EP3507444B1 - Système de prise en charge des gaz dans une colonne montante et son procédé d'utilisation - Google Patents

Système de prise en charge des gaz dans une colonne montante et son procédé d'utilisation Download PDF

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Publication number
EP3507444B1
EP3507444B1 EP17780853.2A EP17780853A EP3507444B1 EP 3507444 B1 EP3507444 B1 EP 3507444B1 EP 17780853 A EP17780853 A EP 17780853A EP 3507444 B1 EP3507444 B1 EP 3507444B1
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EP
European Patent Office
Prior art keywords
riser
assembly
tension ring
control device
disconnect assembly
Prior art date
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Application number
EP17780853.2A
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German (de)
English (en)
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EP3507444A1 (fr
Inventor
Alan Murray Clark
Alan John REID
Ian McQueen ALLAN
Graham Paterson Birkett
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Deep Blue Oil and Gas Ltd
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Deep Blue Oil and Gas Ltd
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Publication of EP3507444A1 publication Critical patent/EP3507444A1/fr
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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
    • E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
    • E21B17/01—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
    • E21B19/006—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 including heave compensators
    • 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
    • E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
    • E21B21/001—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor specially adapted for underwater drilling
    • 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
    • E21B33/08—Wipers; Oil savers
    • E21B33/085—Rotatable packing means, e.g. rotating blow-out preventers

Definitions

  • the present invention relates to a riser gas handling system and method of use, and in particular to riser gas handling systems for subsea applications.
  • a particular aspect of the invention relates to riser gas handling systems that enable managed pressure drilling operations.
  • Drilling operations typically use a rotating drill bit on the end of a drillstring. Mud is pumped down the drillstring from a rig mud pumping system and returned to the surface flowing in the annulus between the drillstring and the well. The returning mud exits the annulus above a blow-out preventer (BOP) into a mud return line where it freely flows into solids control equipment to allow sand and cuttings to be removed from the well. The mud is stored in holding tanks until it is pumped back down the well.
  • BOP blow-out preventer
  • the mud which is pumped down the drillstring performs multiple functions, including providing hydraulic power to drilling tools at the end of the drillstring, stabilising the well, and cooling the drillbit.
  • the mud provides pressure in the well which prevents an influx of pressurised gas or oil from any hydrocarbon bearing formations.
  • the pressure is a function of the mud density, friction in the wellbore caused by the flowing mud, and the vertical depth of the well.
  • the density of the mud must be controlled to provide a pressure at the bottom of the well which is above the pore pressure (the pressure at which the well may collapse or allow a hydrocarbon influx) but below the fracture pressure (the pressure where the well structure could fracture).
  • MPD Managed Pressure Drilling
  • the mud circulation system becomes a closed loop with returning mud from the wellbore flowing into an arrangement of valves or manifolds that can apply backpressure or route the flow to other processing systems.
  • the annulus is capped above the BOP using a seal, typically a rotating control device (RCD).
  • RCD rotating control device
  • Offshore drilling relies on the use of a tubular, known as a drilling riser, which allows the annulus to extend from the seabed to the surface.
  • a riser section known as a slip joint or telescopic joint is used to allow the free movement of the drilling vessel caused by wave motion.
  • the riser is held in position using a device known as a tension ring, connected to an arrangement of cylinders via cable or directly, which provides a constant tension to the sections of riser below the tension ring.
  • a tension ring connected to an arrangement of cylinders via cable or directly, which provides a constant tension to the sections of riser below the tension ring.
  • BOP blow out preventer
  • a riser gas handling (RGH) system is required to respond quickly to a gas influx to divert and release the gas in a controlled manner thereby avoiding potential dangers to rig personnel and mitigating damage to the riser and rig infrastructure.
  • this configuration occupies space that would normally be used by the telescopic joint, reducing the possible stroke of the telescopic section. This reduces the possible geographic deployments of the drilling vessel and limits it to areas with a calmer range of sea states. It is not suitable for deep water applications with dynamic sea conditions.
  • BTR Below Tension Ring
  • the flowspool, riser isolation device, and rotating control device are installed below the tension ring.
  • the telescopic joint can fully extend and contract to its full length, allowing a greater range of geographic deployments and more dynamic sea conditions.
  • the BTR configuration limits access to key components of the riser and requires time consuming and costly operations to install, replace and/or repair RGH and drilling components located beneath the tension ring. These operations involve closing the well, disconnecting the riser from the subsea BOP, and pulling the entire riser string and disassembling it section by section until the desired component housing is reached. Once the component has been replaced or repaired, the entire riser string must be reassembled in sections as the BOP is reattached to the wellhead.
  • a riser assembly comprising: a riser flow spool; a riser isolation device and an upper riser disconnect assembly; wherein at least the riser flow spool is located on a riser below a riser tension ring and wherein the upper riser disconnect assembly is located above the riser tension ring.
  • the riser flow spool and the riser isolation device are configured to be connected to the riser below the tension ring.
  • RGH Riser Flow Spool
  • RID Riser Isolation Device
  • the upper riser disconnect assembly may be configured to connect to a rotating control device (RCD).
  • the rotating control device may be disposed above the upper riser disconnect assembly.
  • the rotating control device may be disposed above the riser tension ring.
  • the RCD releasably connects above the upper riser disconnect assembly.
  • the RCD releasably connects to the riser assembly above the upper riser disconnect assembly.
  • the RCD comprises one or more seals encased in a rotating bearing.
  • the bearing sits in a housing that may provide lubrication for the movement of the bearing.
  • the RCD may include latching elements that hold the bearing in a vertical position against a force possibly present in the wellbore.
  • the RCD may require regular replacement of the seals, due to the axial movement of the drill pipe through the seals which cause wear. This wear can be aggravated by the surface finish of the drill pipe, the pressure in the wellbore, the vertical speed of the drill pipe, and the load on the seal caused by the connection points (known as tool joints).
  • the replacement of the seal involves sealing the well below the RCD (typically performed using one or more of the sealing elements in the BOP), then unlatching the bearing element which is then retrieved by pulling the drillstring out of the well.
