DK202101018A1

DK202101018A1 - Subsea well head assembly for use in riserless drilling operations

Info

Publication number: DK202101018A1
Application number: DKPA202101018A
Authority: DK
Inventors: Engelbrecht Hansen Kristian
Original assignee: Noble Drilling As
Priority date: 2021-10-28
Filing date: 2021-10-28
Publication date: 2023-05-04

Abstract

A subsea well head assembly for use in riserless drilling operations is adapted for enclosing a tubular (20) and comprising a Rotating Control Device (60) and a blowout preventer (40). The Rotating Control Device (60) is adapted for sealing the tubular running (20) while the tubular (20) moves. The blowout preventer (40) is adapted for preventing a blowout from a well bore operated by the tubular (20). A flex joint (50) is provided in between the Rotating Control Device (60) and the blowout preventer (40) enabling the Rotating Control Device (60) to align with the tubular (20).

Description

SUBSEA WELL HEAD ASSEMBLY FOR USE IN RISERLESS DRILLING OPERATIONS

The invention relates to a subsea well head assembly for use in riserless drilling operations and being adapted for enclosing a tubular, the subsea well head assembly comprises a Rotating Control

Device (RCD) and a blowout preventer (BOP).

BACKGROUND OF THE INVENTION

In offshore drilling, risers serve to move fluids from the sea floor to an offshore drilling unit on the sea surface. A well head assembly is connected to a marine riser having several functionalities, namely to serve as a return conduit for drilling fluid coming from well, to be used for attachment of rigid choke and kill lines that must be in place between a Subsea BOP and a drilling rig for well control, to handle the subsea BOP relatively to the wellhead on the seabed, and to avoid pollution during drilling. On top of the well head assembly, a flex joint allows the riser to bent relatively to the well head assembly, and thereby release stress acting on the well head assembly due to sea originated forces acting on riser.

Over the past decades, riserless solutions have been discussed e.g. by US 20130126182 Al. The well head assembly in riserless configurations comprises a blowout preventer adapted for preventing a blowout from a well bore and a Rotating Control Device (RCD) being adapted for sealing a tubular during operation. The RCD may be adapted to divert drill fluid for return to a rig via a mud return pipe.

Forces acting on the tubular will cause stress on the well head assembly. For the connected condition while tripping or drilling, the rigs operating offset will be restricted by an allowable angle between tubular and RCD defined by yielding of tubular. Such allowable angles may be up to 2-3 degrees. This may be problematic for rigs operating on shallow water.

The RCD is used for sealing off the well on top of the BOP. Tubulars, such as drilling or tripping drill pipes or casings passes through the RCD. For the connected condition while tripping or drilling the rigs operating offset will be restricted by an allowable angle between the tubular and RCD defined by yielding of the tubular.

The purpose of the invention is to make the well head assembly in a riserless configuration more robust.

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SUMMARY OF THE INVENTION

This purpose is according to the invention achieved by a subsea well head assembly for use in riserless drilling operations as defined in claim 1, a method of performing riserless drilling operations by using a well head assembly as defined in claim 10, a blowout preventer for use in a subsea well head assembly as defined in claim 12, and a Rotating Control Device for use in a subsea well head assembly adapted for riserless drilling operations as defined in claim 13. Preferred embodiments are defined in the dependent claims.

According to the invention, a flex joint is provided between the RCD and the BOP. The BOP may be a hydraulic or conventional BOP or an electrical BOP. This configuration which enables the RCD to follow the drilling angle defined by the tubular through RCD and BOP. By letting the flex joint taking up that relative angle between the tubular and the RCD, bending stress in the tubular will be reduced and further provides better sealing conditions for the RCD to seal around the tubular.

According to one aspect of the invention, the flex joint is provided as an integral element of the blowout preventer for use in a subsea well head assembly adapted for enclosing a tubular and adapted for riserless drilling operations. The blowout preventer (BOP) being adapted for preventing a blowout from a well bore operated by a tubular. The BOP has a housing element being integral with a lower housing element of a flex joint. An upper housing element of the flex joint is prepared for connecting to an RCD. The flex joint allows the upper housing element, and thereby the RCD, to align with the tubular.

