Abstract:
The present invention generally relates to methods and apparatus for subsea well intervention operations, including retrieval of a wellhead from a subsea well. In one aspect, a method of performing an operation in a subsea well is provided. The method comprising the step of positioning a tool proximate a subsea wellhead. The tool has at least one grip member and the tool is attached to a downhole assembly. The method also comprising the step of clamping the tool to the subsea wellhead by moving the at least one grip member into engagement with a profile on the subsea wellhead. The method further comprising the step of applying an upward force to the tool thereby enhancing the grip between the grip member and the profile on the subsea wellhead. Additionally, the method comprising the step of performing the operation in the subsea well by utilizing the downhole assembly.

Description:
BACKGROUND OF THE INVENTION 
       [0001]    1. Field of the Invention 
         [0002]    Embodiments of the present invention generally relate to a subsea well. More particularly, embodiments of the invention relate to methods and apparatus for subsea well intervention operations, including retrieval of a wellhead from a subsea well. 
         [0003]    2. Description of the Related Art 
         [0004]    After the production of a subsea well is finished, the subsea well is closed and abandoned. The subsea well closing process typically includes recovering the wellhead from the subsea well using a conventional wellhead retrieval operation. During the conventional wellhead retrieval operation, a retrieval assembly equipped with a casing cutter is lowered on a work string from a floating rig until the retrieval assembly is positioned over the subsea wellhead. Next, the casing cutter is lowered into the wellbore as the retrieval assembly is lowered onto the wellhead. The casing cutter is actuated to cut the casing by using the work string. The cutter may be powered by rotating the work string from the floating rig. Since the work string is used to manipulate the retrieval assembly and the casing cutter, the floating rig is required at the surface to provide the necessary support and structure for the work string. Even though the subsea wellhead may be removed in this manner, the use of the floating rig and the work string can be costly and time consuming. Therefore, there is a need for an improved method and apparatus for subsea wellhead retrieval. 
       SUMMARY OF THE INVENTION 
       [0005]    The present invention generally relates to methods and apparatus for subsea well intervention operations, including retrieval of a wellhead from a subsea well. In one aspect, a method of performing an operation in a subsea well is provided. The method comprises the step of positioning a tool proximate a subsea wellhead. The tool has at least one grip member and the tool is attached to a downhole assembly. The method also comprises the step of clamping the tool to the subsea wellhead by moving the at least one grip member into engagement with a profile on the subsea wellhead. The method further comprises the step of applying an upward force to the tool thereby enhancing the grip between the grip member and the profile on the subsea wellhead. Additionally, the method comprises the step of performing the operation in the subsea well by utilizing the down hole assembly. 
         [0006]    In another aspect, an apparatus for use in a subsea well is provided. The apparatus comprises a grip member movable between an unclamped position and a clamped position, wherein the grip member in the clamped position applies a grip force to a profile on the subsea wellhead. Additionally, the apparatus comprises a lifting assembly configured to generate an upward force which increases the grip force applied by the grip member. 
         [0007]    In yet another aspect, a method of performing an operation in a subsea well is provided. The method comprises the step of positioning a tool proximate a subsea wellhead. The tool has at least one grip member and a lock member. The tool is also attached to a downhole assembly. The method further comprises the step of moving the at least one grip member from an unclamped position to a clamped position in which the grip member engages the subsea wellhead. The method also comprises the step of hydraulically activating the lock member such that the lock member engages a portion of the grip member thereby retaining the grip member in the clamped position. Additionally, the method comprises the step of performing the operation in the subsea well by utilizing the downhole assembly. 
         [0008]    In a further aspect, an apparatus for use in a subsea well is provided. The apparatus comprises a grip member for engaging a subsea wellhead, wherein the grip member is movable between an unclamped position and a clamped position. The apparatus further comprises a lock member movable between an unlocked position and a locked position upon activation of a hydraulic cylinder, wherein the lock member in the locked position retains the grip member in the clamped position. 
