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BACKGROUND OF THE DISCLOSURE 
       [0001]    Field of the Disclosure 
         [0002]    The present disclosure generally relates to a method of sealing wells by squeezing a sealant into an annulus thereof. 
         [0003]    Description of the Related Art 
         [0004]    The hard impermeable sheath deposited in the annular space in a well by primary cementing is subjected to a number of stresses during the lifetime of the well. The pressure inside the casing can increase or decrease as the fluid filling it changes or as additional pressure is applied to the well, such as when the drilling fluid is replaced by a completion fluid or by a fluid used in a stimulation operation. A change of temperature also creates stress in the cement sheath, at least during the transition period before the temperatures of the steel and the cement come into equilibrium. As a result of pressure and temperature changes, the integrity of the cement sheath can be compromised. Thus, it can become necessary to repair the primary cement sheath, such as during a plug and abandonment operation. One way to repair the primary cement sheath is by squeeze cementing, i.e., squeezing Portland cement thereinto. 
         [0005]    The use of conventional Portland cement for squeeze cementing has limitations, for instance, if the primary cement sheath is leaking fluid, such as gas, through micro-channels, squeeze cementing is not feasible, even using micro-fine ground Portland cement. 
       SUMMARY OF THE DISCLOSURE 
       [0006]    The present disclosure generally relates to a method of sealing wells by squeezing sealant into the annulus between the inner and outer tubular strings. In one embodiment, a method for sealing a well includes: placing an obstruction in a bore of an inner tubular string disposed in a wellbore; forming an opening through a wall of the inner tubular string above the obstruction; mixing a resin and a hardener to form a sealant; and squeezing the sealant into the bore, through the opening, and into an annulus formed between the inner tubular string and an outer tubular string, thereby repairing a cement sheath present in the annulus. 
         [0007]    In another embodiment, a method for sealing a well includes: placing an obstruction in a bore of an inner tubular string disposed in a wellbore; forming an opening through a wall of the inner tubular string above the obstruction; mixing a resin and a hardener to form a sealant; and squeezing the sealant into the bore, through the opening, and into an annulus formed between the inner tubular string and the wellbore, thereby repairing a cement sheath present in the annulus. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0008]    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. 
           [0009]      FIG. 1  illustrates delivery of an equipment package to a platform for performing the squeeze operation, according to one embodiment of the present disclosure. 
           [0010]      FIG. 2A  illustrates perforation of a production casing string.  FIG. 2B  illustrates deployment of a sealing string. 
           [0011]      FIGS. 3A-3C  illustrate operation of a mixing unit of the equipment package to form sealant. 
           [0012]      FIG. 4  illustrates squeezing of the sealant into an annulus formed between the production casing string and a surface casing string. 
           [0013]      FIGS. 5A and 5B  illustrate a first alternative sealing operation, according to another embodiment of the present disclosure. 
           [0014]      FIGS. 6A and 6B  illustrate a second alternative sealing operation, according to another embodiment of the present disclosure. 
           [0015]      FIGS. 7A and 7B  illustrate a third alternative sealing operation, according to another embodiment of the present disclosure. 
       
    
    
     DETAILED DESCRIPTION 
       [0016]      FIG. 1  illustrates an illustrative equipment package  1  used for performing the squeeze operation, and located on a platform  2 , according to one embodiment of the present disclosure. The platform  2  may be part of a well  3  further including a subsea wellbore  4 , a drive pipe  5 , a surface casing string  6 , a production casing string  7 , and a production tubing string  8 . The drive pipe  5  is commonly set from above a surface  9   s  (aka waterline) of the sea  9 , through the sea, and into the seafloor  9   f  (aka mudline). The drive pipe  5  allows the wellhead (not shown) to be located on the platform  2  above the waterline  9   s.    
         [0017]    Once the drive pipe  5  has been set, and (if desired cemented  10   a,  the subsea wellbore  4  is drilled into the seafloor  9   f  within the envelope of the drive pipe  5 . The surface casing string  6  is then run-in the drive pipe  5  and into the wellbore  4  and cemented into place by forming a cement sheath  10   b.  When the wellbore  4  reaches a hydrocarbon-bearing formation  11 , i.e., crude oil and/or natural gas, the production casing  7  is run-into the wellbore  4  and cemented into place with cement sheath  10   c . Thereafter, the production casing string  7  is perforated  12  to permit the fluid hydrocarbons (not shown) to flow into the interior thereof. The hydrocarbons are transported from the formation  11  through the production tubing string  8 . An annulus  13  defined between the production casing string  7  and the production tubing string  8  is commonly isolated from the producing formation  11  with a production packer  14 . 
         [0018]    During production of hydrocarbons from the well  3 , it may become necessary to workover the well, install an artificial lift system, and/or stimulate or treat the formation  11 . To facilitate any of these operations, it is typically desirable to temporarily plug the well  3 . Also, once the formation  11  has been produced to depletion, regulations often require permanently plugging the well  3  prior to abandoning the well  3 . If either or both of the cement sheathes  10   b,c  have become compromised, they will need to be repaired during either the temporary or permanent plugging and abandonment operation, using the squeeze operation. 
