Abstract:
A method of capturing flow discharged from a subsea blowout or oil seep includes lowering a collector from a mobile offshore drilling unit (MODU) onto a seafloor at a location distant from subsea equipment blowing production fluid. A workstring is connected to the collector and an inert gas is injected through the workstring. The collector is landed onto the subsea equipment while maintaining the injection of inert gas. The inert gas injection is halted and a top of the workstring is routed to surface collection equipment, thereby directing the blowing production fluid from the subsea equipment, into the collector, and through the workstring to the MODU.

Description:
BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     Embodiments of the present invention generally relate to a collector for capturing flow discharged from a subsea blowout. 
     2. Description of the Related Art 
     Bringing an underwater well blowout under control is difficult since it is usually accompanied by hydrocarbons and/or fire at the surface and damage to the subsea equipment connector. This uncontrolled flow of crude oil and/or natural gas is not only a waste of energy but also can be a source of water and beach pollution. Control of the well flow from a blowout and collection of oil spills therefrom have been handled separately. Control of well flow is attempted by drilling separate wells to feed heavy mud into the flowing well to kill the flow. 
     SUMMARY OF THE INVENTION 
     Embodiments of the present invention generally relate to a collector for capturing flow discharged from a subsea blowout. In one embodiment, a collector for capturing flow discharged from a subsea blowout includes a tubular housing having a containment chamber; a seal connected to the housing; a tubular chimney connected to the housing, having a portion of a subsea connector, and having a diameter less than a diameter of the containment chamber; and a head connected to the housing and the chimney. 
     In another embodiment, a method for capturing flow discharged from a subsea blowout includes: lowering a collector from a mobile offshore drilling unit (MODU) onto a seafloor at a location distant from subsea equipment blowing production fluid; connecting a workstring to the collector; injecting an inert gas through the workstring; moving the MODU and connected collector to the subsea equipment and landing the collector onto the equipment while maintaining injection of the inert gas; halting injection of the inert gas; and routing a top of the workstring to surface collection equipment, thereby directing the blowing production fluid from the subsea equipment into a chimney of the collector, wherein the chimney is connected to the MODU by the workstring. 
     In another embodiment, a method for collecting seepage from a seafloor includes: lowering a collector from a mobile offshore drilling unit (MODU) onto the seafloor at a location distant from the seepage; connecting a workstring to the collector; injecting an inert gas through the workstring; moving the MODU and connected collector to the seepage and landing the collector into the seafloor around the seepage while maintaining injection of the inert gas; halting injection of the inert gas; and collecting the seepage from the seafloor to the MODU via the collector and workstring. 
    
    
     
       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. 1  illustrates lowering a collector to a subsea wellhead having a blowout, according to one embodiment of the present invention.  FIGS. 1A and 1B  illustrate landing and operation of a face seal collector.  FIGS. 1C and 1D  illustrate landing and operation of an overshot collector. 
         FIGS. 2A and 2B  illustrate a side-entry collector for receiving a tubular laying on or near the seafloor, according to another embodiment of the present invention. 
         FIGS. 3A and 3B  illustrate a siphon seal overshot collector, according to another embodiment of the present invention. 
         FIG. 4  illustrates an overshot collector having a drill string receiver, according to another embodiment of the present invention. 
         FIGS. 5A-5C  illustrate a face seal collector for a subsea connector, according to another embodiment of the present invention. 
         FIGS. 6A-6C  illustrate an overshot collector for a subsea flange, according to another embodiment of the present invention. 
     
    
    
     DETAILED DESCRIPTION 
       FIG. 1  illustrates lowering a collector  100  to a subsea wellhead  5  having a blowout  50  ( FIG. 1A ), according to one embodiment of the present invention. As shown, the well is a subsea well, such as having a wellhead  5  located below the water  1 . The blowout preventer (BOP)  10   b  has malfunctioned and failed to contain the blowout  50 . The mobile offshore drilling unit (MODU) (not shown) may have burned and sunk to the seafloor. The drilling riser  15   r  may still be attached to the lower marine riser package (LMRP)  10   u  (riser already cut as shown). A drillstring  15   d  or workstring may reside within the riser  15   r,  depending on the operation that caused the blowout  50 . Alternatively, the collector  100  may be deployed to control a subsea hydrocarbon release from any other type of subsea equipment, such as a production (aka Christmas) tree. 