         [0009]    In a further aspect, a method of cutting a casing string in a subsea well is provided. The method comprises the step of positioning a tool proximate a subsea wellhead. The tool has at least one grip member and the tool is attached to a cutting assembly. The method further comprises the step of operating the at least one grip member to clamp the tool to the subsea wellhead. The method also comprises the step of cutting the casing string below the subsea wellhead by utilizing the cutting assembly. Additionally, the method comprises the step of applying an upward force to the tool during the cutting of the casing string which is at least equal to an axial reaction force generated from cutting the casing string, wherein at least a portion of the upward force is created by a cylinder member in the tool that acts on the subsea wellhead. 
         [0010]    In yet a further aspect, an apparatus for cutting a casing string in a subsea well is provided. The apparatus comprises a cutting assembly configured to cut the casing string. The apparatus also comprises a grip member for engaging a subsea wellhead, the grip member movable between an unclamped position and a clamped position. Additionally, the apparatus comprises a lifting assembly configured to generate an upward force which is at least equal to an axial reaction force generated from cutting the casing string, wherein the lifting assembly comprises a cylinder and piston arrangement that is configured to act upon a portion of the subsea wellhead. 
         [0011]    Additionally, a method of gripping a subsea wellhead is provided. The method comprises the step of positioning a tool proximate the subsea wellhead. The tool has at least one grip member. The method further comprises the step of clamping the tool to the subsea wellhead by moving the at least one grip member into engagement with a profile on the subsea wellhead. Additionally, the method comprises the step of applying an upward force to the tool thereby enhancing the grip between the grip member and the profile on the subsea wellhead. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0012]    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. 
           [0013]      FIG. 1  is an isometric view of a subsea wellhead intervention and retrieval tool according to one embodiment of the invention. 
           [0014]      FIG. 2  is a view illustrating the placement of the tool on a wellhead. 
           [0015]      FIG. 3  is a view illustrating the tool engaging the wellhead. 
           [0016]      FIG. 4  is a view illustrating the tool cutting a casing string below the wellhead. 
           [0017]      FIGS. 5A and 5B  are enlarged views illustrating the components of the tool. 
           [0018]      FIG. 6  is a view illustrating the tool after the casing string has been cut. 
           [0019]      FIG. 7  is a view illustrating a subsea wellhead intervention and retrieval tool with a perforating tool. 
           [0020]      FIG. 8  is a view illustrating a subsea wellhead intervention and retrieval tool with the perforating tool disposed on a wireline. 
           [0021]      FIG. 9  is a view illustrating a subsea wellhead intervention and retrieval tool with the perforating tool. 
           [0022]      FIG. 10  is a view illustrating a subsea wellhead intervention and retrieval tool with a cutter assembly. 
           [0023]      FIG. 11  is a view illustrating a subsea wellhead intervention and retrieval tool with an explosive charge device. 
       
    
    
     DETAILED DESCRIPTION 
       [0024]    Embodiments of the present invention generally relate to methods and apparatus for subsea well intervention operations, including retrieval of a wellhead from a subsea well. To better understand the aspects of the present invention and the methods of use thereof, reference is hereafter made to the accompanying drawings. 
         [0025]      FIG. 1  shows a subsea wellhead intervention and retrieval tool  100  according to one embodiment of the invention. As shown, the tool  100  includes a shackle  210  and a mandrel  195  for connection to a conveyance member  202 , such as a cable. The use of cable with the tool  100  allows for greater flexibility because the cable may be deployed from an offshore location that includes a crane rather than using a floating rig with a work string as in the conventional wellhead retrieval operation. In another embodiment, the conveyance member may be an umbilical, coil tubing, wireline or jointed pipe. 
