Abstract:
A method for sealing a well includes: placing an obstruction in a bore of an inner tubular string; forming an opening through a wall of the inner tubular string above the obstruction; mixing a resin and a hardener to form a sealant having a density greater than a density of fluid present in the bore and present in an annulus formed between the inner tubular string and an outer tubular string; and injecting the sealant into the annulus. The sealant falls down the annulus to the opening. A portion of the sealant is diverted through the opening and into the bore. The sealant cures to form a balanced plug in the annulus and the bore.

Description:
BACKGROUND OF THE DISCLOSURE 
       [0001]    Field of the Disclosure 
         [0002]    The present disclosure generally relates to a method of sealing an annulus and/or pipe of a well by injection of sealant. 
         [0003]    Description of the Related Art 
         [0004]      FIG. 1  illustrates a prior art platform well. A drive pipe  2  may be set from above a surface (aka waterline)  3  of the sea  4 , through the sea, and into the seafloor (aka mudline)  5 . The drive pipe  2  allows the wellhead (not shown) to be located on a platform  6  above the waterline  3 . 
         [0005]    Once the drive pipe  2  has been set and (may or may not be) cemented  7 , a subsea wellbore  8  may be drilled into the seafloor  5 . A string of casing, known as surface casing  10 , may then be run-in and cemented  11  into place. As the wellbore  8  approaches a hydrocarbon-bearing formation  12 , i.e., crude oil and/or natural gas, another string of casing, known as production casing  13 , may be run-into the wellbore  8  and cemented  14  into place. Thereafter, the production casing string  13  may be perforated  15  to permit the fluid hydrocarbons  16  to flow into the interior of the casing. The hydrocarbons  16  may be transported from the production zone of the wellbore  8  through a production tubing string  17  run into the wellbore  8 . An annulus  18  defined between the production casing string  13  and the production tubing string  17  may be isolated from the producing formation  12  with a packer  19 . 
         [0006]      FIG. 2  illustrates the platform  6  and completion  1  damaged by a hurricane. Hurricanes in the Gulf of Mexico have damaged or destroyed several platforms  6  along with the completions  1 . The platforms  6  and the completions  1  may have sunk to the seafloor  5 . Many of the wells had been in production for many years, thereby depleting the formations  12  such that the platform operators desire to plug and abandon the wells. The damage to the platform  6  and completion  1  makes traditional abandonment operations unfeasible. 
       SUMMARY OF THE DISCLOSURE 
       [0007]    The present disclosure generally relates to a method of sealing an annulus and/or pipe of a well by injection of sealant. In one embodiment, a method for sealing a well includes: placing an obstruction in a bore of an inner tubular string; forming an opening through a wall of the inner tubular string above the obstruction; mixing a resin and a hardener to form a sealant having a density greater than a density of the well fluid present in the bore and present in an annulus formed between the inner tubular string and an outer tubular string; and injecting the sealant into the annulus. The sealant falls down the annulus to the opening. A portion of the sealant is diverted through the opening and into the bore. The sealant cures to form a balanced plug in the annulus and the bore. 
         [0008]    In another embodiment, a method for sealing a well includes: placing an obstruction in a bore of an inner tubular string; forming an opening through a wall of the inner tubular string above the obstruction; mixing a resin and a hardener to form a sealant having a density greater than a density of fluid present in the bore and present in an annulus formed between the inner tubular string and an outer tubular string; and injecting the sealant into the annulus; and injecting the sealant into the bore. The sealant falls down the bore to the opening. A portion of the sealant is diverted by the obstruction, through the opening, and into the annulus. The sealant cures to form a balanced plug in the annulus and the bore. 