     To prepare the well for installation of the collector  100 , the riser  15   r,  drill string  15   d,  and/or workstring may be cut and cleared from the wellhead  5  using one or more remotely operated vehicles (ROVs)  20   a,b . A MODU, such as a drillship  25  or semi-submersible, may be deployed a safe distance from the blowing well. The collector  100  may be lowered to the seafloor  1   f  by a winch or crane of the MODU  25  or by a workstring  30 , such as drill pipe, flexible pipe, or coiled tubing. If the winch or crane was used for deployment, the workstring  30  may then be assembled and connected to the collector  100 . The collector  100  may be fastened to the workstring  30 , such as by a quick latch  212  ( FIG. 2A , only profile shown) or subsea hydraulic connector. The quick latch may be a J-latch  212  and may be operated from the MODU  25  by manipulation of the workstring  30 . The collector  100  may have the female portion  212  of the J-latch and the workstring  30  may have the male portion (not shown) or vice versa. The workstring  30  may have an adapter  35  connected to a bottom thereof. The adapter  35  may include a tubular body having a threaded end for connection to the workstring  30 , such as a pin or box, a seal disposed around an outer surface of the tubular body for engaging a seal bore of the collector, a guide nose, and one or more lugs connected to the body, such as with fasteners, and extending from an outer surface of the body. The lugs may engage respective J-slots  212  formed in an outer surface of a chimney  110  ( FIG. 3A ) of the collector, thereby forming the J-latch connection. 
     Alternatively, the collector  100  may be connected to the workstring  30  by a threaded or flanged connection. Alternatively, the collector  100  may be connected to the workstring  30  on the MODU  25  before deployment into the sea  1 . Alternatively, the workstring  30  may be insulated to discourage gas hydrates formation. Alternatively, a light intervention vessel may be deployed and the collector may be connected to the vessel by coiled tubing. Additionally, the workstring  30  may include a heave compensator, such as a telescopic joint, to isolate the collector from heave or vertical displacement of the MODU. Alternatively, the workstring  30  may also be connected to the surface vessel or MODU with a conventional heave compensator or draw works. 
       FIGS. 1A and 1B  illustrate landing and operation of a face seal collector  100   f.  Depending on the damage to the subsea equipment  10   u,b ,  15   r,d  caused by the blowout  50 , the riser  15   r  may be clean cut  15   w  near a top of the LMRP  10   u,  such as near the riser adapter connector  40 . If the cut  15   w  is clean, i.e. made with a diamond wire saw, the face seal collector  100  may be employed. The face seal collector  100   f  may include a lower landing guide  120 , a frame  115 , a housing  105 , a seal, such as a grommet  130 , a head  107 , and the chimney  110 . Except for the seal  130 , each of the collector members may be connected to one or more of the other members, such as by fastening or welding. Except for the seal  130  and where otherwise specified, the collector members may each be made from a metal or alloy, such as steel, stainless steel, or nickel based alloy. The grommet  130  may be made from a polymer, such as an elastomer, and may be bonded to the housing  105 . A lower surface of the grommet  130  may have a sealing surface that is flat, conical, convex, or concave relative to the cut face, or other surface on which it lands. 
     The lower landing guide  120  may surround the riser adapter  40  and provide lateral support to the collector  100 . The lower guide  120  may be annular or conical having a diameter or minor diameter corresponding to a diameter of the riser adapter  40  and have the frame  115  extending along an outer surface and connected thereto. The grommet  130  may engage the riser cut face  15   w  and a weight of the collector  100   f  may be set on the grommet  130 , thereby compressing the grommet and providing sealing pressure. The grommet  130  may provide a low pressure seal, such as less than or equal to fifty psig, so that a positive pressure differential (relative to pressure of the sea) may be maintained in a containment chamber formed by the housing  105 . The positive pressure may prevent or mitigate entry of seawater into the containment chamber, thereby preventing or controlling gas hydrate formation in the containment chamber. For stabilization and/or workstring support, the collector weight may be substantial, such as greater than or equal to four, five, eight, or ten tons. The weight may be provided by the natural weight of the collector members or weights (not shown) may be added below the grommet, such as at the lower landing guide, to prevent tipping. The workstring  30  may be supported by the MODU  25  in a neutral position with or without heave compensation to prevent buckling of the workstring. 