         [0026]    The conveyance member  202  is used to lower the tool  100  into the sea to a position adjacent the subsea wellhead. A power source (not shown), such as a hydraulic pump, pneumatic pump or a electrical control source, is attached to the tool  100  via an umbilical cord (not shown) connected to connectors  205  to manipulate and/or monitor the operation of the tool  100 . The power source is attached to a control system  230  of the tool  100 . The control system  230  may include a manifold arrangement that integrates one or more cylinders of the tool  100 . The manifold arrangement may include a filtration system and a plurality of pilot operated check valves which allows the cylinders of the tool to function in a forward direction or a reverse direction. In one embodiment, the manifold arrangement allows the cylinders to operate independently from the other components in the tool  100 . The functionality of the cylinders will be discussed herein. The control system  230  may also include data sensors, such as pressure sensors and temperature sensors that generate data regarding the components of the tool  100 . The data may be used to monitor the operation of the tool  100  and/or control the components of the tool  100 . Further, the data may be used locally by an onboard computer or by the ROV. The data may also be used remotely by sending the data back to the surface via the ROV or via an umbilical attached to the tool. 
         [0027]    The power source for controlling the control system  230  of the tool  100  is typically located near the surface. The power source may be configured to pump fluid from the offshore location through the umbilical cord connected to the connectors  205  in order to operate the components of the tool  100  such as arms  125  and wedge blocks  150  as described herein. In another embodiment, the tool  100  may be manipulated using a remotely operated underwater vehicle (ROV). In this embodiment, the ROV may attach to the tool  100  via a stab connector  215  and then control the control system  230  of the tool  100  in a similar manner as described herein. The ROV may also manipulate the position of the tool  100  relative to the wellhead by using handler members  220 . 
         [0028]    As illustrated in  FIG. 1 , the tool  100  may be attached to a downhole assembly such as a motor  115  and a rotary cutter assembly  105 . The motor  115  may be an electric motor or a hydraulic motor such as a mud motor. The rotary cutter assembly  105  includes a plurality of blades  110  which are used to cut the casing. The blades  110  are movable between a retracted position and an extended position. In another embodiment, the tool  100  may use an abrasive cutting device to cut the casing instead of the rotary cutter assembly  105 . The abrasive cutting device may include a high pressure nozzle configured to output high pressure fluid to cut the casing. The use of abrasive cutting technology allows the tool  100  to cut through the casing with substantially no downward pull or torque transmission to the wellhead which is common with the rotary cutter assembly  105 . In another embodiment, the tool  100  may use a high energy source such as laser, high power light, or plasma to cut the casing. The high energy cutting system may be incorporated into the tool  100  or conveyed to or through the tool  100  via a transmission system. Suitable cutting systems may use well fluids, and/or water to cut through multiple casings, cement and voids. The cutting systems may also reduce downward pull and subsequent reactive torque transmission to the wellhead. 
         [0029]      FIG. 2  is a view illustrating the placement of the tool  100  on a wellhead  10 . The tool  100  is lowered via the conveyance member until the tool  100  is positioned proximate the top of the wellhead  10  disposed on a seafloor  20 . As the tool  100  is positioned relative to the wellhead  10 , the motor  115  and the cutter assembly  105  are lowered into the wellhead  10  such that the blades  110  of the cutter assembly  105  are adjacent the casing string  30  attached to the wellhead  10 . Generally, the wellhead  10  includes a profile  50  at an upper end. The profile  50  may have different configurations depending on which company manufactured the wellhead  10 . The arms  125  of the tool  100  include a matching profile  165  to engage the wellhead  10  during the wellhead retrieval operation. It should be noted that the arms  125  or the profile  165  on the arms  125  may be changed (e.g., removed and replaced) with a different profile in order to match the specific profile on the wellhead  10  of interest. The arms  125  are shown in an unclamped position in  FIG. 2  and in a clamped position in  FIG. 3 . 