         [0009]    In another embodiment, a method for sealing a well includes: mixing a resin and a hardener to form a sealant having a density greater than a density of fluid present in an annulus formed between an inner tubular string and at least one of an outer tubular string and a formation of the well; and injecting the sealant into the annulus. The sealant falls down the annulus to the top of a defective cement sheath. The sealant cures to form a plug remediating the defective cement sheath. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0010]    So that the manner in which the above recited features of the present disclosure can be understood in detail, a more particular description of the disclosure, 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 disclosure and are therefore not to be considered limiting of its scope, for the disclosure may admit to other equally effective embodiments. 
           [0011]      FIG. 1  illustrates a prior art platform well. 
           [0012]      FIG. 2  illustrates the platform and completion of the well damaged by a hurricane. 
           [0013]      FIG. 3  illustrates a diver tier-cutting the completion to begin the abandonment operation, according to one embodiment of the present disclosure. 
           [0014]      FIG. 4  illustrates deployment of a packoff. 
           [0015]      FIG. 5  illustrates engagement of the packoff with the remaining completion. 
           [0016]      FIG. 6  illustrates connection of a sealant flow line to the packoff and deployment of a lower bridge plug from a support vessel. 
           [0017]      FIG. 7A  illustrates setting of the lower bridge plug in the production tubing string. 
           [0018]      FIG. 7B  illustrates perforation of the production tubing string. 
           [0019]      FIGS. 8-10  illustrate a mixing unit onboard the support vessel and operation thereof to form the sealant. 
           [0020]      FIG. 11A  illustrates falling of the sealant down an annulus of the well.  FIG. 11B  illustrates curing of the sealant to plug the production tubing string and the annulus. 
           [0021]      FIG. 12A  illustrates cutting of the production tubing string.  FIG. 12B  illustrates setting of an upper bridge plug in the production casing string. 
           [0022]      FIG. 13  illustrates cement plugging of a bore of the production casing string. 
           [0023]      FIG. 14  illustrates the diver supplying the sealant into the well and falling of the sealant down a bore of the production tubing string, according to another embodiment of the present disclosure. 
           [0024]      FIG. 15  illustrates falling of the sealant down the production casing bore to plug a casing annulus of the well, according to another embodiment of the present disclosure. 
           [0025]      FIG. 16  illustrates falling of the sealant down a bore of a subsea production tree, according to another embodiment of the present disclosure. 
           [0026]      FIG. 17A  illustrates falling of the sealant down an annulus to remediate a primary cement sheath, according to another embodiment of the present disclosure. 
           [0027]      FIG. 17B  illustrates curing of the sealant to plug the annulus. 
       
    
    
     DETAILED DESCRIPTION 
       [0028]      FIG. 3  illustrates a diver  20  tier-cutting the completion  1  to begin the abandonment operation, according to one embodiment of the present disclosure. A support vessel  21  may be deployed to a location over the subsea wellbore  8 . The vessel  21  may include a tower  22  located over a moonpool  23 , a hoisting winch  24 , a wireline winch  25 , a flow line reel  26 , a mixing unit  27 , and a hydraulic power unit (HPU)  28 . 
         [0029]    The diver  20  may be dispatched from the support vessel  21  to the subsea wellbore  8 . The diver  20  may then sever an upper portion of the completion  1  from a lower portion thereof using a saw  29 , such as a band saw, reciprocating saw, or a diamond wire saw. The cut may be adjacent to a location where the completion  1  extends from the seafloor  5 . The diver  20  may tier-cut the completion  1  so that a portion of the production casing string  13  and a portion of the production tubing string  17  extend from the seafloor  5 . 
         [0030]    Alternatively, a crane (not shown) may be used instead of the winch and tower. Alternatively, a remotely operated vehicle (ROV) (not shown) may be deployed instead of the diver  20 . Alternatively, the mixing unit  27  and flow line reel  26  may be located on a support barge (not shown) adjacent to the support vessel  21 . 