  • the RCD may be installed, removed and/or temporarily disconnected for maintenance operations without having to remove components of the lower riser assembly below the tension ring or disconnect the riser string from the BOP or wellhead. This allows the RCD to be quickly and conveniently installed and/or removed from the riser assembly above the tension ring while minimising any impact on the stroke length of the slip joint.
  • a further benefit of an embodiment of the invention is that the RCD may be quickly and easily installed on the riser assembly only when managed pressure drilling is required.
  • Conventional drilling with RGH functionality may be performed during routine drilling.
  • the drill system may be adapted for managed pressure drilling. By installing an RCD and/or other MPD equipment only when required may result in lower operation costs.
  • An additional benefit of an embodiment of the invention is improved hose management as the hoses and control lines connected to the RID and RFS may be vertically offset from the tensioning system, which includes the tension ring, tension cylinders and tension rods and/or lines. This may prevent the RGH hoses from being hindered by the tensioning cylinders or rods connected to the tensioning rings.
  • the RID is positioned above the RFS on the riser string.
  • the RID is closed during a riser gas handling event.
  • the upper riser disconnect assembly, riser flow spool and/or riser isolation device may be controlled remotely.
  • the RID is controlled remotely.
  • the RID may comprise a packing element.
  • the RID comprises at least one sensor to monitor actuation of the packing element and/or sealing of the RID.
  • the RID may comprise pressure control for sealing the RID.
  • the RID may be dimensioned to fit through a platform rig floor rotary table.
  • the RFS may have at least one flowline.
  • the at least one flowline may be configured to be connected to a distribution assembly, choke assembly and/or a mud-gas separator.
  • the at least one flowline may be connected to a safety valve.
  • the safety valve may be configured to divert riser gas overboard.
  • the RFS has multiple flowlines.
  • the RFS may be configured to be connected to at least one hose.
  • the at least one hose may be configured to be vertically offset from the tensioning system.
  • the RID and RFS are integrated in a single unit.
  • the RID and RFS may be combined into an integrated riser joint.
  • the integrated riser joint may be dimensioned to pass through the rig floor rotary table.
  • the RFS has at least one valve assembly.
  • the at least one valve assembly may be configured to open a pathway between the riser annulus and the distribution assembly, choke assembly and/or a mud-gas separator in the event of a riser gas influx.
  • the RFS assembly may be dimensioned to fit through a platform rig floor rotary table.
  • the RFS is compact and lightweight to allow quick rig up/rig down time.
  • the tension ring is coupled to a tensioning system to allow relative vertical movement between the riser and the platform.
  • the tension ring is disposed between the tensioning system and the riser.
  • the tension ring may be disposed circumferentially about a portion of the riser, a portion of the RID, a portion of slip joint, an outer barrel of a slip joint, a portion of the upper riser disconnect assembly and/or a tension joint.
  • the upper riser disconnect assembly may be connected to a RCD and/or other drilling operation components.
  • the upper riser disconnect assembly may be configured to allow the RCD and/or other drilling operation components to be releasably latched to the riser assembly.
  • the upper riser disconnect assembly may comprise an upper connector and a lower connector.
  • the upper and lower connectors may be configured to disconnect from one another.
  • the separated upper and lower connectors may be configured to connect to one another.
  • the upper and lower connectors may be configured to connect to or disconnect from one another on command.
  • the upper connector may be to an RCD or other drilling/riser components.
  • the lower connector of the upper riser disconnect assembly may be connected to a tension ring, tension joint and/or an outer slip joint barrel.
  • the upper riser disconnect assembly is a slip joint disconnect assembly.
  • the upper riser disconnect assembly may comprise at least one sensor to monitor and/or indicate a latched and/or unlatched status.
  • the upper riser disconnect assembly is a quick disconnect assembly.
  • the upper riser disconnect assembly may be controlled remotely.
  • the upper riser disconnect assembly is configured for remote releasably latching/unlatching.
  • the upper riser disconnect assembly is configured for assembly to the slip joint above the tension ring.
  • the upper riser disconnect assembly may be disposed below the slip joint.
  • the slip joint may be a two-part slip joint. Alternatively, the slip joint may be a three or more part slip joint.
  • the slip joint may comprise at least one sealing assembly.
  • the slip joint may comprise two telescopic members.
  • the slip joint may comprise more than two telescopic members.
  • the RCD may be installed onto the RGH system to allow a managed pressure drilling operation without requiring structural modifications to the RGH system.
  • the RCD may be connected to the upper riser disconnect assembly located above the tension ring.
  • the RCD may be configured to seal off the riser annulus while a drill string is located in the RCD.
  • the system may comprise a choke.
  • the choke may receive the drilling fluid from the annulus below the RCD, and may be an MPD choke.
  • a system for handling gas in a riser comprising:
  • the riser flow spool and the riser isolation device are configured to be connected to the riser below the tension ring.
  • the upper riser disconnect assembly is configured to be connected to a slip joint above the tension ring.
  • a rotary control device may be configured to be connected to the upper riser disconnect assembly above the tension ring.
  • the rotary control device and/or the upper riser disconnect assembly is configured to be releasably connected to the riser assembly above the tension ring.
  • Embodiments of the second aspect of the invention may include one or more features of the first aspect of the invention or its embodiments, or vice versa.
  • a system for handling gas in a riser to enable managed pressure drilling operations comprising:
  • the riser flow spool and the riser isolation device are configured to be connected to the riser below the tension ring.
  • the upper riser disconnect assembly is configured to be connected to a slip joint above the tension ring.
  • the rotary control device may be configured to be connected to the upper riser disconnect assembly above the tension ring.
  • the rotary control device is configured to be releasably connected to the riser assembly above the tension ring via the upper riser disconnect assembly.
  • Embodiments of the third aspect of the invention may include one or more features of the first or second aspects of the invention or its embodiments, or vice versa.
  • a riser gas handling system in a subsea riser comprising:
  • the method may comprise installing a riser isolation device below the tension ring.
  • the method may comprise installing a riser isolation device on the riser string below the tension ring.
  • the method may comprise installing the riser flow spool assembly below the riser isolation device.
  • the method may comprise providing a distribution assembly and/or a choke manifold.
  • the method may comprise making up a tension ring.
  • the method may comprise connecting the tension ring to the riser, riser isolation device, slip joint and/or the upper riser disconnect assembly.