         [0030]      FIG. 3  illustrates the tool  100  engaging the wellhead  10 . The tool  100  includes an actuating cylinder  135  (e.g. piston and cylinder arrangement) that is attached to the arm  125 . As the cylinder  135  is actuated by the power system, the arms  125  rotate around pivot  130  from the unclamped position to the clamped position in order to engage the wellhead  10 . It must be noted that the arms  125  may be individually activated by a respective cylinder  135  or collectively activated by one or more cylinders. As shown, the profile  165  on the arms  125  mate with the corresponding profile  50  on the wellhead  10 . After the arms  125  have engaged the wellhead  10 , the arms  125  are locked in place by activating a locking cylinder  155  (e.g. piston and cylinder arrangement) which causes a wedge block  150  to slide along a surface of the arm  125  as shown in  FIG. 4 . The movement of the wedge block  150  prevents the arms  125  from rotating around the pivot  130  to the clamped position. It must be noted that the wedge blocks  150  may be individually activated by the respective cylinder  155  or collectively activated by one or more cylinders. 
         [0031]      FIG. 4  is a view illustrating the tool  100  cutting a casing string  30  below the wellhead  10 . After the arms  125  are locked in place by the wedge block  150 , an optional cylinder  180  (e.g. piston and cylinder arrangement) is activated that causes a shoe  175  to act upon a surface  25  of the wellhead  10  and axially lift the tool  100  relative to the wellhead  10 . The axial movement of the tool  100  relative to the wellhead  10  allows for active clamping of the tool  100  on the wellhead  10 . For instance, as the tool  100  moves relative to the wellhead  10 , the profile  165  on the arms  125  moves into maximum contact with the profile  50  on the wellhead  10  such that the tool  100  is clamped on the wellhead  10  and will not rotate (or spin) relative to the wellhead  10  when the rotary cutter assembly  105  is in operation. In this respect, reactive torque resistance is provided for the mechanical cutting system. After the tool  100  is fully engaged with the wellhead  10 , the motor  115  activates the rotary cutter assembly  105  and the blades  110  move from the retracted position to the extended position as illustrated in  FIG. 3  to  FIG. 4 . Thereafter, the casing string  30  is cut by the rotary cutter assembly  105 . It should be noted that the cylinders  135 ,  155 ,  180  may be independently operated by the power source or by the ROV. Additionally, it is contemplated that cylinders  135 ,  155 ,  180  may include any suitable number of cylinders as necessary to perform the intended function. 
         [0032]      FIGS. 5A and 5B  are enlarged views illustrating the components of the tool  100 . The conveyance member may be pulled from the surface to enhance the clamping of the tool  100  on the wellhead  10 . The upward force applied to the tool  100  by the conveyance member causes an inner mandrel  170  to move from a first position ( FIG. 5A ) to a second position ( FIG. 5B ). As illustrated in  FIGS. 5A and 5B , the inner mandrel  170  includes a key member  190 . It should be noted that the key member  190  may be a separate component attached to the inner mandrel  170  as illustrated or the key member  190  may be formed as part of the mandrel  170  as a single piece. As shown in  FIG. 5B , the inner mandrel  170  has moved axially up relative to the wellhead  10 . As a result, the inner mandrel  170  (and/or the key member  190 ) contacts and applies a force to a surface  120  of the arms  125  which increases (or enhances) the gripping force applied by the arms  125  to the profile  50  on the wellhead  10 . In other words, the inner mandrel  170  applies the force to the arms  125  and that force is transferred due to the shape of each arm  125  (i.e. lever) and the pivot  130  into the gripping surface which grips the profile  50 , thereby enhancing the grip on the profile  50 . 
         [0033]    The conveyance member connected to the tool  100  may also be pulled from the surface (i.e., offshore location) to create tension in the wellhead  10  and the casing string  30 . As the conveyance member is pulled at the surface, the tool  100 , the wellhead  10 , and the casing string  30  are urged upward relative to the seafloor  20  which creates tension in the wellhead  10  and the casing string  30 . The tension created by pulling on the conveyance member may be useful during the cutting operation because tension in the casing string  30  typically prevents the cutters  110  of the rotary cutter assembly  105  from jamming (or become stuck) as the cutters  110  cut through the casing string  30 . The upward force created by pulling on the conveyance member is preferably at least equal to any downward force generated during the cutting operation. The upward force is typically maintained during the cutting operation. Optionally, the upward force may also be sufficient to counteract the wellhead assembly deadweight. 
