Patent Publication Number: US-2012043089-A1

Title: Retrieving a subsea tree plug

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application claims benefit of U.S. Prov. Pat. App. No. 61/374,182 (Atty. Dock. No. WWCI/0014USL), filed Aug. 17, 2010 and U.S. Prov. Pat. App. No. 61/408,036 (Atty. Dock. No. WWCI/0014USL2), filed Oct. 29, 2010, both of which are herein incorporated by reference in their entireties. 
    
    
     BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     Embodiments of the present invention generally relate to retrieving a subsea tree plug. 
     2. Description of the Related Art 
     Subsea crude oil and/or natural gas wells frequently require workover to maintain adequate production. Workover operations may include perforating, gravel packing, production stimulation and repair of a downhole completion or production tubing. During the workover, specialized tools are lowered into the well by means of a wireline and winch. This wireline winch is typically positioned on the surface and the workover tool is lowered into the well through a lubricator and blowout preventer (BOP). Workover operations on subsea wells require specialized intervention equipment to pass through the water column and to gain access to the well. The system of valves on the wellhead is commonly referred to as a production or Christmas tree and the intervention equipment is attached to the tree with a blowout preventer (BOP). 
     The commonly used method for accessing a subsea well first requires installation of a BOP with a pre-attached tree running tool (TRT) for guiding the BOP to correctly align and interface with the tree. The BOP/running tool is lowered from a derrick that is mounted on a mobile offshore drilling unit (MODU), such as a drill ship or semi-submersible platform. The BOP/TRT is lowered on a segmented length of pipe called a workover riser string. The BOP/TRT is lowered by adding sections of pipe to the riser string until the BOP/TRT is sufficiently deep to allow landing on the tree. After the BOP is attached to the tree, the workover tool is lowered into the well through a lubricator mounted on the top of the riser string. The lubricator provides a sealing system at the entrance of the wireline that maintains the pressure and fluids inside the well and the riser string. The main disadvantage of this method is the large, specialized MODU that is required to deploy the riser string and the riser string needed to deploy the BOP. 
       FIG. 1A  illustrates a prior art completed subsea well. A wellbore  10  has been drilled from a floor if of the sea  1  into a hydrocarbon-bearing (i.e., crude oil and/or natural gas) reservoir (not shown). A string of casing (not shown) has been run into the wellbore and set therein with cement (not shown). The casing has been perforated to provide to provide fluid communication between the reservoir and a bore of the casing. A wellhead (not shown) has been mounted on an end of the casing string. A string of production tubing  10   p  (see  FIG. 1B ) may extend from the wellhead (not shown) to the formation to transport production fluid from the formation to the seafloor  1   f.  A packer (not shown) may be set between the production tubing  10   p  and the casing to isolate an annulus  10   a  (see  FIG. 1B ) formed between the production tubing  10   p  and the casing (not shown) from production fluid. 
       FIG. 1B  illustrates a prior art horizontal production tree  50 . The production tree  50  may be connected to the wellhead, such as by a collet, mandrel, or clamp tree connector. The tree  50  may be vertical or horizontal. If the tree is vertical (not shown), it may be installed after the production tubing  10   p  is hung from the wellhead. If the tree  50  is horizontal (as shown), the tree may be installed and then the production tubing  10   p  may be hung from the tree  50 . The tree  50  may include fittings and valves to control production from the wellbore into a pipeline (not shown) which may lead to a production facility (not shown), such as a production vessel or platform. The tree  50  may also be in fluid communication with a hydraulic conduit (not shown) controlling a subsurface safety valve SSV  10   v  (not shown). 
     The tree  50  may include a head  51 , a wellhead connector  52 , a tubing hanger  53 , an internal cap  54 , an external cap  55 , an upper crown plug  56   u,  a lower crown plug  56   l,  a production valve  57   p,  and one or more annulus valves  57   u,l.  Each of the components  51 - 54  may have a longitudinal bore extending therethrough. The tubing hanger  53  and head  51  may each have a lateral production passage formed through walls thereof for the flow of production fluid. The tubing hanger  53  may be disposed in the head bore. The tubing hanger  53  may support the production tubing  10   p.  The tubing hanger  53  may be fastened to the head by a latch  53   l.  The latch  53   l  may include one or more fasteners, such as dogs, and an actuator, such as a cam sleeve. The cam sleeve may be operable to push the dogs outward into a profile formed in an inner surface of the tree head  51 . The latch  53   l  may further include a collar for engagement with a running tool (not shown) for installing and removing the tubing hanger  53 . 
     The tubing hanger  53  may be rotationally oriented and longitudinally aligned with the tree head  51 . The tubing hanger  53  may further include seals  53   s  disposed above and below the production passage and engaging the tree head inner surface. The tubing hanger  53  may also have a number of auxiliary ports/conduits (not shown) spaced circumferentially there-around. Each port/conduit may align with a corresponding port/conduit (not shown) in the tree head  51  for communicating hydraulic fluid or electricity for various purposes to tubing hanger  53 , and from tubing hanger  53  downhole, such as for operation of the SSV. The tubing hanger  53  may have an annular, partially spherical exterior portion that lands within a partially spherical surface formed in tree head  51 . 
     The annulus  10   a  may communicate with an annulus passage formed through and along the head  51  for and bypassing the seals  53   s.  The annulus passage may be accessed by removing internal tree cap  54 . The tree cap  54  may be disposed in head bore above tubing hanger  53 . The tree cap  54  may have a downward depending isolation sleeve received by an upper end of tubing hanger  53 . Similar to the tubing hanger  53 , the tree cap  54  may include a latch  54   l  fastening the tree cap to the head  51 . The tree cap  54  may further include a seal  54   s  engaging the head inner surface. The production valve  57   p  may be disposed in the production passage and the annulus valves  57   u,l  may be disposed in the annulus passage. Ports/conduits (not shown) may extend through the tree head  51  to a tree controller (not shown) for electrical or hydraulic operation of the valves. 
     The upper crown plug  56   u  may be disposed in tree cap bore and the lower crown plug  56   l  may be disposed in the tubing hanger bore. Each crown plug  56   u,l  may have a body with a metal seal on its lower end. The metal seal may be a depending lip that engages a tapered inner surface of the respective cap and hanger. The body may have a plurality of windows which allow fasteners, such as dogs, to extend and retract. The dogs may be pushed outward by an actuator, such as a central cam. The cam may have a profile on its upper end. The cam may move between a lower locked position and an upper position freeing dogs to retract. A retainer may secure to the upper end of body to retain the cam. 
     SUMMARY OF THE INVENTION 
     Embodiments of the present invention generally relate to retrieving a subsea tree plug. In one embodiment, a method for riserless intervention of a subsea well includes: lowering a pressure control assembly (PCA) from a vessel to a subsea production tree; fastening the PCA to the tree; deploying a plug running tool (PRT) into the PCA, wherein the PRT comprises a latch, an anchor, and a stroker; engaging the latch with a plug of the tree; engaging the anchor with the PCA; and operating the stroker to pull the latch and the plug from the tree. 
     In another embodiment, a plug running tool (PRT) for riserless intervention of a subsea well includes: a cablehead for connection to a wireline; a hydraulically operated anchor connected to the cablehead; a hydraulically operated stroker comprising a housing and a shaft, the housing connected to the anchor; an electric pump connected to the cablehead for operating the stroker and the anchor; and a latch connected to the shaft and comprising a gripper and an actuator operable to lock and release the gripper, wherein the PRT is tubular. 
    
    
     
       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. 
         FIG. 1A  illustrates a prior art completed subsea well.  FIG. 1B  illustrates a prior art horizontal production tree. 