  • the method may comprise raising the RID and RFS to a position just below the tension ring.
  • the method may comprise raising the RID and RFS to a position just below the tension ring by positioning a riser tension joint between the RID and the tension ring.
  • the method may comprise connecting a RCD and/or other drilling components to the upper riser disconnect assembly.
  • the method may comprise installing the upper riser disconnect assembly on the riser string above the tension ring.
  • the method may comprise bolting, welding and/or clamping the rotary control device onto an upper connector of the upper riser disconnect assembly.
  • the method may comprise connecting a lower connector of the upper riser disconnect assembly onto a tension ring, tension joint and/or an outer slip joint barrel.
  • the method may comprise connecting the slip joint to the rotary control device.
  • the method may comprise coupling the upper and lower connectors of the upper riser disconnect assembly.
  • Embodiments of the fourth aspect of the invention may include one or more features of the first, second or third aspects of the invention or their embodiments, or vice versa.
  • a riser gas handling system to enable managed pressure subsea drilling on a subsea riser comprising:
  • the method may comprise installing a riser isolation device below the tension ring.
  • the method may comprise installing a riser isolation device on the riser string below the tension ring.
  • the method may comprise providing a distribution assembly, a choke manifold and/or MPD choke manifold.
  • the method may comprise making up the tension ring.
  • the method may comprise connecting the tension ring to the riser, RID, slip joint and/or the upper riser disconnect assembly.
  • the method may comprise installing the upper riser disconnect assembly on the riser string and then installing the rotary control device onto the upper riser disconnect assembly.
  • the rotary control device may be installed on the upper riser disconnect assembly by releasably latching onto the upper riser disconnect assembly.
  • Embodiments of the fifth aspect of the invention may include one or more features of the first to fourth aspects of the invention or their embodiments, or vice versa.
  • a method of converting a marine riser for RGH operations comprising:
  • the method may comprise installing a riser isolation device below the tension ring.
  • the method may comprise installing a riser isolation device on the riser string below the tension ring.
  • the method may comprise removing an existing slip joint and/or an existing slip joint inner barrel on the subsea riser.
  • the method may comprise installing the RFS and RID onto an existing riser.
  • the method may comprise installing the RFS and RID onto an existing riser above an existing riser termination joint.
  • the method may comprise installing a riser auxiliary line termination joint on the existing riser.
  • the method may comprise installing the RFS and RID onto the termination joint.
  • the method may comprise making up the tension ring.
  • the method may comprise connecting the tension ring to the riser, RID, slip joint and/or the upper riser disconnect assembly.
  • the method may comprise installing a slip joint outer barrel onto the RID.
  • the tension ring may be made up and connected to the slip joint outer barrel.
  • the method may comprise installing the upper riser disconnect assembly above the tension ring.
  • the method may comprise reversibly latching a slip joint to the upper riser disconnect assembly.
  • Embodiments of the sixth aspect of the invention may include one or more features of the first to fifth third aspects of the invention or their embodiments, or vice versa.
  • a method of converting a marine riser for RGH operations which enables managed pressure subsea drilling operations comprising:
  • the method may comprise installing a riser isolation device below the tension ring.
  • the method may comprise installing a riser isolation device on the riser string below the tension ring.
  • the method may comprise providing a distribution assembly, a choke manifold and/or MPD choke manifold.
  • the method may comprise removing an existing slip joint and/or an existing slip joint inner barrel on the subsea riser.
  • the method may comprise installing the RFS and RID onto an existing riser.
  • the method may comprise installing the RFS and RID onto an existing riser above an existing riser termination joint.
  • the method may comprise installing a riser auxiliary line termination joint on the existing riser.
  • the method may comprise installing the RFS and RID onto the termination joint.
  • the method may comprise making up the tension ring.
  • the method may comprise connecting the tension ring to the riser, RID, slip joint and/or the upper riser disconnect assembly.
  • the method may comprise installing a slip joint outer barrel onto the RID.
  • the tension ring may be made up and connected to the slip joint outer barrel.
  • the method may comprise installing a lower connector of the upper riser disconnect assembly on the riser string above the tension ring.
  • the method may comprise installing a rotary control device made up with a connector configured to releasably latch onto the lower connector of the upper riser disconnect assembly.
  • the method may comprise bolting, welding and/or clamping the rotary control device onto an upper connector of the upper riser disconnect assembly.
  • the method may comprise connecting a lower connector of the upper riser disconnect assembly onto a tension ring, tension joint and/or an outer slip joint barrel.
  • the method may comprise connecting the slip joint to the rotary control device.
  • the method may comprise coupling/decoupling the upper and lower connectors of the upper riser disconnect assembly to/from one another.
  • the method may comprise connecting a slip joint to the rotary control device.
  • Embodiments of the seventh aspect of the invention may include one or more features of any of the first to sixth aspects of the invention or their embodiments, or vice versa.
  • a riser assembly comprising:
  • the riser flow spool and the riser isolation device are configured to be connected to the riser below the tension ring.
  • the method may comprise actuating a blowout preventer on the riser to close the riser below the flow spool.
  • the method may comprise actuating a distribution manifold and/or riser gas handling choke to control the diversion of gas trapped below the riser isolation device.
  • the method may comprise opening valves on the riser flow spool, distribution manifold and/or riser gas handling choke to enable the gas to flow to a mud gas separator.
  • Embodiments of the eighth aspect of the invention may include one or more features of any of the first to seventh aspects of the invention or their embodiments, or vice versa.
  • a riser assembly comprising:
  • the riser flow spool and the riser isolation device are configured to be connected to the riser below the tension ring.
  • the method may comprise providing a rotary control device.
  • the rotary control device may be releasably connected to the upper riser disconnect assembly.
  • the method may comprise actuating a blowout preventer on the riser to close the riser below the flow spool.
  • the method may comprise controlling the diversion of gas trapped below the riser isolation device.
  • the method may comprise actuating a distribution manifold and/or riser gas handling choke to control the diversion of gas trapped below the riser isolation device.
  • the method may comprise opening valves on the riser flow spool, distribution manifold and/or riser gas handling choke to enable the gas to flow to a mud gas separator.