     The housing  105  may be tubular and may have a diameter corresponding to the cut face diameter or the housing diameter may be greater than the cut face diameter. The housing  105  may form the containment chamber and may be connected to the head  107  and have the frame  115  extending along an outer surface thereof and connected thereto. The head  107  may be conical to serve as a reducer from the housing diameter to a diameter of the chimney  110 . The frame  115  may also extend along and connect to an outer surface of the head  107 . The head  107  may have one or more ports formed through a wall thereof and in fluid communication with the containment chamber, such as one or more injection ports  135  and one or more vent ports  145 . Alternatively, one or more of the ports may be formed through the housing. The vent ports  145  may be equipped with a subsea connector to allow connection of additional collection conduits, such as hose, drill pipe, or coiled tubing, should it be necessary or desirable to collect and produce additional production fluids. They may also be used to inject gas for gas lift boosting of the produced fluids if necessary. An injection line  140  may connect to each injection port  135  and extend to the MODU  25  or support vessel (not shown). The injection line  140  may be coiled tubing. A first portion of a coupling may be connected to an end of the injection line  140  and a second portion of a coupling may be connected to an inlet of the injection port  135 . The coupling may be operable by the ROV, such as a hot stab, to sealingly connect the injection line  140  with the injection port  135 . A hydrates inhibitor, such as methanol, ethylene glycol, or propylene glycol, may be injected into the injection ports  135  to prevent or control hydrates formation. 
     A shutoff valve  347  ( FIG. 3A ) may be connected to each vent (or collection) port  145 . Each shutoff valve  347  may have an actuator operable by an ROV  20   a,b . The vents  145  may provide fluid communication between the containment chamber and the sea (when the shutoff valves are open). The vents  145  may be opened to facilitate landing of the collector  100   f  on the wellhead  5 , if the flow may prevent landing, and then gradually closed as the collector becomes operational. The chimney  110  may be tubular (or other shape), connected to the head  107 , and have an upper end of the frame  115  connected thereto. The chimney  110  may have a diameter corresponding to the workstring  30  and structurally and sealingly connect to the workstring, as discussed above. The chimney diameter may be less than or substantially less than the housing diameter. 
     Once the collector  100   f  is lowered to the required depth on the workstring  30 , aninert gas, such as nitrogen, may be injected through the workstring to displace seawater for prevention of hydrate formation. The injection lines  140  may be connected to the injection ports  135  using the ROV  20   a,b . Hydrates inhibitor may then be injected into the containment chamber through the injection lines  140 . The MODU  25  may then move to the blowing well while continuously injecting the nitrogen and inhibitor. Once near the blowing well, the ROV  20   a,b  may be used to guide the collector  100   f  over the leaking source, such as the cut riser end  15   w.  The collector  100   f  may include one or more ROV handles  125  to facilitate placement and guidance of the collector, since the leaking source may create a plume that obstructs visualization of the collector during placement by ROVs  20   a,b . An extended ROV handle may allow a better indication of position during placement under such conditions. Once the collector  100   f  is seated, the spewing production fluid may flow through the open vents  145  and/or through the grommet seal cut pipe interface into the sea  1 . The nitrogen injection may be halted and an upper end of the workstring  30  may be placed in fluid communication with one or more production facilities, thereby allowing the production fluid to flow through the workstring  30  to the MODU  25 . The flow may be facilitated by the density difference between the lighter production fluid and the heavier seawater  1 . The ROV  20   a,b  may begin closing the vent valves  347  (if open) of the collector  100   f.  Injection of the hydrates inhibitor may or may not continue after steady state flow is achieved. 
     If capacity of the production facilities connected to the collector are greater than or equal to the production (blowout) rate of the wellbore, once steady state flow is achieved, all of the vents  145  not connected to collecting units may be closed and the production choke controlled to maintain the positive pressure differential in the containment chamber, such as greater than or equal to one psig. Alternatively, the chamber pressure differential may be less than one psig, such as zero or slightly negative. The chamber pressure differential may depend on seal quality with the leak source (i.e., greater differential for poorer quality to prevent seawater entry and hydrates formation). The production choke may be located at surface or subsea. If subsea, the production choke may be part of the collector  100   f  (i.e., in the chimney  110 ) or part of the workstring  30  (i.e., part of the workstring adapter  35 ). Production fluid may flow to the MODU  25  through the workstring  30  and to the production facilities where the production fluid may be separated into crude oil, natural gas, and (produced) water and may flow to additional surface or subsea collecting units. The crude oil may be stored onboard the MODU  25  or transferred to a tanker or supertanker (not shown). The gas may be flared. The water may be stored for later treatment or treated and pumped into the sea. 
