OFFSHORE DRILLING APPARATUS AND METHODS

Abstract

An offshore method includes providing an elongate support string for extending between a mobile offshore drilling unit and a seabed location. The string has an upper portion and a lower portion, and an articulated joint is provided between the upper portion and the lower portion. The provision of the articulated joint maintains the lower portion of the elongate support string in a substantially vertical orientation and increases the safe operating radius of the mobile offshore drilling unit or increases the speed at which the unit may transit through the sea with objects suspended via the elongate support string.

Claims

1. An offshore method comprising: providing an elongate support string for extending between a mobile offshore drilling unit and a seabed location, the string having an upper portion and a lower portion; providing an articulated joint between the upper portion and the lower portion of the elongate support string, and rotating the elongate support string and transferring torque between the upper and lower portions of the elongate support string while maintaining the lower portion of the elongate support string in a substantially vertical orientation.

2. The method of claim 1, wherein the elongate support string extends through open water and through a drilling riser or other structure.

3. (canceled)

4. The method of claim 1, further comprising: supporting a tool on the support string, which tool may comprise at least one of: a drill bit; a jetting assembly, and a bottom hole assembly (BHA); and providing the articulated joint between the support string and the tool.

5. (canceled)

6. The method of claim 4, further comprising at least one of: lowering the tool onto the seabed, onto, into or through an assembly or structure on the seabed, or into a bore hole extending below the seabed.

7. The method of claim 4, further comprising creating a new bore hole extending below the seabed.

8. The method of claim 4, further comprising pulling, lifting, or retrieving a tool from the seabed, from or through an assembly or structure on the seabed, or from or through a bore hole extending below the seabed.

9. The method of claim 1, further comprising providing a through bore in the support string and the articulated joint and passing a tool or fluid through the string and the joint.

10. The method of claim 1, further comprising moving the mobile offshore drilling unit across a body of water with the elongate support member suspended from the unit.

11. The method of claim 1, further comprising supporting a conductor on the support string, optionally jetting the supported conductor through the seabed to target depth, and further optionally providing a drill bit on the support string and drilling the bore beyond the end of the conductor.

12. The method of claim 1, further comprising providing the articulated joint in a first configuration permitting articulation and providing the articulated joint in a second configuration restricting articulation.

13. The method of claim 1, comprising configuring the articulated joint to restrict a maximum degree of articulation available between the portions of the support string.

14. An apparatus for use in offshore drilling operations comprising: an elongate support string for extending between a mobile offshore drilling unit and a seabed location, the string comprising a tubular drill string formed of multiple drill pipe sections and having an upper portion and a lower portion, and with a bore-forming assembly mounted on a lower end of the lower portion, and an articulated joint between the upper portion and the lower portion of the elongate support string, whereby the articulated joint facilitates maintaining the lower portion of the elongate support string in a substantially vertical orientation.

15. The apparatus of claim 14, wherein the bore-forming assembly comprises at least one of a drill bit and a jetting assembly.

16. The apparatus of claim 14, comprising at least two articulated joints.

17. The apparatus of claim 14, wherein at least one articulated joint is provided intermediate the ends of the support string.

18. The apparatus of claim 14, wherein at least one articulated joint is provided at an end of the support string.

19. The apparatus of claim 14, comprising an articulated joint provided between the support string and a subsea or downhole tool.

20. The apparatus of claim 14, wherein the support string and the articulated joint define a through bore to permit the passage of tools or fluid.

21. The apparatus of claim 14, wherein the articulated joint is adjustable to restrict the maximum degree of articulation between the portions of the support string.

22. The apparatus of claim 14, wherein the articulated joint is configurable to prevent any pivoting or articulation between the support string portions.

23. The apparatus of claim 14, wherein the articulated joint comprises a sleeve locatable on the joint to restrict articulation of the joint; wherein the degree of articulation permitted by the sleeve is related to the position or configuration of the sleeve; and wherein an inner surface of the sleeve defines a locking face, and the locking face includes areas oriented at different angles to an axis of the joint.

24-25. (canceled)

26. The apparatus of claim 14, further comprising a drill string guide including a restraining member for location above the seabed for limiting the lateral movement of the support string.