         [0031]      FIG. 4  illustrates deployment of a packoff  30 . The packoff  30  may include a clamp, such as retention flange, upper and lower annular blowout preventers (BOPs) (i.e., conical or spherical), a spool, an inlet, and a pressure gage. The packoff  30  may be lowered from the support vessel by the hoisting winch  24  to the diver  20 . The diver  20  may guide the packoff  30  onto the tier-cut portion of the completion  1  and fasten the retention flange to the production casing string  13 . A hydraulic umbilical  31  may then be connected from the HPU  28  onboard the support vessel  21  to hydraulic ports of the annular BOPs. 
         [0032]      FIG. 5  illustrates engagement of the packoff  30  with the remaining completion  1 . The annular BOPs of the packoff  30  may then be operated by injection of hydraulic fluid from the HPU  28 , through the umbilical  31 , and into respective hydraulic ports thereof until respective packers thereof engage the respective production casing  13  and tubing  17  strings, thereby isolating the annulus  18  therebetween. 
         [0033]      FIG. 6  illustrates connection of a sealant flow line  32  to the packoff  30  and deployment of a lower bridge plug  33  from the support vessel  21 . The flow line  32 , such as hose, may be lowered to the diver  20  by unwinding from the reel  26 . The diver  20  may connect the lower end of the flow line  32  to the inlet of the packoff  30 . The upper end of the flow line  32  may be connected to an outlet of the mixing unit  27 . A first bottomhole assembly (BHA)  34  may be connected to wireline  35  onboard the support vessel  21  and lowered therefrom into the production tubing bore. The first BHA  34  may include a cablehead, a collar locator, a setting tool, and the lower bridge plug  33 . 
         [0034]    Alternatively, the flow line  32  may be flex hose, stick pipe, or coiled tubing. Alternatively, if the completion  1  is still upright, the sealant  36  may be injected into the annulus  18  via the wellhead. 
         [0035]      FIG. 7A  illustrates setting of the lower bridge plug  33  in the production tubing string  17 . The first BHA  34  may be deployed to a setting depth adjacent to, such as just below, the production packer  19 . Once the first BHA  34  has been deployed to the setting depth, electrical power may then be supplied to the first BHA via the wireline  35  to operate the setting tool, thereby expanding the lower bridge plug  33  against an inner surface of the production tubing string  17 . Once the lower bridge plug  33  has been set, the setting tool may be released from the set plug. The setting tool may then be retrieved to the support vessel  21 . 
         [0036]    Alternatively, a packer or cement plug may be set instead of the bridge plug  33  or a sand bed poured instead of the bridge plug. 
         [0037]      FIG. 7B  illustrates perforation of the production tubing string  17 . The first BHA  34  may be disconnected from the wireline  35  and a second BHA  37  connected to the wireline. The second BHA  37  may include a cablehead, a collar locator, and a perforating gun. The second BHA  37  may be lowered from the support vessel  21  into the production tubing bore. The second BHA  37  may be deployed to a firing depth adjacent to, such as just above, the production packer  19 . Once the second BHA  37  has been deployed to the firing depth, electrical power may then be supplied to the second BHA via the wireline  35  to fire shaped charges of the perforating gun into the production tubing string  17 , thereby forming perforations  38  through a wall thereof. The second BHA  37  may then be retrieved to the support vessel  21 . 
         [0038]    Alternatively, the first  34  and second  37  BHAs may be combined and the bridge plug set  33  and the production tubing string  17  perforated in a single round trip instead of two round trips. Alternatively, another type of opening besides perforations may be formed through the production tubing wall, such as by a wireline operated tubing cutter ( FIG. 12A ), an abrasive jet cutter, a tubing punch, or a thermite torch. Alternatively, if the production tubing string  17  has already been breached by corrosion, the breach may be utilized, thereby obviating the need for perforation. 