         [0034]    During the wellhead retrieval operation, the inner mandrel  170  in the tool  100  may move between the first position as shown in  FIG. 5A  and the second position as shown in  FIG. 5B . In the first position, a portion of the inner mandrel  170  (and/or the key member  190 ) is positioned proximate a stop block  185  as shown in  FIG. 5A . In this position, the inner mandrel  170  has moved axially down relative to the wellhead  10  which typically occurs when the tension in the conveyance member attached to the tool  100  has been minimized. In the second position, a portion of the inner mandrel  170  is positioned proximate the surface  120  of the arms  125 . In this position, the inner mandrel  170  has moved axially up relative to the wellhead  10  which typically occurs when the tension in the conveyance member attached to the tool  100  has been increased. Further, in the second position, the inner mandrel  170  (and/or the key member  190 ) contacts and applies a force to the surface  120  of the arms  125  which increases (or enhances) the gripping force applied by the arms  125  to the profile  50  on the wellhead  10 . In other words, the inner mandrel  170  applies the force to the arms  125  and that force is transferred due to the shape of each arm  125  (i.e. lever) and the pivot  130  into the gripping surface which grips the profile  50 , thereby enhancing the grip on the profile  50 . 
         [0035]      FIG. 6  is a view illustrating the tool  100  after the casing string  30  has been cut. The cutters  110  on the rotary cutter assembly  105  continue to operate until a lower portion of the casing string  30  is disconnected from an upper portion of the casing string  30 . At this point, the rotary cutter assembly  105  is deactivated which causes the cutters  110  to move from the extended position to the retracted position. Next, the tool  100 , the wellhead  10 , and a portion of the casing string  30  are lifted from the seafloor  20  by pulling on the conveyance member attached to the tool  100  until the wellhead  10  is removed from the sea. After the wellhead  10  is located on the offshore location, such as the floating vessel, the cylinders  135 ,  155 ,  180  may be systematically deactivated to release the tool  100  from the wellhead  10 . 
         [0036]    In operation, the tool  100  is lowered into the sea via the conveyance member until the tool  100  is positioned proximate the top of the wellhead  10  disposed on the seafloor  20 . Next, the cylinder  135  is actuated to cause the arms  125  to rotate around pivot  130  to engage the wellhead  10 . Subsequently, the arms  125  are locked in place by actuating the cylinder  155  which causes the wedge block  150  to slide along the surface of the arms  125  to prevent the arms  125  from rotating around the pivot  130  to the unclamped position. Thereafter, the cylinder  180  is activated which causes the shoe  175  to act upon the surface  25  of the wellhead  10  and axially lift the tool  100  relative to the wellhead  10 . The axial movement of the tool  100  relative to the wellhead  10  allows for active clamping of the tool  100  on the wellhead  10 . This sequential function is automatically controlled by the onboard manifold or can be manually sequenced as required by the operator or via a ROV. Next, the conveyance member connected to the tool  100  is pulled from the surface (i.e. offshore location) to create tension on the wellhead assembly  10  and the casing string  30 . The motor  115  activates the rotary cutter assembly  105  and the blades  110  move from the retracted position to the extended position to cut through the casing string or multiple casing strings  30 . The wellhead assembly deadweight is born mechanically to leverage the load for increased clamping force on the external wellhead profile to maximize reactive torque resistance capability for high torque cutting. Axial load cylinder  180  function to stabilize and preload grip arms during cutting operation. After the casing string  30  is cut, the tool  100 , the wellhead  10  and a portion of the casing string  30  is lifted from the seafloor  20  by pulling on the conveyance member attached to the tool  100 . When the wellhead  10  is safely located on the offshore location, such as the floating vessel, the cylinders  135 ,  155 ,  180  may be systematically deactivated to release the tool  100  from the wellhead  10 . At any time during operation, the cylinder function sets  135 ,  155 ,  180  may be independently controlled and shut down or reversed for function testing, unsuccessful wellhead release, or maintenance as required through surface controls or remotely using a ROV in case of umbilical failure. 