         FIG. 2A  illustrates a pressure control assembly (PCA), according to one embodiment of the present invention.  FIG. 2B  illustrates deployment of the PCA to the subsea production tree, according to another embodiment of the present invention.  FIG. 2C  illustrates deployment of a control pod to the PCA using an umbilical.  FIG. 2D  illustrates deployment and connection of a fluid conduit to the tree. 
         FIG. 3A  illustrates a plug running tool (PRT) and a wireline module for deploying the PRT, according to another embodiment of the present invention.  FIGS. 3B and 3C  illustrate operation of a stroker of the PRT. 
         FIG. 4A  illustrates deployment of the PRT and wireline module to the subsea production tree, according to another embodiment of the present invention.  FIG. 4B  illustrates connection of the wireline module to the PCA.  FIG. 4C  illustrates deployment of the PRT to the upper crown plug.  FIG. 4D  illustrates engagement of a latch of the PRT with the upper crown plug.  FIG. 4E  illustrates preparation of a stroker of the PRT to remove the upper crown plug.  FIG. 4F  illustrates removal of the upper crown plug.  FIG. 4G  illustrates washing the upper crown plug.  FIG. 4H  illustrates retrieval of the wireline module, PRT, and upper crown plug. 
         FIG. 5A  illustrates deployment of a modified PRT to install a tree saver in the tree.  FIG. 5B  illustrates operation of the stroker to seat the tree saver in the tree.  FIG. 5C  illustrates release of the PRT from the tree saver.  FIG. 5D  illustrates the tree ready for intervention. 
         FIG. 6  illustrates an intervention operation being conducted using a coiled tubing module connected to the PCA, according to another embodiment of the present invention. 
         FIG. 7A  illustrates a PRT having a vibratory jar, according to another embodiment of the present invention.  FIGS. 7B-7D  illustrate operation of the vibratory jar in upstroke mode. 
     
    
    
     DETAILED DESCRIPTION 
       FIG. 2A  illustrates a pressure control assembly (PCA)  100 , according to one embodiment of the present invention. The PCA  100  may include a tree adapter  105 , a fluid sub  110 , an isolation valve  115 , a blow out preventer (BOP) stack  120 , a tool housing (aka lubricator riser)  125 , a frame  130 , a manifold  135 , a pod receptacle  140 , and one or more accumulators  145  (two shown). The tree connector  105 , fluid sub  110 , isolation valve  115 , BOP stack  120 , and tool housing  125  may each include a housing or body having a longitudinal bore therethrough and be connected, such as by flanges, such that a continuous bore is maintained therethrough. The bore may have a large drift diameter, such as greater than or equal to four, five, six, or seven inches to accommodate a bottom hole assembly (BHA) of a workstring (discussed more below) and the crown plugs  56   u,l  of the tree  50 . 
     The tree adapter  105  may include a connector, such as dogs  105   d,  for fastening the PCA  100  to an external profile  51   p  of the tree  50  and a seal sleeve  105   s  for engaging an internal profile  54   p  of the tree. The tree adapter  105  may further include an electric or hydraulic actuator and an interface, such as a hot stab, so that a remotely operated subsea vehicle (ROV)  180  (see  FIG. 2B ) may operate the actuator for engaging the dogs  105   d  with the external profile  51   p.  The frame  130  may be connected to the tree connector  50 , such as by fasteners (not shown). The manifold  135  may be fastened to the frame  130 . The fluid sub  110  may include a housing having a bore therethrough and a port  110   p  in communication with the bore. The port  110   p  may be in fluid communication with the manifold  135  via a conduit (not shown). 
     The isolation valve  115  may include a housing, a valve member  115   v  disposed in the housing bore and operable between an open position and a closed position, and an actuator  115   a  operable to move the valve member between the positions. The actuator  115   a  may be electric or hydraulic and may be in communication with a stab plate (not shown) of the pod receptacle  140 . The isolation valve  115  may further operate as a check valve in the closed position: allowing fluid flow downward from the tool housing into the wellbore and preventing reverse fluid flow therethrough. Alternatively, the isolation valve  115  may be bi-directional when closed, the PCA  100  may further include a bypass conduit (not shown) connected to a port of a drain sub (not shown) disposed between the isolation valve and the BOP stack, and the drain port may include a check valve allowing downward flow and preventing reverse flow. 
     The BOP stack  120  may include one or more hydraulically operated ram preventers  120   b,w,  such as a blind-shear preventer  120   b  and one or more workstring preventers  120   w,  such as a wireline preventer and a coiled tubing preventer (only one workstring preventer shown) connected together via bolted flanges. Each ram preventer  120   b,w  may include two opposed rams disposed within a body. The body may have a bore that is aligned with the wellbore. Opposed cavities may intersect the bore and support the rams as they move radially into and out of the bore. A bonnet may be connected to the body on the outer end of each cavity and may support an actuator that provides the force required to move the rams into and out of the bore. Each actuator may include a hydraulic piston to radially move each ram and a mechanical lock to maintain the position of the ram in case of hydraulic pressure loss. The lock may include a threaded rod, a motor (not shown) for rotationally driving the rod, and a threaded sleeve. Once each ram is hydraulically extended into the bore, the motor may be operated to push the sleeve into engagement with the piston. Each actuator may include single (shown) or dual pistons (not shown). The blind-shear preventer  120   b  may cut the workstring, such as coiled tubing, wireline, and even drill pipe, when actuated and seal the bore. The coiled tubing preventer may seal against an outer surface of coiled tubing when actuated and the wireline preventer may seal against an outer surface of the wireline when actuated. 
     The tool housing  125  may be of sufficient length to contain either a plug running tool (PRT)  300  ( FIG. 3A ) or a BHA (not shown) so that the PCA  100  may be closed while deploying either a wireline module  200  ( FIG. 3A ) or a coiled tubing module  400  ( FIG. 6 .) The tool housing  125  may have a connector profile  125   c  for receiving an adapter of either workstring module  200 ,  400 . 
     The pod receptacle  140  may be operable to receive a subsea control pod  160  ( FIG. 2B ). The receptacle may include a base  141 , a latch  142 , and an actuator  143 . The base  141  be connected to the frame  130 , such as by fasteners, and may include a landing plate for supporting the pod  160 , a landing guide (not shown), such as a pin, and the stab plate. The stab plate may provide communication, such as electric (power and/or data), hydraulic, or optic, between the pod  160  and components of the PCA  100 . The latch  142  may be pivoted to the base  141 , such as by a fastener, and be movable by the actuator  143  between an engaged position ( FIG. 2D ) and a disengaged position (shown). The actuator  143  may be a piston and cylinder assembly connected to the frame  135  and the receptacle  140  may further include an interface (not shown), such as a hot stab, so that the ROV  180  may operate the actuator  143 . The actuator  143  may also be in communication with the stab plate for operation by the pod  160 . The latch  142  may include outer members and a crossbar (not shown) connected to each of the outer members by a shearable fastener  144 . The actuator  143  may be dual function so that the latch may be locked in either of the positions by either the pod  160  or the ROV  180 . 
     The control pod  160  may be in electric, hydraulic, and/or optic communication with a control van  151  onboard a support vessel  175  ( FIG. 2B ) via an umbilical  165  ( FIG. 2D ). The pod  160  may include one or more control valves (not shown) in communication with the BOP stack  120  (via the stab plate) for operating the BOP stack. Each control valve may include an electric or hydraulic actuator in communication with the umbilical  165 . The umbilical  165  may include one or more hydraulic or electric control conduit/cables for each actuator. The accumulators  145  may store pressurized hydraulic fluid for operating the BOP stack  120 . Additionally, the accumulators  145  may be used for operating one or more of the other components of the PCA  100 . The accumulators  145  may be charged via a conduit of the umbilical  165  or by the ROV  180 . 