     If collection capacity is less than the production rate of the leak, then one or more vents  145  may remain open to vent the excess production fluid into the sea  1 . Alternatively, the vents  145  may be closed and the excess production fluid may leak through the interface between the grommet  130  and the leak source  15   w.  As the leak is collected, the ROV  20   a,b  may visually monitor the collector  100   f  for leakage from the grommet  130 . If substantial leakage is observed, the production choke may be adjusted to reduce backpressure on the collector  100   f  to reduce or eliminate the leakage. Minimal leakage may be allowed to ensure positive pressure in the containment chamber, thereby ensuring against seawater entry and hydrates formation. 
     Additionally, the workstring  30  may be deployed through a riser (not shown) connected to the MODU  25  and a heated fluid, such as sea water, may be pumped through the riser-workstring annulus to discourage formation of hydrates in the production fluid flowing through the workstring. Pumping of the heated seawater may commence when the workstring  30  is connected to the collector  100   f  and continue during steady state production. 
     Alternatively, the collector  100   f  may be lowered from the MODU  25  using the workstring  30 . The collector  100   f  may be connected to the workstring  30  and lowered to the wellhead  5  as the workstring  30  is assembled. Alternatively, a second, different type of collector may be lowered to the seafloor and if the collector is unable to seat on the wellhead, the first collector may be released to the seafloor and the second collector may be connected to the workstring for a second attempt without disassembling the workstring  30 . 
       FIGS. 1C and 1D  illustrate landing and operation of an overshot collector  100   o.  The overshot collector  100   o  may be similar to the face seal collector  100   f , discussed above, so only additions and/or differences will be discussed. The housing  155  may be extended and the housing and the head  157  may serve the purpose of the frame and landing guide. The housing  155  may have a landing shoulder (not shown) formed therein for receiving the riser adapter  40  and supporting the weight of the collector therefrom. Instead of the grommet, the housing may have an overshot seal (not shown) or lip seal  630  ( FIG. 6B ) for engaging an outer surface of the cut riser instead of the cut face  15   s,  thereby eliminating the importance of the cut quality, such as from a hydraulic shear cut. Alternatively, the overshot collector  100   o  may be employed to control leaks on other damaged subsea equipment or seafloor seepage. 
       FIGS. 2A and 2B  illustrate a side-entry collector  200  for receiving a tubular laying on or near the seafloor, according to another embodiment of the present invention. The tubular may be rigid pipe or flexible tubing, such as a riser, drill pipe, heavy drill pipe, drill collar, production pipeline or umbilical. The side-entry collector  200  may be similar to the overshot collector  100   o,  discussed above, so only additions and/or differences will be discussed. In some instances, it may not be desirable to cut the tubular or the side-entry collector  200  may be deployed as a stopgap until the tubular is cut. The side-entry collector  200  may be deployed over an end of the tubular lying on or near the seafloor. 
     Instead of an overshot seal, the side-entry collector may include a doorway  210  formed through a wall of the housing  255 , an upper seal  215   u  lining the doorway and extending around an inner surface of the housing proximate the doorway, and a lower seal  215   b  extending inward from an inner surface of the housing. The doorway  210  may have a semi-oval shape for receiving the end of the tubular. A size of the doorway  210  may correspond to a diameter of the tubular. The upper seal  215   u  may be bonded or fastened to the housing  255  and a doorway portion of the upper seal may engage an upper portion of the tubular outer surface as the doorway  210  is lowered over the tubular end. The lower seal  215   b  may engage a lower portion of the tubular outer surface as the doorway  210  is lowered over the tubular end. The upper and lower seals  215   u,b  may be separate seals or integral portions of the same seal. As with the grommet and overshot seals, the upper  215   u  and lower  215   b  seals may form a low pressure barrier between the containment chamber and the sea when the collector  200  is engaged with the tubular end. Engagement of the bottom of the housing  255  with the seafloor if may also serve as part of the barrier. Alternatively, the upper seal  215   u  may extend from a bottom of the housing  255  to engage the seafloor  1   f.  Additionally, sealant (not shown), such as mud, gravel, or sand bags, may be dumped on and/or around the side-entry collector  200  to enhance the sealing. 