         [0037]      FIG. 7  is a view illustrating a subsea wellhead intervention and retrieval tool  200  attached to a perforating tool  215 . For convenience, the components of the tool  200  that are similar to the components of the tool  100  will be labeled with the same reference indicator. As shown in  FIG. 7 , the tool  200  has engaged the wellhead  10  in a similar manner as described herein. 
         [0038]    The tool  200  may be attached to an optional packer member  205  that is configured to seal an annulus formed between a tubular member  220  and the casing string  30  attached to the wellhead  10 . The packer member  205  may be any type of packer known in art, such as a hydraulic packer or a mechanical packer. The packer member  205  may be used for isolation or well control. Upon activation of the packer member  205 , the packer member  205  moves from a first diameter and a second larger diameter. Upon deactivation, the packer member  205  moves from the second larger diameter to the first diameter. The packer member  205  may be activated and deactivated multiple times. 
         [0039]    The tool  200  may be attached to an optional ported sub  210  and the perforating tool  215  mounted on a pipe  225 . It is to be noted that the pipe  225 , the ported sub  210  and the perforating tool  215  may be an integral part of the tool  200  or a separate component that is lowered through the tool  200  via a conveyance member, such as pipe, coiled tubing or an umbilical. Generally, the ported sub  210  may be used in conjunction with the packer member  205  to monitor, control pressure or bleed-off pressure, gas or liquid. The ported sub  210  may also be used to pump cement into the wellbore. In one embodiment, the ported sub  210  is selectively movable between an open position and a closed position multiple times. 
         [0040]    The perforating tool  215  is generally a device used to perforate (or punch) the casing string  30  or multiple casing strings, such as casing strings  30 ,  40 . Typically, the perforating tool  215  includes several shaped explosive charges that are selectively activated to perforate the casing string. It is to be noted that the perforating tool  215  may also be used to sever or cut the casing string  30  so that the wellhead  10  may be removed in a similar manner as described herein. 
         [0041]    In operation, the tool  200  is lowered into the sea via the conveyance member and attached to the wellhead  10  disposed on the seafloor  20  in a similar manner as set forth herein. Next, the optional packer  205  may be activated. The ported sub  210  may also be activated and used as set forth herein. Additionally, the perforating tool  215  may be used to perforate (or cut) the casing string. The tool  200  may further be used to remove the wellhead  10  in a similar manner as described herein. 
         [0042]      FIG. 8  is a view illustrating a subsea wellhead intervention and retrieval tool  250  with the perforating tool  215  disposed on a wireline  255 . For convenience, the components of the tool  250  that are similar to the components of the tools  100 ,  200  will be labeled with the same reference indicator. As shown in  FIG. 8 , the tool  250  has engaged the wellhead  10  in a similar manner as described herein. As also shown in  FIG. 8 , the perforating tool  215  has been positioned in the casing string  30  by utilizing the wireline  255 . This arrangement may be useful if multiple areas are to be perforated by the perforating tool  215 . Further, the use of wireline  255  allows the capability of running the perforating tool  215  in and out of the wellbore multiple times (or runs). Additionally, the tubular member  220  is open ended thereby allowing fluid flow to be pumped through the tubular member  220 . 
         [0043]    In operation, the tool  250  is lowered into the sea via the conveyance member and attached to the wellhead  10  disposed on the seafloor  20  in a similar manner as set forth herein. Next, the optional packer  205  may be activated to create a seal between the tubular member  220  and the casing string  30 . Thereafter, the perforating tool  215  may be positioned in the casing string  30  by utilizing the wireline  255  and then activated to perforate (or cut) the casing string. The tool  250  may further be used to remove the wellhead  10  in a similar manner as described herein. 