     The umbilical  165  may further include hydraulic, electric, and/or optic control conduit/cables for operating valves of the manifold  135 , the actuators  115   a,    143 , tree valves  57   p,u,l  and the various functions of the workstring modules  200 ,  400  (discussed below). The stab plate may further include an output for the workstring modules  200 ,  400  and an output for the tree  50 . Each output may include an ROV operable connector for receiving a respective jumper  166 ,  266 ,  466  (aka flying lead) ( FIGS. 2D ,  4 B, and  6 ). The ROV  180  may connect the tree jumper  166  to a control panel (not shown) of the tree  50  and the workstring jumpers  266 ,  466  to a respective control relay of the workstring modules  200 ,  400 . The umbilical  165  may further include one or more layers of armor (not shown) made from a high strength metal or alloy, such as steel, for supporting the umbilical&#39;s own weight and weight of the control pod  160 . 
     The control pod  160  may further include a microprocessor based controller, a modem, a transceiver, and a power supply. The power supply may receive an electric power signal from a power cable of the umbilical  165  and convert the power signal to usable voltage for powering the pod components as well as any of the PCA components. The PCA  100  may further include one or more pressure sensors (not shown) in communication with the PCA bore at various locations. The workstring modules  200 ,  400  may also include one or more pressure sensors in communication with a respective bore thereof at various locations. The pressure sensors may be in data communication with the pod controller. The modem and transceiver may be used to communicate with the control van  151  via the umbilical  165 . The power cable may be used for data communication or the umbilical  165  may further include a separate data cable (electric or optic). The control van  151  may include a control panel (not shown) so that the various functions of the PCA  100 , the tree  50 , and the workstring modules  200 ,  400  may be operated by an operator on the vessel  175 . 
     The control pod  160  may also include a dead-man&#39;s switch (not shown) for closing the BOP stack  120  in response to a loss of communication with the control van  151 . Alternatively, instead of having individual conduits/cables for controlling each function of the PCA  100 , tree  50 , and workstring modules  200 ,  400 , the pod controller may receive multiplexed instruction signals from the van operator via a single electric, hydraulic, or optic control conduit/cable of the umbilical  165  and then operate the various functions using individual conduits/cables extending from the control pod  160 . 
     The manifold  135  may include one or more actuated valves (not shown) and one or more couplings, such as dry break coupling  147   f,  for receiving a respective fluid conduit  170  ( FIG. 2D ) from the vessel  175 . Actuators of the manifold valves and couplings of dry break connections  147   a  ( FIG. 2D , only one shown) may be in communication with the control pod  160  via the stab plate. Two fluid conduits  170  (only one shown) may extend from a vessel  175  to the manifold  135  for fluid circulation. A first one of the manifold valves may be in fluid communication with a first one of the couplings of dry break connections  147   a  and a fluid conduit extending to the port  110   p.  A second one of the manifold valves may be in fluid communication with a second one of the couplings (not shown) of dry break connections  147   a  and another ROV operable connector for receiving a jumper  276 ,  476  ( FIGS. 4B and 6 ) providing fluid communication with a respective junction plate of the workstring modules  200 ,  400 . 
     The coupling  147   f  may be a female coupling of a passive dry-break connection  147   p  ( FIG. 2D ) (no actuator, tension release) and the dry break connections  147   a  may each have actuators for release. Each of the dry break actuators may also have a shearable release. Suitable dry break connections are discussed and illustrated at FIGS. 3A-3C of U.S. patent application Ser. No. 13/095,596, filed Apr. 27, 2011 (Atty. Dock. No. WWCI/0010US), which is herein incorporated by reference in its entirety. 
       FIG. 2B  illustrates deployment of the PCA  100  to the subsea production tree  50 , according to another embodiment of the present invention. The support vessel  175  may be deployed to a location of the subsea tree  50 . The support vessel  175  may be a light or medium intervention vessel and include a dynamic positioning system to maintain position of the vessel  175  on the waterline  1   w  over the tree  50  and a heave compensator (not shown) to account for vessel heave due to wave action of the sea  1 . Alternatively, the vessel  175  may be a MODU. The vessel  175  may further include a tower  178  located over a moonpool  177  and a winch  179 . The winch  179  may include a drum having wire rope  190  wrapped therearound and a motor for winding and unwinding the wire rope, thereby raising and lowering a distal end of the wire rope relative to the tower. Alternatively, a crane (not shown) may be used instead of the winch and tower. The vessel  175  may further include a wireline winch  176 . 
     The ROV  180  may be deployed into the sea  1  from the vessel  175 . The ROV  180  may be an unmanned, self-propelled submarine that includes a video camera, an articulating arm, a thruster, and other instruments for performing a variety of tasks. The ROV  180  may further include a chassis made from a light metal or alloy, such as aluminum, and a float made from a buoyant material, such as syntactic foam, located at a top of the chassis. The ROV  180  may be controlled and supplied with power from vessel  175 . The ROV  180  may be connected to support vessel  175  by an umbilical  181 . The umbilical  181  may provide electrical (power), hydraulic, and/or data communication between the ROV  180  and the support vessel  175 . An operator on the support vessel  175  may control the movement and operations of ROV  180 . The umbilical  181  may be wound or unwound from drum  182 . 
     The ROV  180  may be deployed to the tree  50 . The ROV  180  may transmit video to the ROV operator for inspection of the tree  50 . The ROV  180  may remove the external cap  55  from the tree  50  and carry the cap to the vessel  175 . Alternatively, the winch  179  may be used to transport the external cap  55  to the waterline  1   w.  The ROV  115  may then inspect an internal profile of the tree  50 . The wire rope  190  may then be used to lower the PCA  100  to the tree  50  through the moonpool  177  of the vessel  175 . The ROV  180  may guide landing of the PCA  100  on the tree  50 . The ROV  180  may then operate the adapter connector  105   d  to fasten the PCA  100  to the tree  50 . 
       FIG. 2C  illustrates deployment of the control pod  160  to the PCA  100  using the umbilical  165 . The vessel  175  may further include a launch and recovery system (LARS)  150  for deployment of the control pod  160  and the umbilical  165 . The LARS  150  may include a frame, an umbilical winch  152 , a boom  153 , a boom hoist  154 , a load winch  155 , and a hydraulic power unit (HPU, not shown). The LARS  150  may be the A-frame type (shown) or the crane type (not shown). For the A-frame type LARS  150 , the boom  153  may be an A-frame pivoted to the frame and the boom hoist  154  may include a pair of piston and cylinder assemblies (PCAs), each PCA pivoted to each beam of the boom and a respective column of the frame. The HPU may include a hydraulic fluid reservoir, a hydraulic pump, and one or more control valves for selectively providing fluid communication between the reservoir, the pump, and the PCAs  154 . The hydraulic pump may be driven by an electric motor. 
     The umbilical  165  may include an upper portion  161  and a lower portion  162  fastened together by a shearable connection  163 . Each winch  152 ,  155  may include a drum having the respective umbilical upper portion  161  or load line  156  wrapped therearound and a motor for rotating the drum to wind and unwind the umbilical upper portion or load line  156 . The load line  156  may be wire rope. Each winch motor may be electric or hydraulic. An umbilical sheave and a load sheave may each hang from the A-frame  153 . The umbilical upper portion  161  may extend through the umbilical sheave and an end of the umbilical upper portion may be fastened to the shearable connection  163 . The frame may have a platform for the control pod  160  to rest. The umbilical lower portion  162  may be coiled and have a first end fastened to the shearable connection  163  and a second end fastened to the control pod  160 . The load line  161  may extend through the load sheave and have an end fastened to the lifting lugs of the control pod, such as via a sling. Pivoting of the A-frame boom  153  relative to the platform by the PCAs  154  may lift the control pod  160  from the platform, over a rail of the vessel  175 , and to a position over the waterline  1   w.  The load winch  155  may then be operated to lower the control pod  160  into the sea  1 . 