Description

BRIEF DESCRIPTION OF THE DRAWINGS

[0034] These and other examples of aspects of the disclosure, will now be described, by way of example, with reference to the accompanying drawings, in which:

[0035] FIG. 1 is an illustration of a subsea drilling operation for installation of a conductor or surface casing;

[0036] FIG. 2 shows a subsea drilling operation in accordance with an example of the present disclosure;

[0037] FIG. 3 is a sectional view of an articulated joint used in the drilling operation of FIG. 2;

[0038] FIG. 4 shows a tree-cap or plug-pulling operation in accordance with an example of the present disclosure;

[0039] FIG. 5 shows apparatus located in a well through a drilling riser in accordance with an example of the present disclosure;

[0040] FIG. 6 shows a subsea drilling operation utilizing a drill string guide in accordance with an example of the present disclosure;

[0041] FIG. 7 shows a multiple well arrangement utilizing a drill string provided with two articulated joints in accordance with an example of the present disclosure, and

[0042] FIG. 8 shows a conductor jetting operation in accordance with an example of the present disclosure.

DETAILED DESCRIPTION

[0043] Reference is first made to FIG. 1 of the drawings, an illustration of a subsea drilling operation for installation of a conductor or surface casing. Drilling operations are conducted from a mobile offshore drilling unit 10 floating on the sea surface 12, and a wellhead assembly 14 has been positioned on the seabed. The assembly 14 includes a wellhead housing 15 and a guide base 17 which extend from the seabed or mudline 19. The figure illustrates an initial drilling stage, before installation of a drilling riser, and following installation and cementing of the conductor 16, the first section of bore-lining tubing/casing.

[0044] A drill string 18 extends from the drilling unit 10 through open water and into the conductor 16. A bottom hole assembly (BHA) 20 is mounted on the lower end of the string 18 and is provided with a drill bit 22. A bushing 24 is provided in the wellhead assembly 14 to prevent wear or damage from contact between the rotating drill string 18 and the assembly 14.

[0045] The drill bit 22 will drill out of the conductor shoe and beyond the lower end of the conductor 16 to extend the bore 26 and allow installation of a further casing string (not shown) to line the newly drilled bore section. The casing will extend from the wellhead assembly 14 to the end of the newly drilled bore section.

[0046] During a drilling operation the drilling unit 10 will experience dynamic forces from, for example, waves, wind, heave, and sea currents. The unit 10 will be provided with systems which operate to maintain the unit 10 directly above the bore 26, but it is inevitable that some movement of the unit 10 will occur, particularly in severe weather. The drilling apparatus will tolerate a degree of movement of the drilling unit 10 away from direct vertical alignment with the bore 26, and this safe operating radius 28 is sometimes referred to as the watch circle. If the unit 10 approaches or moves beyond the safe operating radius 28 operations may have to be stopped, and in extreme situations the drill string 18 may have to be disconnected. Also, even when the drilling unit 10 remains within the watch circle 28 the drill string 18 may experience bending and if the drill string 18 is rotating this may result in metal fatigue damage to the string 18, thus shortening the safe working life of the drill string components.

[0047] Reference is now made to FIG. 2 of the drawings, a subsea drilling operation in accordance with an example of the present disclosure, and to FIG. 3 of the drawings, a sectional view of an articulated joint for use in the drilling operation of FIG. 2. The apparatus used in the operation of FIG. 2 is similar in many respects to the apparatus illustrated in FIG. 1 however the apparatus of FIG. 2 includes a modified drill string 40 comprising an upper section 40a and a lower section 40b joined by an articulated joint 200, as shown in greater detail in FIG. 3. The joint 200 includes a ball and socket arrangement 202 and is capable of transmitting torque. The joint 200 is described in greater detail below. A conventional drill string 18, as illustrated in FIG. 1, is relatively rigid and will only tolerate limited bending. However, the provision of the joint 200 in the string 40 allows the upper and lower drill string sections 40a, 40b to pivot relative to one another. This facility for pivoting between the sections 40a, 40b allows the string 40 to accommodate a greater degree of misalignment between the drilling unit 10 and the bore 26 and facilitates retaining the lower drill string section 40b in a substantially vertical orientation. This facilitates the drilling of a vertical bore.