         [0039]      FIGS. 8-10  illustrate the mixing unit  27  onboard the support vessel  21  and operation thereof to form the sealant  36 . The mixing unit  27  may include two or more liquid totes  39   a,b , a transfer pump  40   a,b  for each liquid tote, a dispensing hopper  41 , and a blender  42 . Each transfer pump  40   a,b  may be a metering pump and the dispensing hopper  41  may be a metering hopper. An inlet of each transfer pump  40   a,b  may be connected to the respective liquid tote  39   a,b.    
         [0040]    A first  39   a  of the liquid totes  39   a,b  may include a resin  43 . The resin  43  may be an epoxide, such as bisphenol F. A viscosity of the sealant  36  may be adjusted by premixing the resin  43  with a diluent, such as alkyl glycidyl ether, benzyl alcohol, or a combination thereof. The viscosity of the sealant  36  may range between one hundred and two thousand centipoise. The resin  43  may also be premixed with a bonding agent, such as silane. A second  39   b  of the liquid totes  39   a,b  may include a hardener  44  selected based on temperature in the wellbore  8 . For low temperature, the hardener  44  may be an aliphatic amine or polyamine or a cycloaliphatic amine or polyamine, such as tetraethylenepentamine. For high temperature, the hardener may be an aromatic amine or polyamine, such as diethyltoluenediamine. The dispensing hopper  41  may include a particulate weighting material  45  having a specific gravity of at least two. The weighting material  45  may be barite, hematite, hausmannite ore, or sand. 
         [0041]    Alternatively, the wellbore fluid may be non-aqueous and the resin  43  may also be premixed with a surfactant to maintain cohesion thereof as the sealant  36  falls therethrough. Alternatively, the resin  43  may also be premixed with a defoamer. 
         [0042]    To form the sealant  36 , the first transfer pump  40   a  may be operated to dispense the resin  43  into the blender  42 . A motor of the blender  42  may then be activated to churn the resin  43 . The hopper  41  may then be operated to dispense the weighting material  45  into the blender  42 . The weighting material  45  may be added in a proportionate quantity such that a density of the sealant  36  is greater than a density of the wellbore fluid. The density of the sealant  36  may only be slightly greater than the density of the wellbore fluid, such as less than or equal to five percent greater than the density of the wellbore fluid. More specifically, the sealant density may be two-tenths pounds per gallon greater than the density of the wellbore fluid. For example if the wellbore  8  is filled with brine, such as seawater, having a (nominal) density of eight and a half pounds per gallon, then the sealant  36  may have a density of eight point seven pounds per gallon. 
         [0043]    The second transfer pump  40   b  may be operated to dispense the hardener  44  into the blender  42 . The hardener  44  may be added in a proportionate quantity such that a thickening time of the sealant  36  corresponds to a time required to pump the sealant to the packoff  30  plus a time required for the sealant to fall down the annulus  18 , and plus a safety factor, such as one hour. Once the blender  42  has formed the sealant  36  into a homogenous mixture, a supply valve  46  connected to an outlet of the blender may be opened. 
         [0044]      FIG. 11A  illustrates falling of the sealant  36  down the annulus  18  of the well. A delivery pump  47  (not shown, see  FIG. 14 ) may be operated to pump the sealant  36  from the blender  42  and into the flow line  32 . The inlet of the delivery pump  47  may then be connected to a supply of chaser fluid (not shown), such as seawater, and the delivery pump operated to pump the chaser fluid into the flow line  32 , thereby driving the sealant  36  through the flow line and to the packoff inlet. The delivery pump  47  may be a metering pump and may be shutoff once a volume of the chaser fluid has been pumped corresponding to a volume of the flow line  32 , thereby ensuring that the sealant  36  has been injected into the annulus  18  via the packoff inlet. Once the sealant  36  has been injected into the annulus  18 , the greater density of the sealant may cause the sealant to fall down the annulus under gravitational acceleration. The sealant  36  may arrive at the production packer  19  and a portion of the sealant may be diverted through the perforations  38  and into the bore of the production tubing string  17  until a depth of the sealant top in the production tubing bore is equal to a depth of the sealant top in the annulus  18  (aka balanced condition or U-tubing). Once balanced, a length of the sealant  36  in the annulus may be greater than or equal to fifty, one hundred, one hundred and fifty, or two hundred feet. 