     The side-entry collector  200  may further include legs  220   a,b  extending through respective lugs  225  formed in or connected to an outer surface of the housing. The legs  220   a,b  may be fastened to the lugs by ROV operable fasteners. One of the legs  220   a  may be longer or substantially longer than the other leg  220   b.  The side-entry collector  200  may be deployed until the doorway  210  is proximate to the leak source but clear from the spewing plume of production fluid. The ROV  20   a,b  may disengage the longer leg fastener, thereby extending the longer leg  220   a  into the seafloor  1   f.  Once the longer leg  220   a  is set, the collector  200  may then be rotated about the set leg  220   a  and lowered onto the leak source. The shorter leg  220   b  may then be set. Engagement of the legs  220   a,b  with the seafloor if may serve to laterally stabilize the collector  200  and facilitate precise positioning of the collector relative to the leak source. The vents and shutoff valves may be omitted from the side-entry collector. Alternatively, the side-entry collector may include the vents (or collection ports) and shutoff valves. 
     Alternatively, the overshot collector  100   o  may be deployed horizontally over the tubular end instead of using the side-entry collector  200 . Alternatively, the doorway  210  may be omitted and the modified collector employed to control seafloor seepage due to casing failure by penetrating the seafloor if and sealing around the leak source. 
       FIGS. 3A and 3B  illustrate a siphon or plumber seal overshot collector  300 , according to another embodiment of the present invention. The siphon seal may be upside down and may take advantage of the density difference between the production fluid  50  and seawater  1 . The siphon seal collector  300  may be similar to the overshot collector  1000 , discussed above, so only additions and/or differences will be discussed. The overshot seal may be omitted from the siphon seal collector  300 . The siphon seal collector  300  may include a landing frame for engaging the subsea connector, i.e., the riser adapter  40 , and longitudinally supporting the collector  300  therefrom. The landing frame may include two or more landers  305 . Each lander  305  may have a stab portion  306  and a landing shoulder  307 . The landers  305  may be reinforced by a support ring  315 . An inner diameter of the housing  155  may correspond to an outer diameter of the cut riser  15   s  to form an additional controlled gap seal therebetween to minimize leakage from the containment chamber to the sea  1 . The elastomeric lip seal  630  may be added to provide additional sealing and configured to act like a pressure release valve to prevent lifting of the collector. As discussed above, maintenance of the positive pressure differential ensures that the collected fluid is production fluid from the containment chamber and not sea water  1  into the containment chamber. 
       FIG. 4  illustrates an overshot collector  400  having a drill string receiver  410 , according to another embodiment of the present invention. The overshot receiver collector  400  may be similar to the overshot collector  100   o , discussed above, so only the additions and/or differences will be discussed. In some instances, instead of cutting the riser  15   r,  it may be possible to remove the LMRP  10   u.  Removing the LMRP  10   u  may expose a connector profile in the top of the BOP stack  10   b.  Removing the LMRP  10   u  may also leave a section of the drill string  15   d  extending from the BOP stack  10   b  or the drill string may be cut or unthreaded leaving a portion extending from the BOP stack. 
     The overshot receiver collector  400  may include the drill string receiver  410  disposed between the chimney  110  and the housing  455  for accommodating the extending drill string portion. The overshot receiver collector  400  may further include a frame  115  extending from the landing shoulder  407 , along an outer surface of the housing  455 , and to the receiver  410  and connected thereto for structural reinforcement. The landing shoulder  407  may be a conical lower portion of the housing  455 . The overshot receiver collector  400  may further include one or more landing pads  506  ( FIG. 5C ) lining an inner surface of the landing shoulder  407  to protect the connector profile from damage. The pads  506  may be made from a polymer, such as a thermoplastic or coploymer, such as polyoxymethylene (POM). Each pad  506  may be connected to the shoulder  407  by one or more fasteners. Heads of the fasteners may be received in respective recesses formed in an inner surface of the pads  506  to prevent the fastener heads from damaging the connector profile. 
     The overshot receiver collector  400  may further include a control panel  450 . The control panel  450  may include one or more dispersant injection ports, a shutoff valve connected to each port for opening and closing the ports, and an ROV operable actuator for opening and closing the shutoff valves. The shutoff valve actuator may be operable by an ROV. A single actuator may control both valves or the panel may include first and second actuators for respective valves. Alternatively, a three-way valve may replace the shutoff valves  347  or a single port may be used with a diverter valve. A dispersant injection line extending from the MODU  25  may be connected to each port using an ROV operable connector, similar to the injection port connector discussed above. A manifold may lead from one of the dispersant injection ports and conduits may be connected to the manifold. Each conduit may be in communication with a respective vent  145 , such as downstream of the vent shutoff valves  347 . Alternatively, each conduit may connect to the respective vent  145  upstream of the vent shutoff valve  347 . The other dispersant injection port may be connected by a conduit to a sprayer, such as a ring  405 , connected to the frame. The dispersant ring  405  may have outlets, such as orifices or nozzles, spaced therearound for discharging the dispersant toward the landing shoulder  407 . 