[0048] The BHA 20 may incorporate drill collars, relatively stiff and heavy tubular sections, and other heavy components, which maintain the lower section 40b in tension. This provides a pendulum effect which tends to maintain the lower section 40b in a vertical orientation.

[0049] In the absence of the joint 200, movement of the mobile drilling unit 10 from a position vertically above the bore 26 is accommodated by bending of the drill string. As noted above a conventional drill string will only accommodate a limited degree of bending and that bending tends to be concentrated in the uppermost and lowermost sections of the string, limiting the degree of movement of the unit 10 that may be accommodated safely. However, by providing the articulated joint 200 in the string 40 the bending of the string 40 necessary to accommodate movement of the unit 10 is significantly reduced, with the result that the safe operating radius 44 is significantly increased.

[0050] The skilled person will appreciate that this would be particularly beneficial in severe weather conditions, for example high winds and a sea-state that would affect the position of the drill-rig, by increasing the work circle (watch circle) of the drilling unit 10, thus reducing weather down-time and generally improving well construction efficiency.

[0051] The safe operating radius/diameter or watch circle of a conventional offshore operation with a riser attached to the wellhead is typically calculated from a number of weather and sea-state related conditions and rig, riser and well structure capacities, including, lower and upper flexible joint allowable flex, the telescopic joint opening and closing stroke length and the allowable bending moments of the wellhead system including the structural casing. The resultant calculations provide a radius/diameter and is often expressed as a percentage or proportion of water depth. For example, current high specification rigs may operate with a watch circle diameter of 10% water depth, while less sophisticated rigs may operate with a watch circle of 7.5%.

[0052] The safe operating radius/diameter or watch circle of a conventional offshore operation where a riser is not used, that is in through water operations is typically calculated from a number of weather and sea-state related conditions. Examples of the present disclosure allow the watch circle diameter to be increased significantly, for example to 54% of water depth. Thus, while an operation undertaken with a conventional string in 5000 feet (1524 m) of water from a higher specification rig may have a 10% water depth watch circle diameter of 500 feet (152 m), provision of an articulated joint may increase the watch circle diameter to 2679 feet (817 m). Accordingly, it is likely that there will be far fewer interruptions to operations due to movement of the unit 10 than would be the case with a conventional support string.

[0053] The illustrated joint 200 comprises upper and lower tubular parts 204, 206, the upper part 204 including an internally threaded box connection 208 for engaging with a pin connection at the lower end of the upper drill string section 40a and the lower part 206 including an externally threaded pin connection 210 for engaging with a box connection at the upper end of the lower drill string section 40b. The ball and socket arrangement 202 comprises a part-spherical socket 212 provided at the lower end of the upper part 204 for receiving and retaining a ball 214 provided at the upper end of the lower part 206. A seal 216 is provided on the ball 214 to provide a sliding sealing contact with the socket 212 and maintain the joint through bore 218 fluid tight. The ball 214 and socket 212 are keyed together to permit the transmission of torque through the joint 200.

[0054] The joint 200 is provided with a locking arrangement in the form of a sleeve 220 which, in a fully retracted position, allows relatively unrestricted pivoting, and in a fully extended position locks the joint 200 with the upper and lower parts 204, 206 in axial alignment. The sleeve 220 of the illustrated joint may also be fixed in intermediate positions to provide three different maximum pivot angles, as will be described. The sleeve 220 has an upper portion 222 having an inner diameter slightly bigger than the outer diameter of the joint upper part 204 to permit the sleeve 220 to slide axially over the upper part 204. The sleeve 220 has a flared lower portion 224 including an inner surface 226 defining three different locking face angles 226a, 226b, 226c.

[0055] The sleeve 220 is moved relative to the joint parts 204, 206 by any appropriate means, for example by a set of hydraulic cylinders. In other examples the sleeve may be adapted to be moved by an ROV: the sleeve may be mounted on a lazy j-slot and the ROV rotates the sleeve to adjust and lock the sleeve and set the degree of articulation; the sleeve may be mounted to the joint body on a large square thread such that an ROV may rotate the sleeve to a desired position, or the sleeve may be lifted and locked by an ROV. To facilitate ROV movement the sleeve may be coupled to sub-sea buoyancy material to render the sleeve neutrally buoyant.