By letting the flex joint taking up that relative angle between the tubular and the RCD, bending stress in the tubular will be reduced and further provides better sealing conditions for the RCD to seal around the tubular. Furthermore, by integrating the BOP and the flex joint into a single coherent component, the benefits may be obtained with a minimum extra building height as connector elements may be saved. — According to a further aspect of the invention, the flex joint is provided as an integral element of the Rotating Control Device (RCD) for use in a subsea well head assembly adapted for riserless drilling operations. The RCD comprises a housing enclosing a sealing element for sealing a tubular, and a connector element for connecting the RCD to a BOP. The RCD further comprises a flex joint having an upper housing element integral with the housing and a lower housing element integral with the connector element.

By letting the flex joint taking up that relative angle between the tubular and the RCD, bending stress in the tubular will be reduced and further provides better sealing conditions for the RCD to seal around the tubular. Furthermore, by integrating the RCD and the flex joint into a single coherent component, the benefits may be obtained with a minimum extra building height as connector elements may be saved.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention will be described in further details with reference to preferred aspects and the accompanying drawing, in which:

Fig. 1 illustrates schematically a floating vessel performing a riserless drilling operation according to an embodiment of the invention;

Fig. 2 illustrates schematically one embodiment of a well head assembly according to the invention;

Fig. 3 illustrates schematically a blowout preventor (BOP) for use in riserless drilling operation according to an embodiment of the invention;

Fig. 4 illustrates schematically a flex joint for use in riserless drilling operation according to an embodiment of the invention;

Fig. 5 illustrates schematically a rotating control device (RCD) for use in riserless drilling operation according to an embodiment of the invention;

Fig. 6 illustrates schematically a blowout preventor (BOP) with integrated flex joint according to an embodiment of the invention; and

Fig. 7 illustrates schematically a rotating control device (RCD) with integrated flex joint according to an embodiment of the invention.

DETAILED DESCRIPTION

Fig. 1 illustrates schematically a floating vessel 10 performing a riserless drilling or maintenance operation according to one embodiment of the invention. The vessel 10 is in the illustrated embodiment a so-called semi-sub. The vessel 10 is floating on the surface 11 of the sea and has a hull 12 carrying a derrick 14 and a drill deck defining one or more well centers 16. The vessel 10 has at least two submerged, ballasted, watertight pontoons 18.

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The riserless drilling operation is based on Riserless Mud Recovery (RMR) technology with one or more subsea pump 28 provided on seabed 21. By means of the subsea pump 28, well cuttings are moved away from a subsea template, which allows drill mud and cuttings to be returned from a subsea wellhead 31 (shown in fig. 2) to the vessel 10 via the subsea pump 28. The Riserless Mud

Recovery (RMR) technology may be used on vessels like e.g. jack-up and floater rigs.

The riserless drilling operation is operated from the well center 16, from where a tubular, such as a drillstring 20, extends via a well head assembly 25 down to a subsea well 30. Mud is pumped by a mud pumping system present on the drill deck via the drillstring 20 down into the drilled subsea well 30. In the well 30, the drillstring 20 rotates the bottom hole assembly (BHA) or the drill bit 34.

By using the RMR technology cuttings from the drill bit 34 and mud is diverted from the well head assembly 25 via a return mud tube 22 and pumped back to vessel 10 with the subsea pump 28.

Tubular running refers to a generic process of handling tubulars on a rig, lowering tubulars to the well and installing casing accessories. Tubulars are stocked up on the rig (and replenished as required) prior to being run into the well.

For operation on shallow water, the return mud tube 22 may be a flexible liquid-tight hose bringing mud and cuttings to the vessel for separation, and subsequently recirculating the mud. For deep water operation, the return mud tube 22 may be a steel pipe assembled by multiple pipe elements.

For shallow water operation, the mud pumps on the drill floor may be sufficient to drive the mud circulation, why the subsea pump 28 may be omitted.

By using a riserless drilling operation technique for well construction, the drilling operator may obtain several benefits due to the reduced weight the hoisting system on the drill floor must handle.

This may improve wellbore stability, reduce volumes of circulated drilling fluid, reduce volumes of cement used in the well construction, reduce the drilling time and the logistics costs.

The reduced weight lifted by the hoisting system may reduce the required capacity of the hoisting system, or increase the depths on which the vessel 10 is able to operate.

