Abstract:
A method and apparatus for inserting or removing a string of tubulars from a subsea borehole. The apparatus includes a first, lower, gripping mechanism locatable subsea in the vicinity of the subsea borehole. The first gripping mechanism is capable of gripping a portion of the string of tubulars. The apparatus further includes a second, upper, gripping mechanism locatable subsea in the vicinity of the subsea borehole, the second gripping mechanism being capable of-gripping a portion of the sting of tubulars. The first and second gripping mechanisms are moveable with respect to one another. The apparatus further includes a movement mechanism which, when actuated, moves one of the first and second gripping mechanisms with respect to the other of the first and second gripping mechanisms, such that the string of tubulars is inserted into or removed from the subsea borehole.

Description:
BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     The present invention relates to an apparatus and method, particularly, but not exclusively, for use with increasing the speed of tripping into or out of a subsea well on a floating production platform or vessel used in the exploration, exploitation and production of hydrocarbons. Particularly, the apparatus and method is for use in workovers, well maintenance and well intervention in subsea wells, but could also relate to other uses such as water exploration, exploitation and production. 
     2. Description of the Related Art 
     Conventional drilling operations for hydrocarbon exploration, exploitation and production utilize many lengths of individual tubulars (or OCTG products) which are made up into a string, where the tubulars are connected to one another by means of screw threaded couplings provided at each end. Various operations require strings of different tubulars, such as drillpipe, casing and production tubing. The individual tubular sections are made up into the required string on the drilling rig or floating production vessel, etc., by inserting them into the subsea surface well through a riser which extends from the subsea surface up to the drilling rig. A make up/breakout unit adds or removes an individual tubular section from the required string. Conventionally, this is a relatively time consuming task, since the string must be held in conventional slips located on the drilling rig whilst e.g. a new tubular is included in the top of the string on the drilling rig. In addition, conventional drilling rigs, such as jack ups, floating drilling rigs and drill ships are relatively expensive both in terms of manpower and rental rates which may be in the region of 100 men and U.S.$200,000 per day respectively. 
     SUMMARY OF THE INVENTION 
     According to a first aspect of the present invention there is provided an apparatus for inserting or removing a string of tubulars from a sub-sea borehole, the apparatus comprising: 
     a first, lower, gripping mechanism located subsea in the vicinity of the subsea borehole, the first gripping mechanism being capable of gripping a portion of the string of tubulars; 
     a second, upper, gripping mechanism located subsea in the vicinity of the subsea borehole, the second gripping mechanism being capable of gripping a portion of the string of tubulars; 
     wherein the first and second gripping mechanisms are moveable with respect to one another; and 
     a movement mechanism which, when actuated, moves one of the first and second gripping mechanisms with respect to the other of the first and second gripping mechanisms, such that the string of tubulars is inserted into or removed from the subsea borehole. 
     According to a second aspect of the present invention there is provided a method of inserting or removing a string of tubulars from a sub-sea borehole, the method comprising: 
     providing a first gripping mechanism subsea in the vicinity of the subsea borehole, the first gripping mechanism being capable of gripping a portion of the string of tubulars; 
     providing a second gripping mechanism located subsea in the vicinity of the subsea borehole, the second gripping mechanism being capable of gripping a portion of the string of tubulars; 
     wherein the first and second gripping mechanisms are moveable with respect to one another; 
     providing a movement mechanism which is capable of moving one of the first and second gripping mechanisms with respect to the other of the first and second gripping mechanisms; and 
     actuating the movement mechanism such that the string of tubulars is inserted into, or removed from, the subsea borehole. 
     Preferably, the first gripping mechanism is lower than the second gripping mechanism, and more preferably, the first gripping mechanism is substantially stationary with respect to the mouth of the subsea borehole, and the second, upper, gripping mechanism is moved with respect to the first gripping mechanism. 
     Typically, the second, upper, gripping mechanism is operated to grip the string of tubulars whilst the movement mechanism is actuated, and when this is the case, the first, lower, gripping mechanism is preferably not actuated such that the first, lower, gripping mechanism does not grip the string of tubulars. 
     Preferably, the first, lower, gripping mechanism is operated to grip the string of tubulars when the second, upper, gripping mechanism is not operated to grip the string of tubulars. 
     Typically, the movement mechanism comprises a jacking mechanism including a piston cylinder and a piston located within the piston cylinder, wherein one of the first and second gripping mechanisms is secured to the piston and the other of the first and second gripping mechanisms is secured to the piston cylinder. Preferably, the jacking mechanism is operated by introducing fluid into, or removing fluid from, one side of the piston within the piston cylinder. Preferably, a fluid reservoir, which is preferably a high pressure fluid reservoir, is provided to introduce fluid into, or remove fluid from, one side of the piston within the piston cylinder, and more preferably, the fluid reservoir is located subsea, typically in close proximity to the jacking mechanism. 
     Preferably, the jacking mechanism and first and second gripping means are all located vertically above, and typically in line with, a subsea equipment package which includes at least a subsea blow-out preventor (BOP). 
     Preferably, there is further provided a make up/break out mechanism which is capable of adding a tubular to or removing a tubular from the string. Typically, there is further provided a handling mechanism which is adapted to deliver a tubular into, or remove a tubular from, the make up/break out mechanism. Preferably, the make up/break out mechanism, and typically the handling mechanism is/are located on a vessel at the sea surface, where the vessel is typically located substantially vertically above the apparatus located subsea. Typically, a compensation mechanism is provided to compensate the make up/break out mechanism for movement of the vessel in the sea, typically in a direction parallel to the axial direction of the string, such that the string may be substantially continuously inserted into or removed from the borehole. 
     Typically, the make up/breakout mechanism further comprises a pair of vertically spaced tongs which are adapted to selectively grip the tubulars. More preferably, the uppermost tong is adapted to impart rotation to a tubular. 
     Typically, a riser is further provided into an upper end of which the string is inserted into at the vessel. The lower end of the riser may be sealed with respect to the sea or may be open with respect to the sea. 
     A control system is preferably provided to control actuation of the first and second gripping mechanisms and preferably also the jacking mechanisms. Typically, the fluid reservoir is charged up from a pump located on the vessel. 
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS 
     So that the manner in which the above recited features of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments. 
     Embodiments of the present invention will now be described, by way of example only, with reference to the accompanying drawings, in which: 
     FIG. 1 is a schematic view of a first embodiment of an apparatus in accordance with the present invention; 
     FIG. 2 is a detailed view of a portion of the apparatus shown in FIG. 1; 
     FIG. 3 is a further detailed view of a portion of the apparatus shown in FIG. 1; 
     FIG.  4 ( a ) is a cross-sectional side view of a portion of a hydraulic jacking system incorporated in the apparatus of FIG. 1; 
     FIG.  4 ( b ) is a more detailed cross-sectional view of a portion of the hydraulic jacking system shown in FIG.  4 ( a ); 
     FIG.  4 ( c ) is a plan view of the hydraulic jacking system shown in FIG.  4 ( a ); 
     FIG. 5 is a cross-sectional view of the hydraulic jacking system shown in FIGS.  4 ( a )-( c ); 
     FIG. 6 is a second embodiment of an apparatus in accordance with the present invention; and 
     FIG. 7 is a schematic view of a portion of the apparatus shown in FIG.  6 . 
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT 
     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 “V” 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 “V” 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.