     A length of the umbilical lower portion  162  may be sufficient to provide slack to account for vessel heave. A length of the umbilical lower portion  162  may also be sufficient so that the shearable connection  163  is at or slightly above a depth of a top of the workstring modules  200 ,  400 . A length of the load line  156  may correspond to the length of the umbilical lower portion  162 . As the load winch  155  lowers the control pod  160 , the umbilical lower portion  162  may uncoil and be deployed into the sea  1  until the shearable connection  163  is reached. Once the shearable connection  163  is reached, a clump weight  164  may be fastened to a lower end of the umbilical upper portion  161 . The control pod  160  may continue to be lowered using the load winch  155  until the shearable connection  163  and clump weight  164  are deployed from the LARS platform to over the waterline  1   w.  The umbilical winch  161  may then be operated to support the control pod  160  using the umbilical  165  and the load line  156  slacked. The load line  156  and sling may be disconnected from the control pod  160  by the ROV  180 . Alternatively, the load line  156  may be wireline and the sling may have an actuator in communication with the wireline so that the van operator may release the sling. The control pod  160  may then be lowered to a landing depth (clump weight  164  and shearable connection  163  at or above top of workstring module  200 ,  400 ) using the umbilical winch  152 . 
     The PCA  100  may be deployed with the latch  142  locked in the disengaged position. Alternatively, the ROV  180  may operate the actuator  143  to disengage the latch after the PCA  100  has landed. As the control pod  160  is being lowered to the landing depth, the ROV  180  may grasp the control pod and assist in landing the control pod in the receptacle  140 . Once landed, the ROV  180  may engage the latch  142  with the pod  160 . The ROV  180  may then connect the jumper  166  to the tree control panel. The operator in the control van  151  may then close then close the tree valves  57   u,l,p  and the SSV via the umbilical  165 . 
       FIG. 2D  illustrates deployment and connection of a fluid conduit  170  to the tree  50 . An upper portion of each fluid conduit  170  may be coiled tubing  171 . The vessel  175  may further include a coiled tubing unit (CTU, not shown) for each fluid conduit  170 . Each CTU may include a drum having the coiled tubing  171  wrapped therearound, a gooseneck, and an injector head for driving the coiled tubing  171 , controls, and an HPU. Alternatively, each CTU may be electrically powered. A lower portion of each fluid conduit  170  may include a hose  172 . The hose  172  may be made from a flexible polymer material, such as a thermoplastic or elastomer or may be a metal or alloy bellows. The hose  172  may or may not be reinforced, such as by metal or alloy cords. An upper end of the hose  172  may be connected to the coiled tubing  171  by the passive dry beak connection  147   p  and a lower end of the hose  172  may have a male coupling (of the actuated connection  147   a ) connected thereto. The hose  172  may include two or more sections (only one section shown), each section fastened together, such as by a flanged or threaded connection. During deployment of the fluid conduit  170 , a clump weight  173  may be fastened to the lower end of the coiled tubing  171 . 
     The lower portion  172  of the fluid conduit  170  may be assembled on the vessel  175  and deployed into the sea  1  using the CTU. The coiled tubing  171  may be deployed until the clump weight  173  and passive dry break connection  147   p  are at or slightly above a depth of a top of the workstring modules  200 ,  400 . The ROV  180  may then grasp the male coupling of the actuated connection  147   a  and guide the coupling to the manifold  135 . A length of the hose  172  may be sufficient to provide slack in the fluid coupling  170  to account for vessel heave. The van operator may operate the dry break connection actuator to the unlocked position. The ROV  180  may then insert the male coupling into the female coupling and the van operator may lock the connection  147   a.  The operation may then be repeated for the second fluid conduit. 
     An emergency disconnect system (EDS) may include the shearable fasteners  144 , dry break connections  147   a,p,  the shearable connection  163 , the clump weights  164 ,  173 , and the lower portions  162 ,  172 . The EDS may allow the vessel  175  to drift or drive off in the event of a minor or major emergency (see FIGS. 5B and 5C of the &#39;596 application and the accompanying discussion thereof). 
       FIG. 3A  illustrates the PRT  300  and a wireline module  200  for deploying the PRT, according to another embodiment of the present invention. The wireline module  200  may include an adapter  205 , a fluid sub  210 , an isolation valve  215 , one or more stuffing boxes  220   u,l,  a grease injector  225 , a frame  230 , a control relay  260 , an interface, such as a junction plate  235 , a tool catcher  240 , a grease reservoir  245   r,  and a grease pump  245   p.  The adapter  205 , fluid sub  210 , isolation valve  215 , stuffing boxes  220   u,l,  grease injector  225 , and tool catcher  240  may each include a housing or body having a longitudinal bore therethrough and be connected, such as by flanges, such that a continuous bore is maintained therethrough. 
     The adapter  205  may include a connector for mating with the connector profile  125   c,  thereby fastening the wireline module  200  to the PCA  100 . The connector may be dogs or a collet. The adapter  205  may further include a seal face or sleeve and a seal (not shown). The adapter  205  may further include an actuator (not shown), such as a piston and a cam, for operating the connector. The adapter  205  may further include an ROV interface (not shown) so that the ROV  180  may connect to the connector, such as by a hot stab, and operate the connector actuator. Alternatively, the adapter  205  may have the connector profile instead of the connector and the tool housing  125  may have the connector in communication with the control pod  160  for operation by the van operator. The fluid sub  210  may include a housing having a bore therethrough and a port  210   p  in communication with the bore. The port  210   p  may be in fluid communication with the junction plate  235  via a conduit (not shown). The frame  230  may be fastened to the adapter  205  and the relay  260  and interface  235  may be fastened to the frame. The pump  245   p  and reservoir  245   r  may also be fastened to the frame  230 . 
     The isolation valve  215  may include a housing, a valve member  215   v  disposed in the housing bore and operable between an open position and a closed position, and an actuator  215   a  operable to move the valve member between the positions. The actuator  215   a  may be electric or hydraulic and may be in communication with the control relay  260  via a conduit (not shown). The actuator  215   a  may fail to the closed position in the event of an emergency. The isolation valve  215  may be further operable to cut wireline  290  ( FIG. 4A ) when closed or the wireline module  200  may further include a separate wireline cutter. The isolation valve  215  may further operate as a check valve in the closed position: allowing fluid flow downward from the stuffing box  220   l  toward the PCA  100  and preventing reverse fluid flow therethrough. 
     Each stuffing box  220   u,l  may include a seal  220   s,  a piston  220   a,  and a spring  220   b  disposed in the housing. A port  220   p  may be formed through the housing in communication with the piston  220   a.  The port  220   p  may be connected to the control relay  260  via a hydraulic conduit (not shown). When operated by hydraulic fluid, the piston  220   a  may longitudinally compress the seal  220   s,  thereby radially expanding the seal inward into engagement with the wireline  290 . The spring  220   b  may bias the piston  220   a  away from the seal  220   s  and be set to balance hydrostatic pressure. Alternatively, an electric actuator may be used instead of the piston  220   a.    