The well head assembly 25 will be described in greater details with reference to fig. 2. As seen, the well head assembly 25 is mounted on top of the well head 31 just above the seabed 21. The well head 31 is the upper termination of the drilled well 30. The well head assembly 25 comprises a blowout preventer (BOP) 40 and a Rotating Control Device (RCD) 60. The BOP 40 has a connector — 41for connecting to the well head 31.

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In one embodiment, high-pressure lines (choke and kill lines) are attached to the return mud tube 22, and these high-pressure lines allows fluids to be pumped into or removed from the well with the BOP 40 s closed. The choke and kill lines are connected to the well head assembly 25 and controlled from the surface vessel 10. The choke and kill lines are used to circulate fluids into and out of the wellbore to control well pressure. In parallel to the return mud tube 22, an umbilical is present to enable communication between a control room on the vessel 19 and the subsea equipment present in the well head assembly 25 whereby the subsea equipment may be controlled from the surface vessel 10.

The tubular 20 passes through the well head assembly 25 and down to the well 30. According to the invention, a flex joint 50 is provided in between the RCD 60 and the BOP 40. This enables the

RCD 60 to align with the tubular 20.

As illustrated schematically in fig. 2 and greater details in an embodiment shown in fig. 5, the RCD 60 comprises a guiding funnel 61 ending in an opening for guiding the tubular 20 when received.

Furthermore, the RCD 60 has a sealing element 62 for sealing the tubular 20, and a housing 64, and a mud outlet 63 for diverting fluids to the return mud tube 22. Furthermore, the RCD 60 includes bearing 66 for positioning the tubular 20, and a connector element 65 for mounting the RCD 60 to the flex joint 50.

In some embodiments, the RCD 60 comprises at least one outlet 63 for diverting wellbore fluids from the well bore 30 and being adapted for providing a closed-loop environment to contain and divert fluids and to enable wellbore pressure management in a closed-loop drilling (CLD) system.

In some embodiments, the sealing element 62 includes hydraulic control for obtaining a required sealing force towards the tubular 20.

The RCD 60 is a pressure-control device used during drilling for the purpose of making a seal around the tubular 20 while the tubular 20 moves, either by rotation or by axial movement. This device is intended to create a pressure-tight barrier against drilling hazards, such as to contain hydrocarbons or other wellbore fluids and prevent their release to the environment. The RCD 60 is a critical component of any closed-loop drilling (CLD) system, in which the RCD 60 creates a closed-loop environment to contain and divert fluids and to enable wellbore pressure management. The sealing element 62 is adapted for sealing the rotating tubular running 20, and being adapted for creating a pressure-tight barrier for wellbore fluids contained and for preventing their release to the surroundings.

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The bearings 66 of the RCD 60 includes in some embodiments axial-radial cylindrical bearings providing low-torque rotation and load support. In some embodiments, the sealing element 62 of

RCD 60 is manufactured from natural rubber, nitrile, butyl, or urethane. The sealing element 62 may be hydraulically controlled. The RCD 60 isolates the environment from potentially harmful wellbore fluids and gases during drilling operations and diverts drilling fluids and cuttings to solids control equipment.

As illustrated schematically in fig. 2 and greater details in an embodiment shown in fig. 4, the flex joint 50 has a first mounting flange or connector element 51 for connecting the flex joint 50 to the

RCD 60, and a second mounting flange or connector element 58 for connecting the flex joint 50 to the BOP 40. The flex joint 50 comprises a top part 52 and a lower part 54. The top part 52 and the lower part 54 has sets of interacting spheric surfaces 55 permitting a longitudinal axis 23 of a lower part of the well head assembly 25 to vary relatively to a longitudinal axis 24 of an upper part of the well head assembly 25. In fig. 4, the top part 52 and the lower part 54 are shown aligned, but for illustrative purposes the longitudinal axis 24 is tilted relatively to the longitudinal axis 23 for indicating the purpose of the flex joint 50, namely to permit the longitudinal axis 24 to tilt relatively to the longitudinal axis 23.

The indication of the longitudinal axis 24 may be seen as the maximum deflection of the top part 52 relatively to the longitudinal axis 23.