  • Embodiments of the ninth aspect of the invention may include one or more features of any of the first to eighth aspects of the invention or their embodiments, or vice versa.
  • kit of parts for converting a riser for riser gas handling operations including:
  • the riser flow spool has connections configured to engage and connect to a riser below a riser tension ring.
  • the riser flow spool may be engageable with the riser isolation device.
  • the riser flow spool and riser isolation device form an integrated unit.
  • the kit of parts may comprise a slip joint.
  • the upper riser disconnect assembly has connections configured to engage and mount a slip joint above a riser tension ring.
  • the kit of parts may comprise a choke manifold and/or distribution manifold.
  • the kit of parts may comprise a rotary control device for converting a riser for riser gas handling operations which enables managed pressure subsea drilling operations.
  • the rotary control device may be mountable on the riser string above the riser tension ring.
  • the rotary control device may be releasably mountable on the upper riser disconnect assembly.
  • Embodiments of the tenth aspect of the invention may include one or more features of any of the first to ninth aspects of the invention or their embodiments, or vice versa.
  • a rotary control device in a riser with riser gas handling comprising:
  • the riser flow spool and the riser isolation device are configured to be connected to the riser below the tension ring.
  • the method may comprise closing a blowout preventer on the riser prior to connecting the rotary control device to the upper riser disconnect assembly.
  • Embodiments of the eleventh aspect of the invention may include one or more features of any of the first to tenth aspects of the invention or their embodiments, or vice versa.
  • a method of recovering a rotary control device from a riser comprising:
  • the method may comprise actuating the upper riser disconnect assembly to disconnect the rotary control device from the riser assembly.
  • the method may comprise closing a blowout preventer on the riser prior to disconnect the rotary control device.
  • Embodiments of the twelfth aspect of the invention may include one or more features of any of the first to eleventh aspects of the invention or their embodiments, or vice versa.
  • a method of replacing a rotary control device on a riser comprising:
  • the method may comprise actuating the upper riser disconnect assembly to disconnect the rotary control device from the riser assembly.
  • the method may comprise actuating the upper riser disconnect assembly to disconnect the upper riser disconnect assembly and rotary control device from the riser assembly.
  • the method may comprise actuating the upper riser disconnect assembly to connect the replacement rotary control device to the riser assembly.
  • the method may comprise actuating the upper riser disconnect assembly to connect the upper riser disconnect assembly and replacement rotary control device to the riser assembly.
  • the method may comprise closing a blowout preventer on the riser prior to disconnect the rotary control device.
  • the method may comprise closing a blowout preventer on the riser prior to connecting the replacement rotary control device.
  • Embodiments of the thirteenth aspect of the invention may include one or more features of any of the first to twelfth aspects of the invention or their embodiments, or vice versa.
  • Figures 1A and 1B show features of conventional drilling riser assemblies for extracting oil and natural gas from a subsea reservoir known in the prior art.
  • the riser assembly 10 comprises a riser 12 located between a rig platform 16 and a blowout preventer (BOP) assembly (not shown) secured to the top of the wellhead.
  • BOP blowout preventer
  • the riser 12 is connected to a slip joint 14.
  • the slip joint 14 is configured to respond to heave movement of the platform 16 during dynamic sea conditions.
  • a portion of platform 16 is shown, which may be a floating rig or drillship.
  • the platform supports the riser assembly 10 and comprises a moon pool opening 18.
  • a plurality of tensioning cylinders 20 are secured to the platform and exert an upward force on rods or cables 22.
  • the lower end of each rod or cable 22 is connected to a riser tensioning ring 24 which is connected to maintain the stability of the riser 12 in the offshore environment.
  • External auxiliary lines 26 are connected to the BOP (not shown) and circulate fluids and provide control lines to the BOP.
  • a termination ring 28 is disposed circumferentially about a portion of the riser 12.
  • the auxiliary lines 26 terminate at the termination ring.
  • Flexible hoses 30 are connected to the termination ring 28 and extend upward coupling to the platform. The hoses 30 have been truncated in these drawings for clarity.
  • the termination joint 28 provides fluid communication between the auxiliary lines 26 and the flexible hoses 30.
  • Figure 2 schematically shows features of the riser assembly with RGH according to a first embodiment of the present invention. It will be appreciated that the RGH system can adopt different configurations depending on the type of riser system on which it is being installed and the type of drilling operation. Figure 2 represents one possible configuration that the RGH system may adopt.
  • the riser assembly 100 with RGH system comprises a riser 112 located between a platform 116 and a blowout preventer (BOP) assembly (not shown) secured to the top of the wellhead.
  • BOP blowout preventer
  • the RGH system comprises a riser flow spool (RFS) 134 connected to the riser 112 and a riser isolation device (RID) 136 mounted above the RFS 134.
  • the RFS and RID are disposed on the riser string below the tension ring 124.
  • the RFS comprises two flexible hoses 140 which have been truncated in Figure 2 for clarity.
  • the hoses 140 are connected to a choke manifold or distribution manifold (not shown) to divert return flow to the choke manifold and/or distribution manifold for handling as discussed in Figure 6 below.
  • the tension ring 124 is disposed circumferentially about a tension joint 125 located between the RID 136 and the quick disconnect assembly 150. Although in this example the tension ring 124 is connected to tension joint 125, it may alternatively be connected to an existing rig outer barrel located between the RID 136 and the quick disconnect assembly 150.
  • the RID 136 and RFS 134 are disposed below the tension ring 124 and the quick disconnect assembly 150 is disposed above the tension ring 124.
  • Tensioning cylinders 120 are secured to the platform 116 and exert an upward force on rods or cables 122.
  • the lower end of each rod or cable 122 is connected to a riser tensioning ring 124 which is connected to maintain the stability of the riser string.
  • the quick disconnect assembly 150 is connected to a slip joint 114.
  • the slip joint 114 is configured to respond to heave movement of the platform 116 during dynamic sea conditions.
  • the platform 116 supports the riser 112 and RGH system 100.
  • the slip joint is a telescopic three-part slip joint. However, it is appreciated that other types of slip joint may be used.
  • the slip joint enables the riser system to adjust in length as the platform heaves in response to motion of the waves.
