Patent Number: 
Section: description

FIG. 1 shows an apparatus 1 in accordance with the present invention. A support vessel 3 such as a floating drilling rig or other floating vessel is located substantially vertically above a hydrocarbon borehole (not shown) and is typically either dynamically positioned over the particular well by means of conventional thrusters for example or is moored by conventional means over the required well. The support vessel 3 comprises a conventional crane or derrick 5 and is further provided with a make up/breakout unit generally shown at 7. The make up/breakout unit 7 comprises an upper tong 9 and a lower tong 11, which may preferably be a lower rotary back-up 11. The reader is directed towards our co-pending British Patent Application No 0004354.7 and PCT Application No GB 00/04241 for further details of a suitable make up/break out unit 7. In summary, the upper tong 9 provides means to make up and breakout tubing, casing or drillpipe 16 during tripping and snubbing operations, and is hydraulically powered. The upper tong 9 comprises three sliding jaws. (not shown) which virtually encircle the tubular 16 to maximize torque whilst minimizing marking and damage and is provided with a cam operated jaw system (not shown) which can be operated to allow passage of workstring tool joints as well as tubing casing couplings. The upper tong 9 is powered by hydraulic motors (not shown) which provide speeds and torque capable of spinning and making/breaking high torque connections. The lower tong or rotary back-up 11 generally has two functions. During drilling operations, the rotary back-up 11 generates the torque required for high speed milling and drilling. This torque is transferred to the outer diameter of the string 16 by means of three sliding jaws (not shown). During tripping operations, the jaws of the rotary back-up 11 are activated to grip the lower tubular 16 in the make up/breakout unit 7 (i.e. the tubular that is already included in the string 16) and resist the torque generated by the upper tong 9 when making up or breaking out the tubular connections. The make up/breakout unit 7 is mounted on the support vessel 3 by means of tong table compensator 13 which moves the make up/breakout unit 7 with respect to the support vessel 3, such that the make up/breakout unit 7 is substantially stationary with respect to the subsea surface. Thus, the tong table compensator 13 compensates for the action of the wave motion upon the support vessel 3. The heave of the support vessel 3 due to the ocean waves may be in the. region of 10 to 15 feet, and the stroke of the compensator table 13 substantially matches the heave of the support vessel 3, such that the make up/breakout unit is stationary with respect to the subsea equipment 17. A riser 15 extends downwardly from the support vessel 3 wherein the upper end of the riser 15 is located substantially immediately below the tong table compensator 13, although the lower end of the riser 15 could be offset from the upper end of the riser 15 as is known in the art. The riser 15 extends downwardly towards subsea equipment 17 of the apparatus 1. The subsea equipment 17 comprises an outer frame 19 which is suitably provided with sufficient strength bearing members in the form of struts, braces, etc. The subsea equipment 17 comprises a subsea annular seal 21 or lower riser seal 21 which is provided at the upper, in use, end of the frame 19. The lower end of the riser 15 is located within the lower riser seal 21, such that the outer surface of the lower end of the riser 15 is sealed to the sea water by the lower riser seal 21. A set of travelling slips 23 are mounted upon a passive rotary bearing 25. The rotating portion of the passive rotary bearing 25 supports the traveling slips 23, and allows the travelling slips 23 to rotate with respect to the non-rotating portion of the passive rotary bearing 25. The purpose of the travelling slips 23 will be described subsequently. The lower end of the passive rotary bearing 25 is mounted to the upper end of a hydraulic jack system 27, as can be more clearly seen in FIG. 2 and particularly FIG. 3. There are at least a pair of hydraulic jacks 27, and more preferably four hydraulic jacks 27 mounted equi-distantly spaced around a central region through which a tubing string 16 can pass. Each hydraulic jack 27 comprises a piston 29 and cylinder 31 arrangement. The piston 29 comprises a piston head 33 at its lower end, and the outer radial surface of the piston head 33 is sealed with respect to the inner surface of the cylinder 31 by means of a set of xe2x80x9cVxe2x80x9d seal packings 35. The packings 35 shown in FIGS. 4(a) to 4(c) comprise an upper set of three seals arranged to seal in the direction from above the piston head 33, and hence seal against the subsea hydrostatic