         [0045]      FIG. 11B  illustrates curing of the sealant  36  to plug the production tubing string  17  and the annulus  18 . The sealant  36  may then be allowed to cure for a time, such as between one to five days, thereby forming a balanced plug  48 . The cured balanced plug  48  may have a minimal density differential between a top and a bottom thereof, such as less than or equal to five percent. The cured balanced plug  48  may plug the annulus  18  adjacent to the production tubing string  17  and the bore of the production tubing string. Once the sealant  36  has cured, the packoff  30  may be used to pressure test the balanced plug  48 . The packoff  30  may then be disengaged and retrieved to the support vessel  21 . 
         [0046]      FIG. 12A  illustrates cutting of the production tubing string  17 . The second BHA  37  may be disconnected from the wireline  35  and a third BHA  49  connected to the wireline. The third BHA  49  may include a cablehead, a collar locator, an anchor, a second HPU, an electric motor, and the tubing cutter. The third BHA  49  may be lowered from the support vessel  21  into the production tubing bore. The third BHA  49  may be deployed to a cutting depth adjacent to the surface casing string  10 . Once the third BHA  49  has been deployed to the cutting depth, the second HPU may be operated by supplying electrical power via the wireline  35  to set the anchor and extend blades of the tubing cutter and the motor operated to rotate the extended blades, thereby severing an upper portion of the production tubing string  17  from a lower portion thereof. The third BHA  49  and cut portion of the production tubing string may then be retrieved to the support vessel  21 . 
         [0047]    Alternatively, the tubing cutter may be a thermite torch or abrasive jet cutter. 
         [0048]      FIG. 12B  illustrates setting of an upper bridge plug  50  in the production casing string  13 . The third BHA  49  may be disconnected from the wireline  35  and the first BHA  34  reconnected to the wireline (with the upper bridge plug  50 ). The first BHA  34  may be lowered from the support vessel  21  into the production casing bore. The first BHA  34  may be deployed to a setting depth adjacent to, such as just above, the top of the remaining production tubing string  17 . Once the first BHA  34  has been deployed to the setting depth, electrical power may then be supplied to the first BHA via the wireline  35  to operate the setting tool, thereby expanding the upper bridge plug  50  against an inner surface of the production casing string  13 . Once the upper bridge plug  50  has been set, the setting tool may be released from the set plug. The setting tool may then be retrieved to the support vessel  21 . The diver  20  may then cut the production casing string  13  at the seafloor  5  and the scrap may be retrieved to the support vessel  21 . 
         [0049]      FIG. 13  illustrates cement plugging of a bore of the production casing string  13 . Once the upper bridge plug  50  has been set, cement slurry  51  may be pumped into the production casing bore down to the upper bridge plug  50  and allowed to cure, thereby forming a top cement plug and completing the abandonment operation. 
         [0050]    Alternatively, the sealant  36  may be used to plug a terrestrial wellbore. 
         [0051]      FIG. 14  illustrates the diver  20  supplying the sealant  36  into the well and falling of the sealant down a bore of the production tubing string  17 , according to another embodiment of the present disclosure. Alternatively, the tier-cut and packoff  30  may not be used especially if the completion  1  has been damaged at or below the seafloor  5 . The diver  20  may then manually insert the lower end of the flow line  32  into the production tubing bore (shown) or the annulus  18  (not shown) and the sealant  36  injected therein. The sealant  36  may then fall down the production tubing bore or the annulus  18  to the perforations  38 . 