  • the riser gas handling system may include additional assemblies such as a rotating control device and/or diverter systems capable of releasably coupling to the RGH system for different drilling operations.
  • FIG. 3 schematically shows features of the riser assembly 200 with RGH system enabled for Managed Pressure Drilling (MPD) operations according to an embodiment of the present invention.
  • the RGH system 200 is similar to the system 100 described in
  • FIG. 2 the system 200 described in Figure 3 includes a rotating control device (RCD) 260 connected above the quick disconnect assembly 250 and below the slip joint 214.
  • RCD rotating control device
  • the RCD 260 is disposed above the tension ring 224 and may be easily installed on the riser assembly when managed pressure drilling is required.
  • the RCD 260 is a drill through device with a rotating internal sealing element that seals against the drill string to create a pressure-tight barrier.
  • the RCD 260 is installed between the disconnect assembly 250 and the slip joint 214 above the tension ring 224.
  • a MPD choke manifold is also provided (not shown).
  • the choke manifold is connected to the distribution manifold and is configured to receive drilling fluid from the annulus and restricts the flow of the drilling fluid to adjust the pressure in the annulus.
  • the RCD 260 When managed pressure drilling operations are not required the RCD 260 may be removed by decoupling and/or unlatching the quick disconnect assembly 250.
  • the RGH system will then adopt the configuration described in Figure 2 .
  • By facilitating the easy installation and/or removal of the RCD it may only be installed when MPD operation are required. This may extend the working lifespan of the RCD and reduce operating costs.
  • the RCD 260 may be quickly and easily removed without removing components of the RGH system 200 below the tension ring 224 or disconnecting the BOP.
  • the compact size of the RCD 260 and the quick disconnect assembly 250 above the tension ring 224 reduces or minimises loss of stroke length of the slip joint, without adjustment of the vertical position of the tension ring from its preferred location. This facilitates marine riser assemblies to be located in areas which experience dynamic sea conditions to be converted for RGH systems.
  • Figure 4A , 4B and 4C show schematic representation of conventional drill systems shown in Figure 1A and 1B converted for RGH operations.
  • the auxiliary lines 26 terminate below the slip joint.
  • the existing slip joint shown as 14 in Figure 1A is removed.
  • the RFS 334 and RID 336 are installed onto the existing riser 312 above the existing riser termination ring 328.
  • the tension ring 324 is made up and connected above the RID 336 on the tension joint 325.
  • the lower connector 350a of the disconnect assembly 350 is then installed on the tension joint 325 above the tension ring 324.
  • the telescopic slip joint 314 is made up with an upper connector 350b and is run in and releasably latched to the lower connector of the disconnect assembly 350.
  • the first example provides a riser assembly RGH system 400 with the auxiliary lines terminating below the RFS and RID as described below and shown in Figure 4B .
  • An alternative is to provide a riser assembly RGH system 500 with the auxiliary lines terminating above the RFS and RID as described below and shown in Figure 4C .
  • a new riser auxiliary line termination joint 462 is installed on the existing riser 412.
  • the RFS 434 and RID 436 are installed above the termination joint 462.
  • the tension ring 424 is made up and connected to a tension joint 425 positioned above the RID 436.
  • the lower connector 450a of disconnect assembly 450 is installed above the tension ring 424.
  • the telescopic slip joint 414 is made up with upper connector 450b and run in and releasably latched to the lower connector 450a of disconnect assembly 450.
  • Figure 4C shows a conventional drill system shown in Figure 1B converted to include a RGH system.
  • the auxiliary lines 26 terminate on the slip joint outer barrel.
  • the example shown in Figure 4C provides a riser assembly 500 with the auxiliary lines 526 terminating above the RFS 534 and RID 536.
  • the existing slip joint inner barrel is removed.
  • the RFS 534 and RID 536 are installed onto the existing riser 512.
  • the slip joint outer barrel 515 is installed onto the RID 536.
  • the tension ring is made up and connected to an upper end of the slip joint outer barrel 515.
  • the lower connector 550a of quick disconnect assembly 550 is then installed on the slip joint outer barrel 515 above the tension ring 524.
  • the telescopic joint 514 is made up with an upper connector 550b and is run in and releasably latched to the lower connector 550a of quick disconnect assembly 550.
  • FIGS 5A and 5B show schematic representations of the RGH systems of Figures 4A and 4B setup for managed pressure drilling according to an embodiment of the invention.
  • the system 600 is similar to the configuration of the systems 300, 500 described in Figures 4A and 4C and will be understood from the descriptions of Figure 4A and 4C above.
  • the system 600 described in Figures 5A and 5B includes a rotating control device (RCD) 660 connected above the quick disconnect assembly and below the slip joint 614.
  • RCD rotating control device
  • a MPD choke manifold is also provided (not shown).
  • the choke manifold is connected to the distribution manifold and receives drilling fluid from the riser annulus.
  • the RCD 660 and choke manifold control are configured to maintain the desired pressure in the annulus to allow managed pressure drilling operations.
  • the RCD 660 may be quickly and easily removed without removing components of the RGH system below the tension ring or requiring the BOP to be disconnected.
  • the compact size of the RCD and the quick disconnect assembly above the tension ring maximizes the space available above the tension ring 624 and minimizes the loss of the slip joint stroke length.
  • Figure 6 shows a flow diagram of a method of operating the RGH system during a conventional drilling operation.
  • the RGH system 700 is similar to the configuration of the system 200 described in Figure 2 and will be understood from the description of Figure 2 above.
  • the RGH system 700 comprises a RFS 734 with two return flowlines 730 and 731.
  • the RFS is also provided with a riser protection line 732.
  • the flowlines are 15.24 cm (six inch) flexible hoses. However, it should be appreciated that a different number and configuration of flowlines may be used.
  • the RGH system 700 also comprises a RID 736 and quick disconnect assembly 750.
  • the RID 736 comprises a packing element (not shown).
  • a tension ring (not shown) is configured to be connected to the riser assembly between the RID 736 and quick disconnect assembly 750.
  • the RID is open.
  • formation gas may go into solution in the mud and may get past the subsea BOP resulting in release of gas into the riser which may endanger personnel and damage the riser and platform.