pressure, and a lower set of three seals arranged to seal in the direction from below the piston head 33 and hence seal against the hydraulic fluid pressure within the cylinder 31; however, it should be noted that more than, or less than, three seals can be provided in the upper and/or lower sets of seals. A second set of xe2x80x9cVxe2x80x9d seal packing 37 acts between the longitudinal body of the piston 29 and the upper end of the cylinder 31, and acts to prevent the hydrostatic pressure of sea water from outside of the cylinder 31 from entering the interior of the cylinder 31. An upper hydraulic port 39 is provided within a side wall of the cylinder 31 toward the upper end thereof, and a lower hydraulic port 41 is provided in the side wall toward the lower end of the cylinder 31, such that the hydraulic ports 39, 41 provide access to the interior of the cylinder 31. A hydraulic fluid control system for providing pressurised hydraulic fluid to the cylinders 31 in a controlled and selective manner is also provided as will now be described. A hydraulic fluid charge pump 43 is provided on the support vessel 3 and is capable of providing/maintaining pressurised hydraulic fluid to an arrangement of hydraulic fluid accumulators 47, mounted on the frame 19, via hydraulic fluid line 45. The accumulators 47 act as high pressure hydraulic fluid reservoirs subsea, and are interconnected via upper 49 and lower 51 valve manifolds and a network of hydraulic lines 50. The valve manifolds 49, 51 are operated by an operator on the support vessel by means of a control console 53 via a control line 55. The control console 53 and hence control line 55 may be electrically or hydraulically powered. Accordingly, operation of the control console 53 in the prescribed manner by the operator can raise or lower the hydraulic jacks 27 by injection of pressurised hydraulic fluid into the respective upper or lower hydraulic ports 39, 41. The lower end of the cylinder 31 of hydraulic jacks 27 is mounted to the upper end of a set of stationary slips 57 which can be operated from the support vessel 3 to selectively grip and hence support the tubing string 16. The set of stationary slips 57 are substantially the same as a conventional set of stationary slips (previously in the prior art only used above the sea surface), although they will likely require modification for use subsea as in the present invention. The stationary slips 57 are mounted to the upper end of a subsea stack 59 which is mounted directly above a blowout prevent or (BOP) 61, which as is conventional, comprises an upper set of rams 62 for emergency sealing about the tubing string 16, a middle set of shear rams 63 which are capable of cutting through the tubing string 16, and a lower set of pipe rams 64 which can be operated in an emergency to seal around the tubing string 16; the BOP is only operated in the event of an emergency in order to seal off the wellbore located below the SOP 61. Conventional choke 67 and kill 69 lines run from the support vessel 3 down to the SOP 61, and are strapped to the riser 15. It should be noted that with the apparatus 1 as shown in FIGS. 1 to 5, there is a further fluid tank (not shown) located on the support vessel 3, and due to the presence of the lower riser seal 21, it is possible to fill the annulus between the inner circumference of the riser and the outer circumference of the tubing/drillstring 16 with fluid supplied from the fluid tank which provides the advantage that the riser is prevented from collapsing due to the hydrostatic pressure of the ocean. In addition, communication lines 71 connect the wellbore, via the SOP 61, to the inner circumference of the lower riser seal 21 and hence the communication lines 71 provide communication between the wellbore and the riser 15. This provides the advantage that if a severe gas kick is experienced from the wellbore, the fluid in the tank will rise, and an operator or a sensor on the support vessel 3 can observe this rise in fluid level in the tank and operate the SOP stack 61 to close the wellbore. In addition, the advantage is provided that if a drilling operation is being conducted through a formation which is relatively low in pressure, the fluid in the riser will quickly drain into the formation and hence the fluid level in the tank will sharply fall and in this scenario the operator can also operate the SOP stack 61 to close the wellbore whilst remedial work can be conducted. Alternatively, and as shown in the second embodiment of apparatus 100 disclosed in FIG. 6 and FIG. 7, it is possible to omit the lower riser seal 21, such that the annulus between the outer circumference of the tubing/drillstring 16 and the inner circumference of the riser 15 is filled with sea water in order to prevent the riser 15 from collapsing. In the apparatus 