     The grease injector  225  may include a housing integral with each stuffing box housing and one or more seal tubes  225   t.  Each seal tube  225   t  may have an inner diameter slightly larger than an outer diameter of the wireline  290 , thereby serving as a controlled gap seal. An inlet port  225   i  and an outlet port  225   o  may be formed through the grease injector/stuffing box housing. A grease conduit (not shown) may connect an outlet of the grease pump  245   p  with the inlet port  225   i  and another grease conduit (not shown) may connect the outlet port  225   o  with the grease reservoir  245   r.  Another grease conduit (not shown) may connect an inlet of the pump  245   p  to the reservoir  245   r.  Alternatively, the outlet port  225   o  may discharge into the sea  1 . The grease pump  245   p  may be electrically or hydraulically driven via cable/conduit (not shown) connected to the control relay  260  and may be operable to pump grease (not shown) from the grease reservoir  245   r  into the inlet port  225   i  and along the slight clearance formed between the seal tube  225   t  and the wireline  290  to lubricate the wireline, reduce pressure load on the stuffing box seals  220   s,  and increase service life of the stuffing box seals. The grease reservoir  245   r  may be recharged by the ROV  180 . 
     The tool catcher  240  may include a piston  240   a,  a latch, such as a collet  240   c,  a stop  240   s,  a piston spring  240   b,  and a latch spring  240   d  disposed in a housing thereof. The collet  240   c  may have an inner cam surface for engagement with a fishing neck of the PRT  300  and/or BHA and the catcher housing may have an inner cam surface for operation of the collet  240   c.  The latch spring  240   d  may bias the collet  240   c  toward a latched position. The collet  240   c  may be movable from the latched position to an unlatched position either by engagement with a cam surface of the fishing neck and relative longitudinal movement of the fishing neck upward toward the stop  240   s  or by operation of the piston  240   a.  Once the cam surface of the fishing neck/BHA has passed the cam surface of the collet  240   c,  the latch spring  240   d  may return the collet to the latched position where the collet may be engagable with a shoulder of the fishing neck, thereby preventing longitudinal downward movement of the PRT/BHA relative to the catcher  240 . The catcher housing may have a hydraulic port  240   p  formed through a wall thereof in fluid communication with the piston  240   a.  A hydraulic conduit (not shown) may connect the hydraulic port to the control relay  260 . The piston  240   a  may be biased away from engagement with the collet  240   c  by the piston spring  240   b.  When operated, the piston  240   a  may engage the collet  240   c  and move the collet upward along the housing cam surface and into engagement with the stop  240   s,  thereby moving the collet to the unlatched position. Alternatively, an electric actuator may be used instead of the piston. 
     The PRT  300  may be tubular and include a stroker  301 , an electric pump  302 , a cablehead  303 , an anchor  310 , and a latch  350 . The stroker  301 , electric pump  302 , cablehead  303 , and anchor  310 , may each include a housing or body connected, such as by threaded connections. The stroker  301  may include the housing  305  and a shaft  309  ( FIG. 3B ). The cablehead  303  may include an electronics package (not shown) for controlling operation of the PRT  300 . The electronics package may include a programmable logic controller (PLC) having a transceiver in communication with the wireline  290  for transmitting and receiving data signals to the vessel  175 . The electronics package may also include a power supply in communication with the PLC and the wireline  290  for powering the electric pump, the PLC, and various control valves. The electric pump  302  may include an electric motor, a hydraulic pump, and a manifold. The manifold may be in fluid communication with the various PRT  300  components and include one or more control valves for controlling the fluid communication between the manifold and the components. Each control valve actuator may be in communication with the PLC. The cablehead  303  may connect the PRT  300  to the wireline module  200 , such as by engagement of a shoulder with a corresponding shoulder formed in the stop  240   s.  The anchor  310  may include two or more radial piston and cylinder assemblies and a die connected to each piston or two or more slips operated by a slip piston. 
     The latch  350  may include a housing  355 . The housing  355  may be fastened to the shaft  309 , such as by a threaded connection. The latch  350  may further include a gripper  360 , such as a collet, connected to an end of the housing  355 . The latch  350  may further include a locking piston  365  disposed in a chamber formed in the housing  355  and operable between a locked position in engagement with the collet  360  and an unlocked position disengaged from the collet. The locking piston  365  may be biased toward the locked position by a biasing member  375   l,  such as a spring. The locking piston  365  may be in fluid communication with the stroker pump  302  via a passage  355   l  formed through the housing  355 , a passage (not shown) formed through the shaft  309  and via a hydraulic swivel (not shown) disposed between the stroker housing  305  and shaft. 
     The latch  350  may further include a release piston  370  disposed in a chamber formed in the housing  355  and operable between an extended position in engagement with a body of the crown plug  56   u  and retracted position so as not to interfere with operation of the collet  360 . The release piston  370  may be biased toward the retracted position by a biasing member  370   r,  such as a spring. The release piston  370  may also be in fluid communication with the stroker pump  302  via a passage  355   r  formed through the housing  355 , a second passage (not shown) formed through the shaft  309  and via the hydraulic swivel (not shown) disposed between the stroker housing  305  and shaft. The release piston  370  may also serve as a landing shoulder. The release piston  370  may include a contact sensor or switch (not shown) in fluid or electrical communication with the PLC via a port or leads (not shown) extending through the housing  355  to the shaft  309  and from the shaft  309  to the stroker housing  305  via the swivel. 
     Alternatively, flexible conduit and/or flexible cable may be used instead of the hydraulic swivel. 
       FIGS. 3B and 3C  illustrate operation of a stroker  301  of the PRT. The stroker  301  may include the housing  305  which is penetrated by the shaft  309 . A piston  308  may be provided around the shaft  309  so that the shaft  309  may move longitudinally within the housing  305  for providing the longitudinal force P. The piston  308  may be provided with a seal  316  in order to provide a sealing connection between the inside of the housing  305  and the outside of the piston  308 . 
     The housing  305  may include a tube  314  which is closed by two rings  315  for forming a chamber  325 . The rings  315  may each have a seal  316 , such as an O-ring, in order to provide a sealing connection between the rings  315  and the shaft  309 . In this way, the chamber  325  may be divided into upper  325   u  and lower  325   l  portions. Each portion may be in fluid communication with the pump  302  via respective ducts  313 . The pump  302  may pump hydraulic fluid  311  into the upper portion  325   u  by sucking a corresponding amount of hydraulic fluid  311  from the lower portion  325   l.  Thus, the piston  308  and, consequently, the shaft  309  are driven forward and away from the pump  302  providing the longitudinal force P downward. Operation of the stroker may be reversed by reversing operation of the pump  302  or by including directional valves in the manifold. 
     The upper portion  325   u  may be provided with a duct  313  at the end closest to the pump  302 , and the lower portion  325   l  may be provided with a duct  313  at the rearmost end in relation to the pump  302 . In this way, the fluid  311  can be sucked or pumped into each chamber until the piston  308  almost abuts the ring  315  of the housing  305 . The PRT  300  may be a closed system, meaning that the same fluid is recirculated being pumped back and forth to operate the various components. 
     Additionally, the stroker  301  may have two or more chambers in order to provide more longitudinal force P. Each chamber may be independently operated by the PLC in order to control the longitudinal force exerted by the stroker. For example, the tube  314  may be divided by five rings  315  into four chambers  325  (not shown). The shaft  309  may penetrate all of the chambers  325  and four pistons  308  may be provided on the shaft  309  so that each piston  308  is provided in one of the four piston chambers  325 . The additional ducts  313  connecting the pump  302  to the chambers  325  may be placed along the circumference of the tube  314 . 
     Six sets of ducts  313  can be seen in the cross-sectional view of  FIG. 3C . The twelve ducts  313  may be used to lead fluid  311  back and forth between six chambers  325  or each chamber portion may have multiple ducts leading thereto. For example, four sets of ducts  313  may provide fluid  311  for four chambers  325 , and the last two sets of ducts  313  may be extra fluid connections to the two chambers  225  positioned furthest from the pump  302  so as to compensate for the extra distance the fluid  311  has to travel. 