  • An annular BOP (not shown) located on the lower riser is closed to seal around the drill string.
  • the RID 736 is closed around the drill string to isolate the upper riser system and allow any gas in the riser to be contained.
  • RFS 734 The function of the RFS 734 is to divert the isolated gas.
  • the options for venting the gas are either to a Mud-Gas Separator 780 (MGS) via the RGH choke or can be diverted overboard via valve 776e.
  • MGS Mud-Gas Separator
  • a riser over pressure protection system will vent the gas overboard via the riser protection line 732 on the RFS in the event of a control system failure.
  • isolation valves 730a and 731a on the RFS are opened to allow trapped gas to be safely circulated along at least one of the flowlines 730 and 731 to the distribution manifold 770 and choke manifold 772 for gas handling.
  • Valves 774a, 774b, 774c and 774d in the distribution manifold 770 and valves 776a, 776c on the choke manifold 772 are opened to open a pathway to the RGH chokes 776b and 776d used to maintain a back pressure in the riser allowing the gas to be circulated out in a controlled manor to the MGS to capture and separate large volume of free gas from the mud. The gas once separated from the mud is then safely vented via pathway 782.
  • Figure 7 shows a flow diagram of a method of operating the RGH system during conventional drilling operations.
  • the method of operating the RGH system described in system 800 is similar to the method of operating the RGH system described in system 700 and Figure 6 and will be understood from the description of Figure 6 above.
  • the system 800 includes operation of a rotating control device (RCD) 860 connected above the quick disconnect assembly 850 and below the slip joint 814.
  • RCD rotating control device
  • the RCD 860 During managed pressure drilling operations, the RCD 860 provides a rotating internal sealing element that seals against the drill string to create a pressure-tight barrier for the purpose of controlling the pressure or fluid flow to surface.
  • a MPD Choke Manifold 868 is connected to the distribution manifold 870 and enables control of the annular pressure by increasing or decreasing the annual flow.
  • annular BOP (not shown) located on the lower riser is closed to seal around the drill string.
  • the RID 836 is closed around the drill string to isolate the upper riser system and allow any gas in the riser to be contained.
  • the gas handling method as described in Figure 6 above is followed while valve 874e on the distribution manifold 870 is isolated.
  • FIG 8 shows a schematic drawing of a riser assembly with an integrated RGH.
  • the riser assembly 900 comprises a riser 912 located between a rig platform 916 and a blowout preventer (BOP) assembly (not shown) secured to the top of the wellhead.
  • BOP blowout preventer
  • the riser 912 is connected to a slip joint 914.
  • a rig diverter 913a and flex joint 913b are located at the top of the riser assembly.
  • the slip joint 914 is configured to respond to heave movement of the platform 916 during dynamic sea conditions.
  • a portion of platform 916 is shown, which may be a floating rig or drillship.
  • the platform supports the riser assembly 900 and comprises a moon pool opening 918.
  • a plurality of tensioning cylinders 920 are secured to the platform and exert an upward force on rods or cables 922.
  • the lower end of each rod or cable 922 is connected to a riser tensioning ring 924 which is connected to maintain the stability of the riser 912 in the offshore environment.
  • the RGH system integrated on the riser assembly comprises a riser flow spool (RFS) 934 connected to the riser 912 and a riser isolation device (RID) 936 mounted above the RFS 934.
  • the RFS and RID are disposed on the riser string below the tension ring 924.
  • the RFS comprises two flexible hoses 940.
  • the tension ring 924 is connected to a tension joint 925 which is positioned between the RID 936 and the quick disconnect assembly 950.
  • the tension ring is shown connected an interface between the RID 936 and the quick disconnect assembly 950, the tension ring may be connected to other components of the riser assembly.
  • the RID 936 and RFS 934 are disposed below the tension ring 924 and the quick disconnect assembly 950 is disposed above the tension ring 924.
  • the quick disconnect assembly 950 is connected to the slip joint 914.
  • the slip joint 914 is configured to respond to heave movement of the platform 916 during dynamic sea conditions.
  • the platform 916 supports the riser 912.
  • the slip joint 914 is a telescopic three-part slip joint. However, it is appreciated that other types of slip joint may be used.
  • the slip joint enables the riser system to adjust in length as the platform heaves in response to motion of the waves.
  • Figure 9A and 9B are schematic drawings of different configurations of riser assembly with an integrated RGH system for managed pressure drilling.
  • riser assembly described in Figures 9A and 9B is similar to the configuration of the assembly in Figure 8 and will be understood from the description of Figure 8 above.
  • riser assemblies described in Figures 9A and 9B includes a rotating control device (RCD) 1060 connected above the quick disconnect assembly and below the slip joint 1014.
  • RCD rotating control device
  • the RCD 1060 By locating the RCD 1060 above the tension ring 1024 the RCD 1060 may be quickly and easily removed from the riser assembly without requiring the removal of components of the riser assembly 1000 below the tension ring 1024 or disconnecting the BOP.
  • the compact size of the RCD 1060 and the quick disconnect assembly 1050 above the tension ring 1024 enable the riser assembly to maximise the space available above the tension ring and minimise the loss of the slip joint stroke length. This facilitates marine riser assemblies to be located in areas which experience dynamic sea conditions to be converted for RGH systems.
  • the quick disconnect assembly 1050 is releasably connected to a RCD 1060.
  • the slip joint 1014 is connected to the RCD 1060.
  • the slip joint 1014 is configured to respond to heave movement of the platform 1016 during dynamic sea conditions.
  • the platform 1016 supports the riser 1012.
  • the slip joint 1014 is a telescopic three-part slip joint. However, it is appreciated that other types of slip joint may be used.
  • the slip joint enables the riser system to adjust in length as the platform heaves in response to motion of the waves.
  • the riser assembly described in Figure 9B is similar to the configuration of the assembly in Figure 9A .
  • the tension joint 1025 ( Figure 9A ) is not present.
  • the tension ring interface is a rig telescopic joint outer barrel 1027.
  • the RID 1036 and RFS 1034 are mounted on the riser 1012.
  • the rig telescopic joint outer barrel 1027 is connected above the RID 1036.
  • the tension ring 1024 is connected to rig telescopic joint outer barrel 1027.