         [0052]      FIG. 15  illustrates falling of the sealant  36  down the production casing bore to plug a casing annulus  52  of the well, according to another embodiment of the present disclosure. Alternatively, if an upper portion of the casing annulus  52  formed between the surface  10  and production  13  casing strings has not been cemented, the production casing string may be perforated and a second batch of sealant  36  mixed. The diver may then insert the lower end of the flow line  32  into the production casing bore (shown) or the casing annulus  52  (not shown) and the second batch of sealant  36  injected therein. The second batch of the sealant  36  may fall down the production casing bore or the casing annulus  52 . A portion of the sealant may then be diverted by the upper bridge plug  50  (if injected into the bore) or top of cement  14  in the casing annulus  52  (if injected into the casing annulus) and through the perforations  53  and allowed to cure, thereby forming the balanced plug in the production casing bore and the casing annulus and obviating the need for the top cement plug. 
         [0053]    Alternatively, the casing annulus  52  may be between the production casing string  13  and an intermediate casing string. 
         [0054]      FIG. 16  illustrates falling of the sealant  36  down a bore of a subsea production tree  54 , according to another embodiment of the present disclosure. Alternatively, the sealant  36  may be used to plug a deeper subsea well having a subsea wellhead  55 . An ROV  56  may be deployed to the tree  54  connected to the subsea wellhead  55 . The ROV  56  may remove the external cap from the tree and carry the cap to the support vessel  21 . The hosting winch  24  may then be used to lower a pressure control head  57  to the tree. The ROV  56  may guide landing of the pressure control head  57  onto the tree  54 . An umbilical  58  and one or more (pair shown) flow lines  59   a,b  may be deployed from the support vessel  21  and connected to the pressure control head  57 . One or more (pair shown) jumpers  60   a,b  may then be connected to the pressure control head  57  and the tree for operation of the tree  54  from a control van (not shown) onboard the vessel  21 . 
         [0055]    A seal head (not shown) may then be deployed from the support vessel  21  using the wireline winch  25  and landed on the pressure control head  57 . A plug retrieval tool (PRT) (not shown) may be released from the seal head and electrical power supplied to the PRT via the wireline, thereby operating the PRT to remove crown plugs from the tree  54 . A tree saver (not shown) may or may not then be installed in the production tree using a modified PRT. Once the crown plugs have been removed from the tree, the first BHA may be connected to the wireline and the seal head and deployed to the pressure control head. 
         [0056]    Once the seal head has landed on the pressure control head, a subsurface safety valve (SSV) (not shown) may be opened and the first BHA may be deployed into the wellbore using the wireline. The first BHA may be deployed to the setting depth adjacent to the production packer and the lower bridge plug set against the inner surface of the production tubing string. The first BHA may be retrieved to the seal head and the seal head dispatched from the pressure control head  57  to the support vessel  21 . 
         [0057]    The second BHA may be connected to the wireline and the seal head and deployed to the pressure control head  57 . Once the second BHA has landed on the pressure control head, the SSV may be opened and the second BHA may be deployed into the wellbore using the wireline. The second BHA may be deployed to the firing depth adjacent to the production packer and the perforations formed through the production tubing wall. The second BHA may be retrieved to the seal head and the seal head dispatched from the pressure control head to the support vessel. 
         [0058]    The sealant  36  may be mixed and pumped down a first one  59   a  of the flow lines  59   a,b , through the pressure control head  57 , and into a bore of the production tree  54 . The sealant  36  may then fall down through the production tree bore and into and down the production tubing bore until reaching the lower bridge plug. A portion of the sealant  36  may be diverted through the perforations and into the annulus adjacent to the production tubing until a depth of the sealant top in the annulus is equal to the depth of the sealant top in the production tubing bore. The sealant  36  may then be allowed to cure, thereby forming the balanced plug. 