     Alternatively, the PRT  300  may be deployed and operated with coiled tubing  490  or electric coiled tubing instead of wireline  290  and the pump may be omitted and a pump of the vessel  100  used instead. Alternatively, the PRT  300  may be electrically operated instead of hydraulically operated. 
     As shown in  FIG. 3C , the housing  305  may include an outer tube  314   o  and an inner tube  314   i.  The outer tube  314   o  may be constructed to withstand the pressure difference between the tube bore and its surroundings. A wall  320   i  of the inner tube  314   i  may be substantially thinner than a wall  320   o  of the outer tube  314   o.  The outside of the inner tube  314   i  may be provided with grooves  319  that define the ducts  313  when the inner tube  314   i  is positioned in the outer tube  314   o.    
       FIG. 4A  illustrates deployment of the PRT  300  and wireline module  200  to the subsea production tree  50 , according to another embodiment of the present invention.  FIG. 4B  illustrates connection of the wireline module  200  to the PCA  100 . To prepare for intervention (or abandonment), the wireline  290  may be fed through the tower  178  and inserted through the wireline module  200  and connected to the PRT  300 . The PRT  300  may then be connected to the tool catcher  240 . The wireline module  200  may then be deployed through the moonpool  177  using the wireline winch  176  and landed on the tool housing  125 . The ROV  180  may operate the adapter connector, thereby fastening the wireline module  200  to the PCA  100 . The ROV  180  may then connect jumper  266  to the control pod  160  and control relay  260  and connect fluid conduit  276  to the manifold  135  and the junction box  235 . The van operator may then engage one or both of the stuffing boxes with the wireline  290 . The van operator may then release the PRT  300  from the tool catcher  240  via the umbilical  165  and control relay  260 . 
       FIG. 4C  illustrates deployment of the PRT  300  to the upper crown plug  56   u.  The van operator may supply electrical power to the PLC via the wireline  290 . The van operator may then feed wireline  290  from the winch  176  toward the tree  50 , thereby lowering the PRT  300  to the upper crown plug  56   u.  The van operator may also instruct the PLC to retract the locking piston  365  and the PLC may respond by supplying hydraulic fluid to the passage  355   l,  thereby retracting the locking piston to the unlocked position. The PRT  300  may be lowered until the collet  360  engages the cam of the upper crown plug  56   u.  The engagement depth may be recorded by the PLC and/or control panel for later reference. Interaction of corresponding profiles may force the collet fingers  360  radially inward until the collet fingers are in alignment with the cam profile at which point stiffness of the collet fingers may snap the fingers into engagement with the profile. 
       FIG. 4D  illustrates the latch  350  engaged with the upper crown plug  56   u.  Simultaneously or shortly thereafter, the release piston  370  may contact the crown plug body, thereby activating the contact switch/sensor. The locking piston  365  may then be moved to the locked position by relief of hydraulic pressure, thereby allowing the spring  370   l  to extend the locking piston  365  to the locked position and preventing disengagement of the collet  360  from the upper crown plug  56   u.    
       FIG. 4E  illustrates preparation of the stroker  301  to remove the upper crown plug  56   u.  The van operator may then instruct extension of the stroker shaft  309 . The PLC may supply hydraulic fluid to the stroker piston  308  to extend the shaft  309 . Once the shaft  309  is extended, the van operator may instruct the PLC to set the anchor  310  and the PLC may supply hydraulic fluid to the anchor, thereby extending the anchor into engagement with the adapter  105 . Alternatively, the PRT  300  may be configured so that the anchor engages the tool housing  125 . 
       FIG. 4F  illustrates removal of the upper crown plug  56   u.  The van operator may then instruct retraction of the stroker shaft  309 . The PLC may supply hydraulic fluid to the stroker piston  308  to retract the shaft  309 . The stroker may exert force P necessary to disengage the upper crown plug  56   u  from the internal cap  54 . The stroker force P may be substantially greater than a force capacity of the wireline  290 , such as greater than or equal to ten, twenty, or thirty thousand pounds. As the shaft  309  retracts, the crown plug cam may be moved upward relative to the body until the cam engages a shoulder of the body, thereby creating a cavity for the dogs to retract. The cam may then pull on the body which may push the dogs into engagement with a profile of the internal tree cap  54 , thereby forcing the dogs radially inward into the cavity. The crown plug  56   u  may then be free from the cap  54 . 
     Additionally, the van operator may add slack to the wireline  290  before operation of the stroker  301  to remove the plug  56   u  so that the vessel  100  may be moved away from the tree  50  by a safe distance should a blowout occur in response to removing the plug. 
       FIG. 4G  illustrates washing the upper crown plug  56   u.  The PRT  300  and upper crown plug  56   u  may then be raised until the cablehead  303  reengages the tool catcher  240 . The van operator may then close the isolation valve  115 . The PRT  300  and upper crown plug  56   u  may then be washed by injecting a hydrates inhibitor  390  from the vessel  175 , through the fluid conduit  170 , the manifold, the conduit  266 , the junction plate  235 , and into the wireline module port  210   p.  The spent inhibitor may be returned to the vessel  175  through the port  110   p,  the manifold  135 , and the second fluid conduit (as discussed above, isolation valve  115  may allow downward flow when closed or the PCA  100  may include a bypass). 
     Additionally, the PRT  200  may include a flushing system (not shown) to remove debris from the crown plugs to prevent the debris from obstructing removal of the crown plugs. The respective crown plug may be flushed before engaging the latch therewith. The flushing system may include a nozzle connected to the housing  355  and in communication with the stroker pump  302 . The stroker  301  may include a cleaning fluid reservoir and discharge cleaning fluid through the nozzle, thereby impinging a fluid jet onto the crown plug  56   u.    
       FIG. 4H  illustrates retrieval of the wireline module  200 , PRT  300 , and upper crown plug  56   u.  Once washing is complete, the blind-shear preventer  120   b  may also be closed. The adapter connector may then be released by the ROV  180  and the wireline module  200  and upper crown plug  56   u  may be retrieved to the vessel  175 . The operation may then be repeated for the lower crown plug  56   l.    
       FIG. 5A  illustrates deployment of a modified PRT  300   t  to install a tree saver  395  in the tree  50 . The wireline module  200  and PRT  300   t  may then be deployed again with a tree saver  395 . The tree saver  395  may include a sleeve with a metal seal on its outer surface. The metal seal may be a depending lip that engages a tapered inner surface of the internal tree cap  54 . Alternatively, the tree saver metal seal may engage the tubing hanger  53  instead of the tree cap  54 . The sleeve may have a plurality of windows which allow fasteners, such as dogs, to extend and retract. The dogs may be pushed outward by an actuator, such as a central cam. The cam may have a profile on its upper end. The cam may move between a lower locked position and an upper position freeing dogs to retract. A retainer may secure to the upper end of body to retain the cam. The tree saver  395  may further include one or more seals. The seals may each be made from a polymer, such as an elastomer. The sleeve may have a length sufficient to extend past the production passage and the lower seal may engage an inner surface of the tubing hanger  53 , thereby isolating the production passage from any harmful fluids used during the intervention operation, such as cement or fracing fluid. Alternatively, the sleeve may extend into the production tubing  10   p  and the lower seal may engage an inner surface of the production tubing. The sleeve may also extend upward to the tree adapter  105  and the upper seal may engage an inner surface of the adapter sleeve  105   s.  Alternatively, the sleeve portion extending from the dogs to the tree connector and the upper seal may be omitted. 