[0056] The lower joint part 206 may have a profile adapted to cooperate with the sleeve inner surface 226 and in the illustrated example the part 206 has a truncated conical form 230.

[0057] The joint 220 is illustrated in FIG. 3 with the sleeve 220 in an intermediate position, and the lower joint part 206 may rotate or pivot relative to the upper part (by up to 7.5? from the axial position, to provide a total maximum articulation of 15?) until the conical outer surface 230 comes into contact with the intermediate locking face angle 226b. The angle of rotation permitted may be increased by retracting or raising the sleeve 220 and decreased by extending or lowering the sleeve 220. If the sleeve 220 is fully extended to bring the shallowest locking face angle 226a into contact with the surface 230 the joint 200 is locked and does not permit any pivoting. In this example fully retracting the sleeve 220 permits pivoting of 15? from the axial to permit a total articulation of 30?.

[0058] The degree of rotation or pivoting permitted by the joint 220 may be related to the dimensions of the tools and other items that are to be passed through the string 40. For example, longer or larger diameter tools may not be able to pass through the joint 220 if the upper and lower joint parts 204, 206 are at an angle which significantly restricts the joint through bore 218. In such a situation the operator will set the sleeve 220 to permit a maximum degree of relative rotation that still permits clear passage of the tool through the joint 200. By way of example, a 4-inch (10.16 cm) diameter bore 218 may be provided in the joint 200. In the locked configuration, in which no pivoting is permitted, larger (+3 inch (7.2 cm)) electric wireline tools on hepta-cable may pass easily through the joint 200. However, if smaller diameter tools are to be deployed through the joint 200, for example small (1 11/16 (4.2863 cm)) electric line tools on monocable or slickline, the joint 200 may be reconfigured to permit a degree of pivoting, limited by contact between the conical surface 230 and the intermediate locking face angle 226b. Further, if the joint 200 is only providing passage for fluids, for example injection of pressured fluids at high rates for well-killing or workover operations, then the maximum degree of pivoting provided by the lower locking face angle 226c may be employed.

[0059] The skilled person will appreciate that the illustrated articulated joint 200 is only one example of a joint that could be employed in the drilling operation. In other examples, the joint may be provided without a locking or adjusting sleeve, and the articulation between the parts of the joint may be provided by means other than a ball and socket arrangement, for example by means of length of flexible tubing supported by a universal joint. Other examples may utilize the joint forms as described in WO2018/042148, the disclosure of which is incorporated herein in its entirety.

[0060] Reference is now made to FIG. 4 of the drawings, a tree-cap or plug-pulling operation in accordance with an example of the present disclosure. In this example a drill pipe string 50 is provided with a tree-cap or plug-pulling tool 52 which is to be aligned with and then engaged with a tree-cap 53 or plug 54 to be removed from a wellhead production assembly 56 so that the operator may then gain entry to the well. The following description refers primarily to the removal of the plug 54 but applies equally to the removal of the cap 53 (the cap 53 would be removed first, using an appropriate cap-pulling tool, and retrieved to the surface before removing the plug 54 using an appropriate plug-pulling tool 52). An articulated joint 200 is provided between the string 50 and the tool 52 and facilitates alignment of the tool 52 with the plug 54, which in turn facilitates engagement of the tool 52 with the plug 54. Engagement of the tool 52 with the plug 54 may be achieved by lowering the tool 52 into engagement of the plug 54, which operation may be assisted by an ROV.

[0061] Following engagement of the tool 52 with the plug 54, the provision of the articulated joint 200 will assist in maintaining the tool 52 substantially vertical to counteract any lateral movement of drill pipe string 50 related to movement of unit 10 and thus facilitate removal of the plug 54; the plug 54 will be a close fit in the wellhead production assembly 56 such that any inclination of the tool 52 would result in tilting of the plug 54 in the assembly 56, making it more difficult to remove the plug 54.

[0062] In other examples multiple plugs may be provided in the assembly 56 and require removal. Further, one of the cap or plugs may be retrieved using a drill pipe string, and wireline may be used to retrieve the other of the cap or plugs.