         [0059]    Alternatively, the sealant  36  may be pumped into the annulus adjacent to the production tubing by opening a lower annulus valve of the production tree  54  and pumping the sealant down a second one  59   b  of the flow lines  59   a,b , through one of the jumpers  60   a,b  and an annulus passage of the tree, and into the subsea wellhead  55 . The sealant  36  may then fall down through the annulus adjacent to the production tubing bore until reaching the production packer. A portion of the sealant may be diverted through the perforations and into the production tubing bore until the depth of the sealant top in the bore is equal to the depth of the sealant top in the annulus. The sealant may then be allowed to cure, thereby forming the balanced plug. 
         [0060]    Advantageously, placement of the sealant  36  by falling allows plugging where the location is not accessible by conventional placement techniques. The epoxy sealant formulation can fall through well fluids and remain cohesive to form a set plug in a desired location. Typical cement slurries suffer dilution from contact with well fluid and must be separated therefrom using darts and/or wiper plugs. 
         [0061]      FIG. 17A  illustrates falling of the sealant  36  down an annulus  61  to remediate a primary cement sheath  62 , according to another embodiment of the present disclosure.  FIG. 17B  illustrates curing of the sealant  36  to plug the annulus  61 . A production casing string  63  has been hung from a terrestrial wellhead  64  and a primary cementing operation conducted to seal the annulus  61  formed between the surface casing string  65  and the wellbore  66 . The primary cementing operation included pumping a fluid train down a bore of the production casing string. The fluid train included a bottom wiper plug  67  followed by a slug of cement slurry which was followed by a top wiper plug  68 . The fluid train was propelled through the production casing string  63  by pumping chaser fluid therein. The bottom wiper plug  67  landed in a float collar of the production casing string  63  and pumping of the chaser fluid continued to burst a diaphragm thereof, thereby allowing the cement slurry to flow therethrough and into the annulus  61 . Pumping of the chaser fluid ceased in response to landing of the top wiper plug  68  onto the bottom wiper plug  67 . 
         [0062]    The intent of the primary cementing operation was to establish a top of the cement sheath  62  above a shoe of the surface casing string  65 . However, due to overpressure in the annulus  61 , some of the cement slurry was lost into the formation, thereby resulting in an actual cement top below the shoe of the surface casing string  65 . The deficiency in the height of the cement sheath  62  unacceptably leaves an upper portion of the formation exposed to the annulus  61 . To remedy this situation, an outlet of the delivery pump  47  may be connected to a valve of a port of the wellhead  64  in fluid communication with the annulus  61 . The mixing unit  27  may be operated to supply the sealant  36  to the delivery pump  47  and the delivery pump may inject the sealant through the wellhead  64  and into the annulus  61 . Once the sealant  36  has been pumped, the valve may be closed. Instead of seawater present in the annulus  61 , the sealant may fall through brine, water, conditioner, drilling mud and/or spacer fluid. The sealant  36  may then fall down the annulus until reaching the top of the cement sheath  62 . The sealant may be allowed to cure to form a plug  69  in a lower wellbore portion of the annulus  61  and an upper casing portion of the annulus, thereby effectively extending the actual top of the cement sheath  62  to the intended top of the cement sheath. 
         [0063]    Alternatively, the quantity of sealant  36  injected into the annulus  61  may only be sufficient to plug the lower wellbore portion of the annulus. 
         [0064]    Alternatively, the cement slurry may have been pumped in without maintaining sufficient pressure in the annulus  61  and gas from the formation may have infiltrated the cement slurry during setting, thereby compromising the integrity of the cement sheath even though the top of the cement sheath  62  is at the intended top. To remedy this situation, the sealant  36  may be injected into the annulus  61  and fall to the actual/intended top of the cement sheath  62 , thereby plugging only the casing portion of the annulus. 
         [0065]    Alternatively, the sealant may be used to remedy a defective cement plug in a subsea wellbore. 
         [0066]    While the foregoing is directed to embodiments of the present disclosure, other and further embodiments of the disclosure may be devised without departing from the basic scope thereof, and the scope of the invention is determined by the claims that follow.