The lower part 54 and a locking part 53 are connected to each other via a biasing package ring or an elastomeric flex element 57. Hereby the lower part 54 and the locking part 53 are flexible relatively to each other when sufficient forces are applied. The spheric surface of the upper part 52 is received in a bowl 56, and the locking part 53 and the upper part 52 are bolted together. When no forces are acting on the tubing 20, the two longitudinal axes 23 and 24 will be aligned.

In some embodiments, the flex joint 50 is a steel and elastomer assembly having a central through- passage equal to or greater in diameter than the diameter of the tubular 20. The flex joint 50 may be positioned in the well head assembly 25 to reduce local bending stresses. In other embodiments, the flex joint 50 is a laminated metal and elastomer assembly, having a central through-passage equal to or greater in diameter than the interfacing pipe or tubing bore, to permit relative angular movement of the tubular 20 and reduce stresses due to vessel motion and environmental forces.

When the tubing 20 performs drilling operations in the well 30, the tubing 20 rotates and is driven downwards in longitudinal direction as passing through the well head assembly 25. While tripping,

, DK 2021 01018 A1 the tubing 20 is moved in longitudinal direction when passing through the well head assembly 25.

The blowout preventer 40 is adapted for preventing a blowout from a well bore operated by the tubular 20, no matter whether the tubing 20 is used for drilling, is tripping or is out of the well.

Fig. 3 shows the blowout preventer (BOP) 40. The BOP 40 has a connector 41 or connector flange for connecting to the BOP 40 to the well head 31, and a connector or connector flange 45 for connecting to the BOP 40 to the flex joint 50. The BOP 40 has a set of pipe rams 42, a set of blind- shear rams 43, and an annular preventer 44. These valve components, the set of pipe rams 42, the set of blind-shear rams 43, and the annular preventer 44, are attached to a vertical tower element 46 extending between the connectors 41 and 45.

In one embodiment, the blowout preventer 40 comprises at least one of the following one set of blind-shear rams 42, one set of pipe rams 43, and an annular preventer 44. In another embodiment, the blowout preventer 40 comprises one set of blind-shear rams 42, one set of pipe rams 43, and an annular preventer 44.

The set of pipe rams 42 are adapted for isolating the annular space by wrapping around the tubular — when closed, and must be capable of closing and sealing on the tubular body of any drill pipe, workstring, and tubing under maximum anticipated surface pressure. The set of blind-shear rams 43 are adapted to seal the wellbore by cutting through the drill string as the rams close off the well.

The Annular preventer 44 is a ring-shaped piece of equipment on the top of the valve stack of the blowout preventer (BOP) 40 and is used to prevent flow through the annular space between the drill string or casing and the annular preventer. The annular preventer may include a doughnut shaped bladder that when in the open position allows the drill pipe to rotate but in the closed position seals the annulus.

Fig. 6 illustrates schematically a Blow-Out Preventor (BOP) 40 with integrated flex joint 50 according to an embodiment of the invention and is in this context named a BOP with flex joint 70. The BOP with flex joint 70 has a connector 41 for connecting to the well head 31. The BOP with flex joint 70 has a set of pipe rams 42, a set of blind-shear rams 43, and an annular preventer 44 attached to a vertical tower element 46. According to this embodiment, the vertical tower element 46 is integral with a lower housing element 54* of the flex joint. The lower housing element 54* is terminated to the upper part of the flex joint as discussed with reference to fig. 4. This means that the lower housing element 54% and a locking part are connected to each other via an elastomeric flex element.

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Hereby the lower part 54 and the locking part 53 are flexible relatively to each other when sufficient forces are applied. The spheric surface 55 of the upper part 52 is received in a bowl 56, the locking part 53 and the upper part 52 are bolted together. The top part and the lower part of the flex joint has sets of interacting spheric surfaces 55 permitting a longitudinal axis 23 of a lower part of the well head assembly 25 to vary relatively to a longitudinal axis 24 of an upper part of the well head assembly 25. The vertical tower element 46 is integral with a lower housing element 54% of the flex joint of the combined BOP with flex joint 70, whereby the connector element 58 (fig. 4) and the connector or connector flange 45 (fig. 3) may be saved and a lower building height may be obtained.

