |
US9938792B2 (en) * | 2015-11-06 | 2018-04-10 | Vetco Gray, LLC | Remotely operated external tieback connector |
US11208862B2 (en) * | 2017-05-30 | 2021-12-28 | Trendsetter Vulcan Offshore, Inc. | Method of drilling and completing a well |
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CA1224715A (en) * | 1983-02-18 | 1987-07-28 | Peter R. Gibb | Apparatus and method for connecting subsea production equipment to a floating facility |
US4626135A (en) * | 1984-10-22 | 1986-12-02 | Hydril Company | Marine riser well control method and apparatus |
US6263982B1 (en) * | 1998-03-02 | 2001-07-24 | Weatherford Holding U.S., Inc. | Method and system for return of drilling fluid from a sealed marine riser to a floating drilling rig while drilling |
CA2363132C (en) * | 1999-03-02 | 2008-02-12 | Weatherford/Lamb, Inc. | Internal riser rotating control head |
CA2803812C (en) * | 2001-09-10 | 2015-11-17 | Ocean Riser Systems As | Arrangement and method for regulating bottom hole pressures when drilling deepwater offshore wells |
US7237623B2 (en) * | 2003-09-19 | 2007-07-03 | Weatherford/Lamb, Inc. | Method for pressurized mud cap and reverse circulation drilling from a floating drilling rig using a sealed marine riser |
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US7144048B2 (en) * | 2004-05-05 | 2006-12-05 | Stena Drilling Ltd. | Composite marine riser |
US8925647B2 (en) * | 2006-06-30 | 2015-01-06 | Stena Drilling Ltd. | Triple activity drilling ship |
US7699109B2 (en) * | 2006-11-06 | 2010-04-20 | Smith International | Rotating control device apparatus and method |
NO329440B1 (en) * | 2007-11-09 | 2010-10-18 | Fmc Kongsberg Subsea As | Riser system and method for inserting a tool into a well |
NO328199B1 (en) * | 2008-02-13 | 2010-01-04 | Fmc Kongsberg Subsea As | Device for repelling a riser |
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2010
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- 2010-12-02 CA CA2782168A patent/CA2782168A1/en not_active Abandoned
- 2010-12-02 WO PCT/EP2010/068771 patent/WO2011067353A2/en active Application Filing
- 2010-12-02 BR BR112012013247A patent/BR112012013247A2/en not_active IP Right Cessation
- 2010-12-02 US US12/958,802 patent/US20110127040A1/en not_active Abandoned
- 2010-12-02 EP EP10784556A patent/EP2507468A2/en not_active Withdrawn
Cited By (1)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US10435980B2 (en) | 2015-09-10 | 2019-10-08 | Halliburton Energy Services, Inc. | Integrated rotating control device and gas handling system for a marine drilling system |
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BR112012013247A2 (en) | 2019-09-24 |
US20110127040A1 (en) | 2011-06-02 |
CA2782168A1 (en) | 2011-06-09 |
WO2011067353A3 (en) | 2011-10-13 |
EP2507468A2 (en) | 2012-10-10 |
AU2010326576A1 (en) | 2012-07-12 |
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