       FIG. 5B  illustrates operation of the stroker  301  t to seat the tree saver  395  in the tree  50 .  FIG. 5C  illustrates release of the PRT  300   t  from the tree saver  395 .  FIG. 5D  illustrates the tree  50  ready for intervention. The PRT  300   t  may be released from the tool catcher  240  and lowered until the tree saver dogs are proximate to the upper crown plug profile in the internal cap  54 . The anchor  310  may then be extended into engagement with the tool housing  125 . The stroker  301   t  may then be extended to engage the tree saver lip with a shoulder of the internal tree cap  54 . The collet  360   t  may push the tree saver dogs into the internal cap profile. Once the shaft  309   t  has extended, the release piston  370  may be extended until contact with the tree saver body and the locking piston  365   t  may be moved to the unlocked position. The shaft  309   t  may then be retracted while pressure is maintained on the release piston  370 . The release piston  370  may continue to extend while the shaft  309   t  retracts, thereby holding the tree saver  395  downward against the cap profile and allowing the collets  360   t  to release from the locking sleeve. Retraction of the shaft  309  may be choked to ensure that the release piston  370  maintains contact with the tree saver body. The PRT  300   t  may then be raised until the cablehead  303  reengages the tool catcher  240 . The PRT  300   t  may be washed, as discussed above for the upper crown plug. The PRT  300   t  and the wireline module  200  may then be retrieved to the vessel. The tree  50  may now be ready for an intervention operation. 
     Alternatively, the anchor  310  may engage the adapter  105 . Alternatively, the retrieval piston  370  may be extended and used for a position sensor to determine when to operate the anchor  310 . Alternatively, the deployment depth may be determined using the removal depth of the upper crown plug  56   u.    
       FIG. 6  illustrates an intervention operation being conducted using a coiled tubing module  400  connected to the PCA  100 , according to another embodiment of the present invention. For a more detailed view of the coiled tubing module  400 , see FIG. 2C of U.S. patent application Ser. No. 13/018,871, filed Feb. 1, 2011 (Atty. Dock. No. WWCI/0011US), which is herein incorporated by reference in its entirety. Alternatively, the wireline module  200  may be used to conduct the intervention or abandonment operation. The coiled tubing module  400  may include an adapter, a fluid sub, an isolation valve, a stripper, a subsea coiled tubing injector, a frame, a control relay, an interface, such as a junction plate, and a tool catcher. The adapter, fluid sub, isolation valve, stripper, and tool catcher may each include a housing or body having a longitudinal bore therethrough and be connected, such as by flanges, such that a continuous bore is maintained therethrough. The adapter may be similar to the wireline adapter. The frame may be fastened to the adapter and the relay and the interface may be fastened to the frame. The fluid sub may include a housing having a bore therethrough and a port in communication with the bore. The port may be in fluid communication with the junction plate via a conduit (not shown). The tool catcher may be similar to the wireline tool catcher. 
     The isolation valve may include a housing, a valve member disposed in the housing bore and operable between an open position and a closed position, and an actuator operable to move the valve member between the positions. The actuator may be electric or hydraulic and may be in communication with the control relay via a conduit (not shown). The actuator may fail to the closed position in the event of an emergency. The isolation valve may be further operable to cut coiled tubing  490  when closed or the coiled tubing module  400  may further include a separate coiled tubing cutter. The isolation valve may further operate as a check valve in the closed position: allowing fluid flow downward from the stripper toward the PCA  100  and preventing reverse fluid flow therethrough. 
     The stripper may include a seal and a piston disposed in the housing. A hydraulic packoff port and a hydraulic release port may be formed through the housing in fluid communication with a respective face of the piston. Each port may be connected to the control relay via a respective hydraulic conduit. When operated by pressurized hydraulic fluid via the pack-off port, the piston may longitudinally compress the seal, thereby radially expanding the seal inward into engagement with the coiled tubing. The seal may be released by application of pressurized hydraulic fluid via the release port. Alternatively, an electric actuator may be used instead of the piston. Alternatively, the stripper may include a spring instead of the release port. 
     The injector may include a traction assembly to engage the coiled tubing  490  and drive the coiled tubing into or out of the wellbore  10 . The traction assembly may include opposing chain loops guided by bearing assemblies. Gripping members may be secured to individual links of the chain loops, so as to grip the coiled tubing. The gripping members and the chain loops may thus move together longitudinally at the area of contact with the coiled tubing  490  to move the coiled tubing into or out of the wellbore  10 . A plurality of rollers may be secured to the links of the chain loops, and roll along support members. The support members may be moved laterally inwardly to urge the gripping members into engagement with the coiled tubing  490  with sufficient force to grip the coiled tubing. The rollers may allow for a large lateral load to be applied without inducing a significant longitudinal drag load. 
     The bearing assemblies and an injector gear case may both be sealed to retain lubricant and prevent intrusion of seawater. The bearing assemblies may be outboard bearing assemblies because the portion of the housing adjacent the sealed gear case may be open to seawater to accommodate the chain loops. The chain loops may be routed over sprockets or gears within the housing, rotating about the axis of the bearings assemblies, and the chain loops may thus be guided by the bearing assemblies. A hydraulic or electric drive motor may drive the chain loops. The drive motor may be in hydraulic/electric communication with the control relay via a conduit/cable. The gear case may house a plurality of gears which may be driven by the drive motor and which may drive the chain loops via a drive shaft sealably extending from the sealed gear case. 
     The injector may further include a lubricant reservoir. The reservoir may compensate pressure within the gear case, each outboard bearing assembly, and other components of the injector that are sealed and sensitive to pressure differentials, such as the rollers. The reservoir may include a housing structurally separate from and attached to an outer housing of the gear case. The reservoir housing may be divided into a compensator chamber and a lubricant chamber by a pressure compensator, such as a piston or diaphragm. The lubricant chamber maybe filled with a lubricant. A conduit may be used to fluidly connect and pass lubricant between the reservoir and the gear case, the bearing assemblies, the rollers, and other sealed components. The compensator chamber may be in fluid communication with the sea by a port formed through the reservoir housing. As the hydrostatic pressure surrounding the reservoir increases, such as when the injector is lowered into a subsea environment, the compensator may pressurize the lubricant, thereby equalizing or substantially equalizing the lubricant pressure and the hydrostatic seafloor pressure. The compensator may be biased so that the lubricant pressure is slightly greater than the seafloor pressure. Accordingly, the pressure differential that would otherwise exist between the seawater environment and the interior of the sealed components is reduced or eliminated. 
     The vessel  400  may further include an additional CTU (second or third) including an injector head  425 , drum  420 , gooseneck, and HPU (not shown). The coiled tubing  490  may be inserted through the coiled tubing module  400  and connected to the BHA (not shown). The BHA may include one or more tools operable to perform an intervention or abandonment operation in the wellbore  10 . The BHA may then be connected to the tool catcher. The injector head  425  may be deployed over the moonpool  177  and the coiled tubing module  400  may be lowered to the tree  50  using the vessel injector  425  and the coiled tubing  490 . 
     Once the coiled tubing adapter has landed onto the PCA  100 , the ROV  180  may operate the adapter connector, thereby fastening the coiled tubing module  400  to the PCA  100 . The ROV  180  may then connect a jumper  466  to the control pod  160  and control relay and connect fluid conduit  476  to the manifold  135  and the junction box. Once fastened, the vessel injector  425  may feed the coiled tubing  490  toward the tree  50 , thereby creating slack in the coiled tubing  490 . The vessel  175  may then (or simultaneously) be moved a distance from the tree  50  ensuring safety of the vessel  400  should a blowout occur during the intervention operation. The slack may also serve to compensate for heave of the vessel. 