Fig. 7 illustrates in cross-section a Rotating Control Device (RCD) 60 with integrated flex joint 50 according to an embodiment of the invention and is in this context named an RCD with flex joint 80. The RCD with flex joint 80 has a connector element 58 for connecting to the BOP 40. The RCD with flex joint 80 has a flex joint section comprising an upper housing element 52% and a lower part 54. The upper housing element 52% and the lower part 54 has sets of interacting spheric surfaces 55 permitting longitudinal axes 23 and 24 of the upper and lower part of the well head assembly 25 to vary. The upper housing element 52% and the lower part 54 are shown aligned, but for illustrative purposes the longitudinal axis 24 of the upper housing element 52% is shown tilted relatively to the longitudinal axis 23 of the lower part 54 for indicating the purpose of the flex joint, namely to permit the longitudinal axis 24 to tilt relatively to the longitudinal axis 23.

The lower part 54 and a locking part 53 are connected to each other via a biasing package ring or an elastomeric flex element 57. Hereby the lower part 54 and the locking part 53 are flexible relatively to each other when sufficient forces are applied. The spheric surface 55 of the upper housing element 52% is received in a bowl 56, whereafter the locking part 53 and the upper housing element 52% are bolted together. The housing 64 of the RCD is integral with a upper housing element 52% of the flex joint of the combined RCD with flex joint 80, whereby the mounting flange — 51 (fig. 4) and the connector or connector element (fig. 5) may be omitted and an overall lower building height may be obtained. The RCD with flex joint 80 has a sealing element 62 for sealing the tubular 20, and bearings 66 for positioning the tubular 20.

The indication of the longitudinal axis 24 may be seen as the maximum deflection of the upper housing element 52% relatively to the longitudinal axis 23.

The flex joint constitutes an integrated part of the RCD 80 as the upper housing element 52% is integral with the housing 64 and a lower housing element 54 is integral with the connector element 58.

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In one embodiment, the sealing element 62 is adapted for creating a pressure-tight barrier for wellbore fluids contained and for preventing their release to the surroundings. In one embodiment, at least one outlet 63 for diverting wellbore fluids contained in the well head assembly 25. Hereby, the RCD 80 is adapted for being part of a closed-loop environment to contain and divert fluids and to enable wellbore pressure management in a closed-loop drilling (CLD) system.

In one embodiment, the bearings 66 are provided as axial-radial cylindrical bearings for providing low-torque rotation and load support for the tubular. In one embodiment, the sealing element 62 in provided in natural rubber, urethane, nitrile, or butyl.

According to the invention, there is provided a method of performing riserless drilling operations.

Riserless drilling operations may be performed by using tubulars, such as drilling or tripping drill pipes or casings, when establishing new wells or when making workover or well intervention on existing wells involving invasive techniques, such as wireline, coiled tubing or snubbing. According to the invention, a well head assembly 25 being adapted for enclosing the tubular 20 is used. The well head assembly 25 comprises an RCD 60 and a BOP 40. A flex joint 50 is provided in between the RCD 60 and the BOP 40. Riserless drilling operations are performed in the well by means of the tubular 20, and the tubular 20 extending from the well head assembly 25 is sealed by means of the

RCD 60. According to the invention, the flex joint 50 allow the RCD 60 to align to the tubular 20 above the well head to reduce stress on the RCD caused by sea originated forces acting on the on the tubing 20. According to the invention, the method includes diverting of wellbore fluids contained from the RCD 60 through at least one outlet 63 for providing a closed-loop environment to contain and divert fluids and to enable wellbore pressure management in a closed-loop drilling (CLD) system.

Claims

1. A subsea well head assembly for use in riserless drilling operations, the well head assembly (25) being adapted for enclosing a tubular (20), the subsea well head assembly comprising a Rotating Control Device (60) and a blowout preventer (40), - the Rotating Control Device (60) being adapted for sealing the tubular (20) while the tubular (20) moves; and - the blowout preventer (40) being adapted for preventing a blowout from a well bore operated by the tubular (20); - wherein in that a flex joint (50) is provided in between the Rotating Control Device (60) and the blowout preventer (40) enabling the Rotating Control Device (60) to align with the tubular (20).