[0063] FIG. 4 illustrates the drilling unit 10 directly vertically above the well, however any displacement of the unit 10 due to wind or sea currents would move the drill pipe string 50 off the vertical and in the absence of the articulated joint 200 this misalignment would impact on the alignment of the tool 52 with the plug 54 or the wellhead assembly 56. The provision of the articulated joint 200 may also facilitate alignment and coupling the tool 52 with a wellhead assembly, or a component in or on the assembly, that is itself inclined, which may be the case if the bore has been drilled off the vertical or the seabed below the assembly has been subject to subsidence.

[0064] Reference is now made to FIG. 5 of the drawings, showing apparatus being positioned in a well through a drilling riser in accordance with an example of the present disclosure. In this drawing a drilling riser 70 has been installed between the drilling unit 10 and a blow-out preventer stack (BOP) 72. At this stage, the well will likely include intermediate or reservoir casings. The upper end of the riser 70 is coupled to the drilling unit 10 via a pivot/ball connection 74 and the lower end of the riser 70 is coupled to the BOP/wellhead assembly 72 via a further pivot/ball connection 76.

[0065] A drill pipe string 78 is being used to run a large diameter tool 80, which may be a plug, packer, or the like, into the well. The tool 80 has an outer diameter only slightly smaller than the inner diameter of the well bore 82 and thus must be substantially vertically aligned with the bore 82 for movement into and through the bore 82. Achieving such vertical alignment is facilitated by provision of an articulated joint 200 between upper and lower string sections 78a, 78b, allowing movement of the lower string section 78b and the tool 80 to align with the well bore 82 in the event of displacement of the drilling unit 10.

[0066] Reference is now made to FIG. 6 of the drawings, a subsea drilling operation utilizing a drill string guide in accordance with an example of the present disclosure. The drill string configuration is like that described above with reference FIG. 2, but additionally incorporates a drill string guide 90. The drill string guide 90 limits transverse movement of the drill string 40 and assists in maintaining the lower portion of the drill string 40b substantially vertical.

[0067] The guide 90 comprises a guide ring 92 provided with a wear bushing 94 to prevent wear between the drill string 40 and the guide 90 during running drill pipe into the well or rotating the drill string to deepen the well. A guide funnel 96 assists in guiding the drill bit 22 and BHA 20 into and through the ring 92 when the drill string 40 is being lowered towards the sea floor. The ring 92 may be provided at any convenient vertical location but is conveniently located such that when drilling commences the ring 92 is positioned above the articulated joint 200. Thus, the ring 92 limits horizontal movement of a lower end of the upper string portion 40a.

[0068] The guide ring 92 is buoyant and is tethered to the seabed by anchor lines 98. Further, the drill-string guide 90 is aquadynamic in form to minimize the effects of sub-sea currents on the guide 90.

[0069] The guide 90 includes both solid and fluid buoyancy systems 100, 102. The fluid buoyancy system includes a fluid-filled tank 104 which may be flooded to facilitate sinking the guide 90 into buoyed position where the guide 90 is then tethered. The tank 104 may then be emptied of sea water by gaseous displacement via an installed nitrogen system.

[0070] The tethering system may be sufficient to maintain the location of the guide 90 but in some examples thrusters 106 may be provided to assist the guide staying in the desired position. The thrusters 106 may be powered by the current flowing past the guide 90, by batteries and generators using energy generated by passing current or waves or may operate in conjunction with remote operated vehicles which are coupled to the guide 90.

[0071] Reference is now made to FIG. 7 of the drawings, showing a multiple well arrangement utilizing a drill string provided with two articulated joints in accordance with an example of the present disclosure.

[0072] The Figure illustrates a development drilling set-up where multiple wells 120, 122 are located together and housed on a wellhead template 124. In other examples the mobile drilling unit 10 may travel between two well locations. The drill string 126 includes two articulated joints 200a, 200b separating upper, intermediate, and lower drill string portions 126a, 126b, 126c.

[0073] In addition to facilitating a drilling operation by maintaining the lower drill string portion 126c substantially vertical, the articulated joints 200a, 200b allows for the drilling unit 10 to move with the drill-string 126 pulled out of the well and suspended from the unit 10 whilst the unit 10 moves from one well location to the next.