  • the quick disconnect assembly 1050, RCD 1060 and slip joint 1014 are connected as described in Figure 9A above.
  • the RGH systems described above may be provided with a plurality of pressure sensors and/or flow meters disposes throughout the RGH system to monitor pressure and/or flow rate at various stages of the RGH system.
  • the invention provides a system for handling gas in a riser.
  • the system comprises a riser flow spool, a riser isolation device and an upper riser disconnect assembly wherein at least the riser flow spool is connected to the riser below a riser tension ring and the upper riser disconnect assembly is located above the riser tension ring.
  • the present invention provides a riser gas handling system with improved reliability and accessibility and which is capable of supporting conventional and managed pressure drilling systems.
  • the invention may facilitate the conversion of marine riser assemblies for RGH operations which enable conventional and/or managed pressure drilling operations.
  • components of the drilling or RGH operation may quickly, safely and easily installed and/or removed from the riser assembly without requiring the BOP to be disconnected and the riser string pulled to surface.
  • This configuration may allow components of a riser assembly, drilling system or RGH system to be installed only when they are required.
  • the invention facilitates the easy and efficient installation and/or recovery of drilling operation components such as a RCD from the upper riser assembly while reducing and/or minimising a loss of stroke length in a slip joint provided above the tension ring. This improves the ability of the riser assembly to withstand dynamic heave conditions.
  • Embodiments of the invention may provide improved hose management as the hoses and control lines connected to at least the RFS may be vertically offset from the tensioning system by being located below the tension ring. By positioning the RFS hoses under the tension ring they are not hindered by the tensioning cylinders or rods connected to the tension ring.

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  • Engineering & Computer Science (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Mechanical Engineering (AREA)
  • Earth Drilling (AREA)
  • Filling Or Discharging Of Gas Storage Vessels (AREA)

Claims (16)

  1. Un ensemble de colonne montante (100, 200, 300, 400, 500, 600, 700, 800, 900, 1000) comprenant :
    une bobine d'écoulement de colonne montante (134, 234, 334, 434, 534, 634, 734, 834, 934,1034) ;
    un dispositif d'isolement de colonne montante (136, 236, 336, 436, 536, 636, 736, 836, 936,1036) et
    un ensemble de déconnexion de colonne montante supérieure (150, 250, 350, 450, 550, 650, 750, 850, 950,1050) ; dans lequel au moins la bobine d'écoulement de colonne montante est située sur une colonne montante (112, 212, 312, 412, 512, 612, 712, 812, 912, 1012), en dessous d'un anneau de tension de colonne montante (124, 224, 324, 424, 524, 624, 724, 824, 924,1024), et dans lequel l'ensemble de déconnexion de colonne montante supérieure est situé au-dessus de l'anneau de tension de colonne montante.
  2. L'ensemble de colonne montante (100, 200, 300, 400, 500, 600, 700, 800, 900, 1000) de la revendication 1, dans lequel le dispositif d'isolement de colonne montante (136, 236, 336, 436, 536, 636, 736, 836, 936,1036) est configuré pour être connecté à la colonne montante (112, 212, 312, 412, 512, 612, 712, 812, 912, 1012) en dessous de l'anneau de tension (124, 224, 324, 424, 524, 624, 724, 824, 924,1024).
  3. L'ensemble de colonne montante (100, 200, 300, 400, 500, 600, 700, 800, 900, 1000) de la revendication 1 ou de la revendication 2, dans lequel l'ensemble de déconnexion de colonne montante supérieure (150, 250, 350, 450, 550, 650, 750, 850, 950,1050) est configuré pour être connecté de manière amovible à un dispositif de commande rotatif (260, 660, 860, 1060).
  4. L'ensemble de colonne montante (100, 200, 300, 400, 500, 600, 700, 800, 900, 1000) de la revendication 3, dans lequel le dispositif de commande rotatif (260, 660, 860, 1060) est disposé au-dessus de l'ensemble de déconnexion de colonne montante supérieure et/ou dans lequel l'ensemble de déconnexion de colonne montante supérieure (150, 250, 350, 450, 550, 650, 750, 850, 950,1050) est disposé en dessous d'un raccord coulissant (114, 214, 314, 414, 514, 614, 714, 814, 914, 1014).
  5. L'ensemble de colonne montante (100, 200, 300, 400, 500, 600, 700, 800, 900, 1000) de l'une des revendications précédentes, dans lequel la bobine d'écoulement de colonne montante (134, 234, 334, 434, 534, 634, 734, 834, 934,1034) comprend au moins une conduite d'écoulement (730, 731, 732), dans lequel au moins une conduite d'écoulement est configurée pour être connectée à un ensemble de distribution (770), un ensemble d'étranglement (772), une soupape de sécurité et/ou un séparateur boue-gaz (780).
  6. L'ensemble de colonne montante (100, 200, 300, 400, 500, 600, 700, 800, 900, 1000) de l'une des revendications précédentes, dans lequel l'ensemble de déconnexion de colonne montante supérieure (150, 250, 350, 450, 550, 650, 750, 850, 950,1050) comprend un connecteur supérieur et un connecteur inférieur, dans lequel les connecteurs supérieur et inférieur sont configurés pour se déconnecter l'un de l'autre.
  7. Un système de traitement du gaz dans une colonne montante (112, 212, 312, 412, 512, 612, 712, 812, 912, 1012) comprenant l'ensemble de colonne montante (100, 200, 300, 400, 500, 600, 700, 800, 900, 1000) de l'une des revendications 1 à 6.
  8. Un procédé d'installation d'un système de traitement du gaz dans une colonne montante sous-marine (112, 212, 312, 412, 512, 612, 712, 812, 912, 1012) consistant à :
    installer un ensemble de bobine d'écoulement de colonne montante sur la colonne montante, en dessous de l'anneau de tension (124, 224, 324, 424, 524, 624, 724, 824, 924,1024) ; et
    installer un ensemble de déconnexion de colonne montante supérieure (150, 250, 350, 450, 550, 650, 750, 850, 950,1050) au-dessus de l'anneau de tension.