         [0044]      FIG. 9  is a view illustrating a subsea wellhead intervention and retrieval tool  300  with the perforating tool  215 . For convenience, the components of the tool  300  that are similar to the components of tools  100 ,  200  will be labeled with the same reference indicator. As shown in  FIG. 9 , the tool  300  has engaged the wellhead  10  in a similar manner as described herein. The tool  300  includes the ported sub  210  and the perforating tool  215 . As set forth herein, the perforating tool  215  may be used to perforate (or sever) the casing string  30  or any number of casing strings, such as casing strings  30 ,  60 . Additionally, the ported sub  210  may be used in a pressure test and/or to distribute cement  55  which is pumped from the surface. 
         [0045]    In operation, the tool  300  is lowered into the sea via the conveyance member and attached to the wellhead  10  disposed on the seafloor  20  in a similar manner as set forth herein. Next, the optional packer  205  may be activated and the ported sub  210  may used as set forth herein. Additionally, the perforating tool  215  may be operated to perforate (or cut) the casing string. The tool  300  may further be used to remove the wellhead  10  in a similar manner as described herein. 
         [0046]      FIG. 10  is a view illustrating a subsea wellhead intervention and retrieval tool  350  attached to a cutter assembly  360 . For convenience, the components of the tool  350  that are similar to the components of the tool  100  will be labeled with the same reference indicator. As shown in  FIG. 10 , the tool  350  has engaged the wellhead  10  in a similar manner as described herein. 
         [0047]    The cutter assembly  360  uses a cutting stream  365  to cut the casing string  30 . In one embodiment, the cutter assembly  360  is a laser cutter. In this embodiment, the laser cutter would be connected to the surface via a fiber optic bundle (not shown). The fiber optic bundle would be used to transmit light energy to the cutter assembly  360  from lasers on the surface. The cutter assembly  360  would direct the light energy by using a series of lenses (not shown) in the cutter assembly  360  toward the casing string  30 . The light energy (i.e. cutting stream  365 ) would be used to cut the casing string  30  or perforate a hole in the casing string  30 . 
         [0048]    In another embodiment, the cutter assembly  360  is a plasma cutter. In this embodiment, the plasma cutter would be connected to the surface via a conduit line (not shown). The conduit line would be used to transmit pressurized gas to the cutter assembly  360 . The gas is blown out of a nozzle in the cutter assembly  360  at a high speed, at the same time an electrical arc is formed through that gas from the nozzle to the surface being cut, turning some of that gas to plasma. The plasma is sufficiently hot to melt the metal of the casing string  30 . The plasma (i.e. cutting stream  365 ) would be used to cut the casing string  30  or perforate a hole in the casing string  30 . 
         [0049]    In a further embodiment, the cutter assembly  360  is an abrasive cutter. In this embodiment, the abrasive cutter would be connected to the surface via a fluid conduit (not shown). The fluid conduit would be used to transmit pressurized fluid having abrasives to the cutter assembly  360 . The pressurized fluid (with abrasives) is blown out of a nozzle in the cutter assembly  360 . The pressurized fluid (i.e. cutting stream  365 ) would be used to cut the casing string  30  or perforate a hole in the casing string  30 . In another embodiment, a chemical or a high energy media may be used with the cutter assembly  360  to cut (or perforate) the casing string  30 . 
         [0050]    The tool  350  includes an optional rotating device  355  configured to rotate the cutter assembly  360 . The rotating device  355  may be controlled at the surface or downhole. The rotating device  355  may be powered by electric power or hydraulic power. Generally the rotating device  355  will rotate the cutter assembly  360  in a  360  degree rotation in order to cut the casing string  30 . The speed, direction and the timing of the rotation will also be controlled by the rotating device  355  in order to allow the cutting stream  365  to sever (or perforate) the casing string  30 . 
         [0051]    The tool  350  may be attached to an optional anchor device  370  to anchor the tool  350  to the casing string  30 . The anchor device  370  may include radially extendable members that grip the casing string  30  upon activation of the anchor device  370 . Generally, the anchor device  370  is used to stabilize (or centralize) the cutter assembly  360  in the casing string  30 . 