     In operation, during startup, the dispersant may be injected into the vents  145  at a flow rate based on the flow rate of production fluid venting into the sea  1 . Once steady state operation is achieved, the dispersant may be injected into the dispersant ring  405  based on the amount of leakage occurring through the seal (if any). 
     A check valve, such as a flapper valve  447 , may be connected to an outlet of each vent  145  to allow flow of production fluid therethrough and prevent reverse flow of seawater  1 . Similar to the overshot collector  100   o , the receiver collector  400  may include one or more injection ports  135  in communication with the containment chamber. An injection line  140  may connect each injection port  135  to the MODU  25 . Alternatively, each injection port may connect to a port formed in the control panel  450 . 
       FIGS. 5A-5C  illustrate a face seal collector  500  for a subsea connector, according to another embodiment of the present invention. The subsea connector face seal collector  500  may be similar to the face seal collector  100   f,  discussed above, so only the additions and/or differences will be discussed. In some instances, instead of cutting the riser  15   r,  it may be possible to remove the riser adapter  40  from the LMRP  10   u  using an emergency riser disconnect (EMRD) of the LMRP. Removing the riser adapter may expose a profile  45  of the EMRD and a seal face suitable for the grommet  130 . Alternatively, the subsea connector face seal collector  500  may be configured to land on the LMRP connector profile, the wellhead connector profile, a connector profile of the BOP stack or any other connector profile of the LMRP or BOP stack be it quick connect or flanged. 
     The landing guide  520  of the subsea connector face seal collector may include a conical portion and a tubular portion. The conical portion may facilitate landing on the EMRD profile  45  and include one or more landing pads  506 , similar to the landing pads of the drill string receiver overshot collector discussed above, for protecting the connector profile. One or more guide pads  507  may be connected to the tubular portion, such as with fasteners, to engage an outer surface of the EMRP profile  45 , thereby providing lateral stabilization. The subsea connector face seal collector  500  may further include a support ring  505  aligned with the landing guide  520  and having a diameter corresponding to a major diameter of the conical portion. An annulus may be defined between the support ring  505  and the landing guide  520 . The frame  115  may extend into the annulus and be connected to the landing guide  520  and the support ring  505 . One or more weights  540  made from a heavy material, such as lead, may be disposed in the annulus for workstring support and/or stabilization by lowering the center of gravity (in some cases below the grommet  130 ), as discussed above. 
     The subsea connector face seal collector  500  may further include additional features similar to the drill string receiver overshot collector  400 , such as the control panel  450 , the vent check valves  447 , and the dispersant ring  405 . Alternatively, the subsea connector face seal collector  500  may include the siphon seal and/or the lip seal  630 , discussed above, in addition to the grommet  130  by closing the annulus formed between the grommet  130  and the frame  115  (dispersant ring  405  may be moved or omitted). 
       FIGS. 6A-6C  illustrate an overshot collector  600  for a subsea flange, according to another embodiment of the present invention. The overshot flange collector  600  may be similar to the overshot receiver collector  400 , discussed above, so only the additions and/or differences will be discussed. In some instances, instead of cutting the riser  15   r,  it may be possible to remove a portion of a flanged joint of the LMRP  10   u  or BOP stack  10   b  using the ROV  20   a,b . Alternatively, the overshot flange collector  600  may be configured to engage a flange joint of a subsea production tree. 
     Relative to the overshot receiver collector  400 , the drill string receiver may be omitted and the housing  455  may have an inner diameter corresponding to an outer diameter of the flange joint. The lip seal  630  may have a diameter corresponding to the flange joint diameter for engaging the flange joint. The overshot flange collector  600  may further include additional features similar to the subsea connector face seal collector, such as the support ring  505  and weights. 
     Alternatively, the vents and vent shutoff valves may be omitted from any of the collectors, discussed above. Additionally, a pump may be added to the workstring or any of the collectors to facilitate collection of the production fluid. The pump may be an electrical submersible pump (ESP). 
     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.