     The stripper may be engaged with the coiled tubing  490  by the van operator and then the isolation valve  115 , blind-shear BOP  120   b,  and SSV may be opened. The van operator may then release the BHA from the tool catcher via the umbilical  350  and control relay. The subsea drive motor may then be operated by the van operator, thereby advancing the BHA toward the tree  50 . The slack may be maintained through synchronization of the vessel injector  425  with the subsea injector by communication with the surface controller. The coiled tubing  490  may continue be advanced (while maintaining the slack via synchronous operation of the vessel injector  425 ) into the wellbore  10  by the subsea injector until the BHA reaches a desired depth in the wellbore. The intervention or abandonment operation may then be conducted using the coiled tubing  490  and the BHA. To facilitate the intervention or abandonment operation, fluid may be pumped through the coiled tubing  490  and the BHA and returned to the vessel  175  via the port  110   p.  Further, fluid may be pumped into the wellbore  10  before or after deployment of the BHA through the port  110   p  with the isolation valve  115  closed, thereby protecting the BOP stack  120  from the fluid. 
     Once the intervention or abandonment operation has concluded, the BHA and coiled tubing  490  may be retrieved from the wellbore  10  by reversing the deployment and landing procedure, discussed above. The isolation valve  115  and SSV may then be closed by the vessel operator. The BHA may then be washed as discussed above for the upper crown plug  56   u.  The blind-shear preventer  120   b  may then be closed. The vessel  175  may return to the position over the tree  50 . The slack may be removed from the coiled tubing  490  by the vessel injector (after or simultaneously with vessel movement). The ROV  180  may disconnect the adapter connector and the coiled tubing module  400  may be retrieved from the tree  50 . If an intervention operation was conducted, the tree saver  395  may be removed and the crown plugs  56   u,l  reinstalled using the wireline module  200  and PRT  300 / 300   t.  Reinstallation of the crown plugs  56   u,l  may be similar to installation of the tree saver  395 , discussed above, and removal of the tree saver may be similar to removal of the crown plugs. Additionally, a vent (not shown) in communication with a portion of the bore between the crown plugs  56   u,l  may be opened to prevent fluid lock between the crown plugs. The PCA  100  may then be retrieved and the well returned to production. 
       FIG. 7A  illustrates a PRT  500  having a vibratory jar  501 , according to another embodiment of the present invention. The PRT  500  may include the cablehead  303 , one or more electric pumps  302 ,  502  the stroker  301 / 301   t,  a vibratory jar  501 , the anchor  310 , the latch  350 / 350   t,  a control head  503 , and a reservoir  575 . The vibratory jar  501  may include a housing  505  and a knocker  509 . The cable head  303  may control operation of the stroker  301 / 301   t  and the anchor  310  and the control head  503  may include an electronics package (not shown) for controlling operation of the vibratory jar  501  and the latch  350 / 350   t.  The control head  503  may be in electrical communication with the wireline  290  via a flexible cable  580 . The electronics package may include a programmable logic controller (PLC) having a transceiver in communication with the wireline  290  for transmitting and receiving data signals to the vessel  100 . The electronics package may also include a power supply in communication with the PLC and the wireline  290  for powering the electric pump  502 , the PLC, and various control valves. The electric pump  502  may include an electric motor, a hydraulic pump, and a manifold. The manifold may be in fluid communication with the jar housing  505  via an internal bore, latch  350 / 350   t,  via flexible conduit  582 , and the reservoir  575 , via flexible conduit  581 , and include one or more control valves for controlling the fluid communication between the manifold and the components. Each control valve actuator may be in communication with the PLC. 
     The cable and control head PLCs may each be connected to the wireline  290  in a parallel arrangement and each of the cable head PLC and the control head PLC may have a unique address so that the vessel  175  may send selectively send commands to each one. Alternatively, the control head PLC may instead be connected to the cable head PLC (series arrangement) and the control head PLC may relay instructions to the control head PLC and the cable head power supply may provide electricity to the control head power supply. Alternatively, the control head  503  and pump  502  may be omitted and the jar  501  and latch  350 / 350   t  may be operated by a flexible conduits or hydraulic swivels in communication with the stroker pump manifold. 
       FIGS. 7B-7D  illustrate operation of the vibratory jar  501  in upstroke mode. The housing  505  may be connected to the pump  502 , such as with threaded connection  517  and the knocker  509  may be connected to the reservoir  575 , such as with threaded connection  547 . The jar  501  may be operated after the latch has engaged one of the crown plugs  56   u,l  and/or the tree saver  395  and as the stroker shaft  309 / 309   t  is retracted to facilitate removal thereof especially if the crown plug/tree saver is stuck due to obstruction by debris and/or corrosion. Retraction of the stroker shaft  309 / 309   t  may cause the jar  501  to be in tension with knocker  509  in an extended position with respect to housing  505  with the tension force being transmitted to knocker  509  via pins  535 . 
     Referring specifically to  FIG. 7B , to operate the jar  501 , hydraulic fluid may be injected into housing conduit  521  using the pump  502 . Fluid pressure within the upper portion of housing  505  may act on dart  550  and piston  561  of mandrel  557  to urge dart  550  and mandrel  557  longitudinally downward to space apart upwardly facing shoulder  526  of hammer  525  from downwardly facing shoulder  553  of knocker  509 , thereby closing valve  560 . When valve  560  is closed, the pressure within flow passage  559  of mandrel  557  may be less than the pressure within the upper portion of housing  505 . Thus, dart  550  may be urged continually into sealing contact with mandrel  557  and may move therewith as a unit. The downward movement of dart  550  and mandrel  557  may compress both dart spring  507  and main spring  513 . 
     Referring specifically to  FIG. 7C , the downward movement of dart  550  and mandrel  557  may continue until shoulder  551  of dart  550  contacts shoulder  515  of housing  505 , thereby halting downward movement of dart  550 . Fluid pressure applied to the upper surface of piston  561  may continue to urge mandrel  557  downwardly, thereby breaking the seal between ball closure member  563  and seat  565 . When the seal between ball  563  and seat  565  is broken, the differential pressure across dart  550  may be effectively removed and dart  550  may be free to be moved longitudinally upward by dart spring  507 . Additionally, mandrel  557  may be free to be moved longitudinally upward by main spring  513 . 
     Referring specifically to  FIG. 7D , the dart  550  may be moved longitudinally upward until valve member  517  engages seat  519  of conduit  521 , thereby momentarily interrupting the flow of fluid through the jar  501 . Mandrel  557  may also be moved sharply upward by main spring  513  such that hammer  525  forcefully impacts (aka jars)  570  internal anvil  553  of knocker  509 , thereby also jarring the connected latch  350 / 350   t  and crown plug/tree saver. Should the blow  570  move the crown plug/tree saver and latch upwardly, knocker  509  may be free to move upwardly with respect to housing  505  by the sliding action of pins  535  within slots  537 . 
     After the impact  570  of hammer  525  upon internal anvil  553  of knocker  509 , the jar  501  may return to the position depicted in  FIG. 7B  and repeat the operating cycle. At typical pressures and flow rates, the jar  501  may operate at one or more cycles per second, thereby creating an upward jarring vibration. The upwardly jarring vibration may continue as long as the jar  501  is in tension and fluid flow is maintained. Fluid flow through passage  559  may continue into reservoir  575  where the fluid may be recycled. A frequency of the jar  501  may be varied by varying a speed of the pump  502 . The PRT  500  may further include a contact switch or sensor for detecting when the crown plug/tree saver has been freed in communication with the control head PLC. The PLC may halt circulation to the jar  501  in response to detecting freedom of the crown plug/tree saver. 
     Additionally, the jar  501  may be operated in a downstroke mode (not shown) to facilitate reinstallation of the crown plugs/tree saver. The jar  501  may be operated as the stroker shaft is being extended to reinstall a respective crown plug/tree saver. Discussion and illustration of the downstroke mode may be found in U.S. Pat. No. 4,462,471, which is herein incorporated by reference in its entirety. 
     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.