  9. Le procédé de la revendication 8, consistant à installer un dispositif d'isolement de colonne montante (136, 236, 336, 436, 536, 636, 736, 836, 936,1036) en dessous de l'anneau de tension (124, 224, 324, 424, 524, 624, 724, 824, 924,1024).
  10. Le procédé de l'une des revendications 8 à 9, consistant à installer un dispositif de commande rotatif (260, 660, 860, 1060) au-dessus de l'anneau de tension (124, 224, 324, 424, 524, 624, 724, 824, 924,1024) pour permettre un forage sous-marin à pression contrôlée.
  11. Un procédé de conversion d'une colonne montante marine pour les opérations de traitement du gaz dans une colonne montante consistant à :
    installer l'ensemble de colonne montante (100, 200, 300, 400, 500, 600, 700, 800, 900, 1000) de l'une des revendications 1 à 6.
  12. Un procédé de traitement du gaz dans une colonne montante sous-marine consistant à :
    fournir un ensemble de colonne montante (100, 200, 300, 400, 500, 600, 700, 800, 900, 1000) comprenant :
    une bobine d'écoulement de colonne montante (134, 234, 334, 434, 534, 634, 734, 834, 934,1034) ;
    un dispositif d'isolement de colonne montante (136, 236, 336, 436, 536, 636, 736, 836, 936,1036) et
    un ensemble de déconnexion de colonne montante supérieure (150, 250, 350, 450, 550, 650, 750, 850, 950,1050) ;
    dans lequel la bobine d'écoulement de colonne montante est située sur une colonne montante (112, 212, 312, 412, 512, 612, 712, 812, 912, 1012), en dessous d'un anneau de tension de colonne montante (124, 224, 324, 424, 524, 624, 724, 824, 924,1024), et dans lequel l'ensemble de déconnexion de colonne montante supérieure est situé au-dessus de l'anneau de tension de colonne montante ; et
    consistant à
    actionner le dispositif d'isolement de colonne montante pour fermer la colonne montante au-dessus de la bobine d'écoulement de colonne montante et actionner la bobine d'écoulement de colonne montante pour dévier le gaz piégé en dessous du dispositif d'isolement de colonne montante.
  13. Le procédé de la revendication 12, consistant à fournir un dispositif de commande rotatif (260, 660, 860, 1060) au-dessus de l'anneau de tension de colonne montante pendant les opérations de forage sous-marin à pression contrôlée.
  14. Un procédé d'installation d'un dispositif de commande rotatif (260, 660, 860, 1060) dans une colonne montante (112, 212, 312, 412, 512, 612, 712, 812, 912, 1012) avec un dispositif de commande rotatif de récupération ou de traitement du gaz dans une colonne montante consistant à :
    fournir un ensemble de colonne montante (100, 200, 300, 400, 500, 600, 700, 800, 900, 1000) comprenant
    une bobine d'écoulement de colonne montante (134, 234, 334, 434, 534, 634, 734, 834, 934,1034) ;
    un dispositif d'isolement de colonne montante (136, 236, 336, 436, 536, 636, 736, 836, 936,1036) ; et
    un ensemble de déconnexion de colonne montante supérieure (150, 250, 350, 450, 550, 650, 750, 850, 950,1050) ;
    dans lequel au moins la bobine d'écoulement de colonne montante est connectée à la colonne montante en dessous d'un anneau de tension de colonne montante et dans lequel l'ensemble de déconnexion de colonne montante supérieure est connecté à la colonne montante au-dessus de l'anneau de tension ; et consistant à connecter un dispositif de commande rotatif (260, 660, 860, 1060) à l'ensemble de déconnexion de colonne montante supérieure pour installer le dispositif de commande rotatif dans la colonne montante ; ou
    déconnecter un dispositif de commande rotatif de la colonne montante au-dessus de l'anneau de tension pour récupérer le dispositif de commande rotatif de la colonne montante.
  15. Le procédé de la revendication 14, consistant à fermer un bloc obturateur sur la colonne montante (112, 212, 312, 412, 512, 612, 712, 812, 912, 1012) avant de connecter ou de déconnecter le dispositif de commande rotatif (260, 660, 860, 1060).
  16. Le procédé de la revendication 14 ou de la revendication 15, consistant à actionner l'ensemble de déconnexion de colonne montante supérieure (150, 250, 350, 450, 550, 650, 750, 850, 950,1050) pour connecter le dispositif de commande rotatif (260, 660, 860, 1060) à l'ensemble de colonne montante ou pour l'en déconnecter.
EP17780853.2A 2016-09-02 2017-09-01 Système de prise en charge des gaz dans une colonne montante et son procédé d'utilisation Active EP3507444B1 (fr)

Applications Claiming Priority (2)

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GBGB1614974.2A GB201614974D0 (en) 2016-09-02 2016-09-02 Riser gas handling system and method of use
PCT/GB2017/052547 WO2018042186A1 (fr) 2016-09-02 2017-09-01 Système de prise en charge des gaz dans une colonne montante et son procédé d'utilisation

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EP (1) EP3507444B1 (fr)
AU (1) AU2017319228A1 (fr)
BR (1) BR112019004222B1 (fr)
CA (1) CA3062822A1 (fr)
GB (2) GB201614974D0 (fr)
MY (1) MY195005A (fr)
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US11118421B2 (en) * 2020-01-14 2021-09-14 Saudi Arabian Oil Company Borehole sealing device
US11428069B2 (en) * 2020-04-14 2022-08-30 Saudi Arabian Oil Company System and method for controlling annular well pressure
US11332987B2 (en) * 2020-05-11 2022-05-17 Safekick Americas Llc Safe dynamic handover between managed pressure drilling and well control

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MY195005A (en) 2022-12-30
BR112019004222A2 (pt) 2019-05-28
US20190195032A1 (en) 2019-06-27
GB201714051D0 (en) 2017-10-18
WO2018042186A1 (fr) 2018-03-08
CA3062822A1 (fr) 2018-03-08
GB2554546B (en) 2019-12-04
GB2554546A (en) 2018-04-04
AU2017319228A1 (en) 2019-05-02
SG11201910126TA (en) 2019-11-28
GB201614974D0 (en) 2016-10-19
EP3507444A1 (fr) 2019-07-10
BR112019004222B1 (pt) 2023-04-18

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