2. The well head assembly according claim 1, wherein the blowout preventer (40) comprises at least one of the following: - one set of blind-shear rams (42), - one set of pipe rams (43), and - an annular preventer (44).

3. The well head assembly according claim 2, wherein the blowout preventer (40) comprises one set of blind-shear rams (42), one set of pipe rams (43), and an annular preventer (44).

4. The well head assembly according claim 1, wherein the Rotating Control Device (60) comprises a sealing element (62) for sealing the tubular (20), and being adapted for creating a pressure-tight barrier for wellbore fluids contained and for preventing their release to the surroundings.

5. The well head assembly according claim 1, wherein the Rotating Control Device (60) comprises at least one outlet (63) for diverting wellbore fluids contained in the tubular (20), whereby the Rotating Control Device (60) is adapted for providing a closed-loop environment to contain and divert fluids and to enable wellbore pressure management in a closed-loop drilling (CLD) system.

6. The well head assembly according claim 1, wherein the Rotating Control Device (60) has a housing (64), and wherein an upper housing element (52*) of the flex joint (50) is integral with the housing (64) of the Rotating Control Device (60).

7. The well head assembly according claim 1, wherein the bearing element (66) comprises axial- radial cylindrical bearings for providing low-torque rotation and load support for the tubular (20).

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8. The well head assembly according claim 1, wherein the sealing element (62) in provided in natural rubber, urethane, nitrile, or butyl.

9. The well head assembly according claim 1, wherein the blowout preventer (40) has a housing element (46), and wherein a lower housing element (54%) of the flex joint (50) is integral with the housing element (46) of the blowout preventer (40).

10. A method of performing riserless drilling operations by using a well head assembly (25) being adapted for enclosing a tubular (20) and comprising a Rotating Control Device (60) and a blowout preventer (40) being adapted for preventing a blowout from a well operated by the tubular (20), - providing a flex joint (50) in between the Rotating Control Device (60) and the blowout preventer (40) - performing riserless drilling operations in the well by means of the tubular (20), - sealing the tubular (20) extending from the well head assembly (25) by means of the Rotating Control Device (60), - aligning the Rotating Control Device (60) to the tubular (20) to reduce sea originated forces acting on the Rotating Control Device (60).

11. A method according to claim 10, wherein the method further comprises diverting wellbore fluids from the Rotating Control Device (60) through at least one outlet (63) for providing a closed- loop environment to contain and divert fluids and to enable wellbore pressure management in a closed-loop drilling (CLD) system.

12. A blowout preventer (70) for use in a subsea well head assembly adapted for enclosing a tubular (20) and adapted for riserless drilling operations, - the blowout preventer (70) being adapted for preventing a blowout from a well bore operated by the tubular (20); - the blowout preventer (70) has a housing element (46) being integral with a lower housing element (54%) of a flex joint; - wherein an upper housing element (52) of the flex joint is prepared for connecting to a Rotating Control Device (70); - whereby the flex joint allows the upper housing element (52), and thereby the Rotating Control Device (70), to align with the tubular (20).

13. A Rotating Control Device (80) for use in a subsea well head assembly adapted for riserless drilling operations, and comprising: - a housing (64) enclosing a sealing element (62) for sealing a tubular (20); - a connector element (58) for connecting the Rotating Control Device (80) to a blowout preventer (40); - wherein the Rotating Control Device (80) further comprises a flex joint having an upper housing element (52%) integral with the housing (64) and a lower housing element (54) integral with the connector element (58).

14. The Rotating Control Device (80) according claim 13, wherein the sealing element (62) is adapted for creating a pressure-tight barrier for wellbore fluids contained and for preventing their release to the surroundings.

15. The Rotating Control Device (80) according claim 13, and further comprising at least one outlet (63) for diverting wellbore fluids contained in the tubular (20), whereby the Rotating Control Device (80) is adapted for providing a closed-loop environment to contain and divert fluids and to enable wellbore pressure management in a closed-loop drilling (CLD) system.

16. The Rotating Control Device (80) according claim 13, and further comprising axial-radial cylindrical bearings (66) for providing low-torque rotation and load support for the tubular (20).

17. The Rotating Control Device (80) according claim 13, wherein the sealing element (62) in provided in natural rubber, urethane, nitrile, or butyl.