         [0052]    In operation, the tool  350  is lowered into the sea via the conveyance member and attached to the wellhead  10  disposed on the seafloor  20  in a similar manner as set forth herein. Next, the optional anchoring device  370  may be used to stabilize (or centralize) the cutter assembly  360  in the casing string  30 . Thereafter, the cutter assembly  360  may be activated to perforate (or cut) the casing string and the cutter assembly may be rotated by using the rotating device  355 . The tool  350  may further be used to remove the wellhead  10  in a similar manner as described herein. 
         [0053]      FIG. 11  is a view illustrating a subsea wellhead intervention and retrieval tool  400  with an explosive charge device  405 . For convenience, the components of the tool  400  that are similar to the components of tools  100 ,  200  will be labeled with the same reference indicator. As shown in  FIG. 11 , the tool  400  has engaged the wellhead  10  in a similar manner as described herein. 
         [0054]    The tool  400  includes the explosive charge device  405  for cutting (or perforating) the casing string  30  or any number of casing strings. Generally, the explosive charge device  405  includes several shaped explosive charges that are selectively activated to cut (or perforate) the casing string  30 . The explosive charge device  405  may also include a single massive explosive charge. If the casing string  30  is to be cut, the explosive charge device  405  may include a  360  degree charge which will cut (or sever) the casing string  30  upon activation. In the embodiment illustrated in  FIG. 11 , the explosive charge device  405  is part of the tool  400 . It is to be noted, however, that the explosive charge device  405  could be a separate device that is lowered through the tool  405  via a wireline or another type of conveyance member, such as coil tubing, jointed pipe or an umbilical. 
         [0055]    In operation, the tool  400  is lowered into the sea via the conveyance member and attached to the wellhead  10  disposed on the seafloor  20  in a similar manner as set forth herein. Next, the explosive charge device  405  may activated to perforate (or cut) the casing string. The tool  400  may also be used to remove the wellhead  10  in a similar manner as described herein. 
         [0056]    The subsea tool described herein may be used for subsea well intervention operations, including retrieval of a wellhead from a subsea well. In one embodiment, one or more systems or subsystems of the subsea tool may be controlled, monitored or diagnosed via Radio Frequency Identification Device (RFID) or a radio antenna array. In another embodiment, the components of the subsea tool may be activated by using a RFID electronics package with a passive RFID tag or an active RFID tag. In this embodiment, one or more components in the subsea tool, such as cylinders or an attached downhole assembly such as a cutter assembly, perforating tool, ported sub, anchoring device, etc., may include the electronics package that activates the component when the active (or passive) RFID tag is positioned proximate a suitable sensor. For instance, the subsea tool having a component with the electronics package is lowered into the sea via the conveyance member and positioned proximate the wellhead disposed on the seafloor in a similar manner as set forth herein. Thereafter, the active (or passive) RFID tag is pumped through an umbilical connected to the tool or lowered into the sea. When the active (or passive) RFID tag is detected, the relevant component may be activated. For example, the electronics package in the tool may sense the active (or passive) RFID tag then send a control signal to actuate the gripping arm. The same electronics package may sense another active (or passive) RFID tag and then send another control signal to actuate the wedge block assembly. The same electronics package may sense a further active (or passive) RFID tag and then send a further control signal to actuate the lifting cylinders. In this manner, the tool may be controlled by using the electronics package with the active (or passive) RFID tags. In a similar manner, an electronics package with the active (or passive) RFID tags may be used to activate and control a downhole assembly attached to the tool. 
         [0057]    The embodiments describe herein relate to a single subsea wellhead intervention and retrieval tool. However, it is contemplated that multiple subsea wellhead intervention and retrieval tools may be used together in a system. Each subsea wellhead intervention and retrieval tool may be independently powered or linked to a primary subsea power source for simultaneous onsite multiple unit operation. 
         [0058]    While the foregoing is directed to embodiments of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.