[0074] In addition, in twin derrick drilling rigs (MODU), the provision of articulated joints 200a, 200b allows for the drilling unit 10 to move with the drill-string 126, or a casing string or the like, suspended from the unit 10 whilst the unit 10 moves from one well location to the next. Thus, while an operation is being conducted on a first well using a first drilling derrick, a drill string or casing string may be at least partially made up using the second derrick and suspended below the rig. Once the operation on the first well has been completed the drill string supported by the first derrick may be partially retrieved such that the drill bit is lifted clear of any structure on the seabed. The rig may then be moved, with the first and second strings extending into the water below the rig, to position the second derrick above the second well.

[0075] The flexibility provided by the joints 200a, 200b largely eliminates low-cycle fatigue and relieves stress in the drill string 126 that would otherwise be induced through the movement of the unit 10.

[0076] Reference is made herein primarily to operations conducted from mobile offshore drilling units (MODUs), or other units, rigs or vessels that may be subject to movement. However, the skilled person will appreciate that the disclosure is relevant to operations conducted from other vessels and rigs, even those that are fixed, for example fixed rigs provided in water that experiences tidal or other sea currents that would induce bending in a support string.

[0077] Reference is now made to FIG. 8 of the drawings, showing a conductor jetting operation in accordance with an example of the present disclosure. In this example a conductor 300 is being located in the seabed 302 by jetting; where the seabed 302 includes a layer of loose material, such as river-borne silt or sediment, this material may be displaced by a fluid jetting arrangement 304 provided at the leading end of the conductor 300, which may have a diameter of, for example, 20 or 30 inches (50.8 to 76.2 cm).

[0078] The jetting arrangement 304 is provided in a drill bit 306 mounted on the distal or lower end of a support string comprising a drill string 308. An articulated joint 200 is provided in the drill string 308. An upper portion of the drill string 308a extends down through the water to the joint 200 from a mobile offshore drilling unit 310. A lower portion of the drill string 308b extends downward from the joint 200 and is releasably coupled to an upper end of the conductor 300 by a running tool 312, such as the Cam-Actuated Drill Ahead (CADA) tool supplied by Dril-Quip, Inc. of Houston, Texas. The lower portion of the drill string 308b further extends through the conductor 300 to the drill bit 306 at the lower end of the conductor 300.

[0079] In use, the conductor 300 is supported from the drilling unit 310 by the drill string 308 and lowered to the seabed 302. Fluid is then pumped down the drill string 308 and exits through the jetting arrangement 304, displacing the loose material ahead of the leading end of the conductor 300 and forming a bore 314. The conductor 300 may thus be advanced into the bore 314 as it is formed in the seabed 302. The articulated joint 200 assists in maintaining the conductor 300 vertical as the conductor 300 is advanced into the loose material.

[0080] Once the conductor 300 has been advanced to the desired depth, the running tool 312 is disengaged from the upper end of the conductor 300. The drill string 308 may then be rotated and the drill bit 306 used to advance the bore 314 beyond the end of the conductor 300. Thus, the drilling of the bore 314 beyond the end of the conductor 300 may be commenced immediately the conductor 300 is in place. If desired, the joint 200 may be locked before drilling commences.

[0081] In other examples, additional articulated joints could be provided in elsewhere in the drill string 308 and could be locked or permitted to pivot, as desired.

[0082] The skilled person will recognize that the provision of an articulated joint in a support string may be very useful to an operator. Where the support string is located within a riser, the provision of a joint facilitates the alignment of tools and the like mounted on the string with assemblies, caps, plugs and the like. The joint may accommodate misalignment that would otherwise arise due to movement of the riser from the vertical, or where subsea infrastructure is itself misaligned from the vertical. Where the support string extends through open water the provision of one or more joints may also serve to increase the watch circle diameter that would otherwise be available and facilitates the correct alignment of conductors being jetted into the seabed and the alignment of casings and the like being deployed into drilled bores.

[0083] The skilled person will recognize that an articulated joint which may be configured to provide a controlled degree of articulation or may be adjusted or configured to provide different degrees of articulation, may have utility independently of the applications described herein.

[0084] The skilled person will further recognize that the apparatus and methods described herein may have utility in operations in addition to those where it is desired to maintain a lower portion of a support string or a tool mounted on a support string in a substantially vertical orientation, for example in extending the watch circle diameter of an offshore operation or in permitting deployment of a support string during adverse weather or during movement of a mobile drilling unit across a body of water.