100, the lower end of the riser 15 secures to a flange located at the uppermost portion of the frame 19, and will thus be open to the sea water. However, the embodiment as shown in FIGS. 1 to 5 is preferred since this provides the advantage that the operator can view the result of the wellbore pressure. In all other respects, the apparatus 100 as shown in FIGS. 6 and 7 is identical with the apparatus 1 as shown in FIGS. 1 to 5. Operation of the apparatus of FIG. 1 will now be described in relation to a drilling operation, but those experienced in the art will appreciate that apparatus 1 can be operated for a host of other operations, such as well intervention, for example. In particular, as those skilled in the art will appreciate, if a through (production) tubing operation is to be performed, the production tree (not shown) is left in place at the mouth of the wellbore, and the frame 19 including the subsea stack 59 and SOP 61 are lowered from the vessel 3 and coupled to the production tree. However, if a full workover operation is to be conducted, the production tubing (not shown) is removed from the wellbore, with the appropriate plugs (not shown) having been placed into the wellbore, and thereafter the frame 19 including the subsea stack 59 and SOP 61 are lowered from the vessel 3 and coupled to the mouth of the wellbore. It should also be noted that the apparatus 100 is operated in a similar manner to the apparatus 1, with the exception that the lower seal riser 21 is not present in the apparatus 100. The tubing string 16, in this case the drillstring 16, is progressively made up in the upper tong 9 and lower rotary back-up 11 and is lowered into the well by the crane 5 and associated winch, with successive drillpipe being included in the drillstring 16. The drillstring 16 first enters the riser 15 and continues downwards until it enters the lower riser seal 21. The lower end of the drillstring 16 then enters the bore of the travelling slips 23, at which point the travelling slips 23 are actuated to securely grip the lower end of the drillstring 16. The hydraulic jack 27 is then operated by an operator at the control console 53, such that the hydraulic jacks 27 are lowered. Hence, the travelling slips 23 take the weight of the drillstring 16. The jacks 27 continue to be lowered until the lower end of the drillstring passes through the stationary slips 57, at which point movement of the hydraulic jacks 27 is halted and the stationary slips 57 are actuated to securely grip the lower end of the drillstring 16. The travelling slips 23 are then disengaged from gripping the drillstring 16 and hence the weight of the drillstring 16 is held by the stationary slips 57. The jacks 27 can then be actuated in the reverse direction, that is to lift the travelling slips 23 upwards until the jacks 27 have reached their, full stroke and the travelling slips 23 can then be actuated once again to grip the next section of drillstring 16; thereafter the stationary slips 57 engagement of the drill string 16 is released. By repeating this operation, the drillstring 16 can be inserted into the wellbore in a much faster manner than achieved using conventional methods. In order to retrieve the drillstring 16 from the wellbore, the apparatus is operated in the reverse direction to that described above, and again, the drillstring 16 can be removed from the wellbore in a manner much quicker than is capable of being achieved with conventional methods. The subsea equipment 17, including the frame 19, subsea stack 59 and SOP 61 can then be retrieved to the vessel 3, after the wellbore has been suitably sealed. Alternatively, if a through (production) tubing operation has been performed, the production tree is left in place at the mouth of the wellbore, and the subsea equipment 17 is de-coupled from the production tree and is retrieved to the vessel. However, if a full workover operation has been conducted, the subsea equipment 17 is de-coupled from the wellbore and is retrieved to the vessel; the production tree is then reinserted in the wellbore mouth, and the appropriate plugs can also then be removed. The embodiments described herein provide the great advantage that most support vessels currently used in the offshore oil and gas industry can be used for such operations with relatively minimal conversion being required, which results in substantial cost and manpower savings. In addition, there is only a very limited supply of jack up rigs available, which means that such operations must wait until a suitable vessel is available; the embodiments described herein substantially increase the number of vessels available in the world capable of performing such operations. Modifications and improvements may be made to the embodiments herein described, without departing from the scope of the invention.