         [0019]    In order to prepare for the squeeze operation, the equipment package  1  is delivered to the platform  2  via a transport vessel (not shown). The equipment package includes a coiled tubing unit  15 , a mixing unit  16 , and a squeeze pump  17 . The coiled tubing unit  15  includes a drum having coiled tubing  22  ( FIG. 2B ) wrapped therearound, a gooseneck, an injector head for driving the coiled tubing, controls, and a hydraulic power unit. A wireline winch  18  onboard the platform  2  may also be used to facilitate the squeeze operation. The wireline winch  18  typically includes a drum having wireline  19  ( FIG. 2A ) wrapped therearound and a motor for winding and unwinding the wireline, thereby raising and lowering a distal end of the wireline relative to the platform  2 . 
         [0020]      FIG. 2A  illustrates perforation of the production casing string  7 .  FIG. 2A  shows the condition of the well during an abandonment or closing in operation, wherein a lower cement plug  21  has been set and the production tubing string  8  has been cut. To establish this condition, the well  3  abandonment operation commences by connecting a bottomhole assembly (BHA) (not shown) to the wireline  19  extending through a lubricator (not shown). In the embodiment, the BHA includes a cablehead, a collar locator, and a tubing perforator, such as a perforating gun. 
         [0021]    To deploy the BHA into the well bore, one or more valves of the tree are opened and the BHA is deployed into the production tubing string in the wellbore  4  using the wireline  19 . The BHA is deployed to a depth adjacent to and above the production packer  14 . Once the BHA has been deployed to the desired depth, electrical power or an electrical signal is supplied to the BHA via the wireline  19  to fire the perforating gun into the production tubing string  8 , thereby forming tubing perforations  20  through the wall thereof. The BHA is retrieved to the lubricator and the lubricator is then removed from the production tree. 
         [0022]    Cement slurry (not shown) is then pumped through the production tree head, down the production tubing string  8 , and into the annulus  13  via the created tubing perforations  20 . Wellbore fluid displaced by the cement slurry will flow up the annulus  13 , through the wellhead and to the platform  2 . Once a desired quantity of cement slurry has been pumped into the annulus  13 , an annulus valve of the wellhead is closed while continuing to pump the cement slurry, thereby forcing or “squeezing” cement slurry into the adjacent formation  11 . Once pumped into place, the cement slurry is allowed to cure for a predetermined amount of time, such as one hour, six hours, twelve hours, or one day, thereby forming the cement plug  21  in the annulus, the surrounding formation, and within the lower portion of the production tubing string  8 . 
         [0023]    Once the cement plug  21  has cured, a second BHA (not shown) is connected to the wireline  19  in the lubricator and deployed through the production tree. The second BHA commonly includes a cablehead, a collar locator, an anchor, a hydraulic power unit (HPU), an electric motor, and a tubing cutter. The second BHA is deployed into the production tubing string  8  to a depth adjacent to and above the production packer  14 . Once the second BHA has been deployed to the cutting depth, the HPU is operated by supplying electrical power via the wireline  19  to extend blades of the tubing cutter and operate the motor to rotate the extended blades, thereby severing an upper portion of the production tubing string  8  from a lower portion thereof. The second BHA is then retrieved to the lubricator and the lubricator is removed from the production tree. The production tree is removed from the wellhead and the severed upper portion of the production tubing string  8  is removed from the wellbore  4 , leaving the wellbore in the state shown in  FIG. 2A . 
         [0024]    Once the severed portion of the production tubing string  8  has been removed, a third BHA (not shown) is connected to the wireline  19  in the lubricator and deployed through the wellhead. The third BHA commonly includes a cablehead, a collar locator, a setting tool, and a bridge plug  23 . The third BHA is deployed to a setting depth along a portion of the production casing string  7  adjacent, and above, the lower terminus of the surface casing string  6 . Once the third BHA has been deployed to the setting depth, electrical power is supplied to the third BHA via the wireline  19  to operate the setting tool, thereby expanding the bridge plug  23  against an inner surface of the production casing string  7 . Once the bridge plug  23  has been set as shown in  FIG. 2A , the bridge plug  23  is released from the setting tool. The third BHA (minus the bridge plug  23 ) is then retrieved to the lubricator and the lubricator is removed from the wellhead. 
         [0025]    A fourth BHA  24  is then connected to the wireline  19  in the lubricator and deployed through the wellhead. The fourth BHA  24  commonly includes a cablehead, a collar locator, and a casing perforator, such as a perforating gun. The fourth BHA  24  is deployed to a firing depth adjacent to and above the bridge plug  23 . Once the fourth BHA  24  has been deployed to the firing depth, electrical power or an electrical signal is supplied to the fourth BHA via the wireline  19  to fire the perforating gun into the production casing string  7 , thereby forming casing perforations  25  through a wall thereof as shown in  FIG. 2A . The fourth BHA  24  is then retrieved to the lubricator and the lubricator is removed from the wellhead. 
         [0026]      FIG. 2B  illustrates deployment of a sealing string. A fifth BHA  26  is connected to the coiled tubing  22  in a snubbing unit (not shown) and deployed through the wellhead. The fifth BHA  26  includes a squeeze packer and a setting tool. The injector head of the coiled tubing unit  15  is operated to lower the fifth BHA  26  to a squeezing depth adjacent to and above the casing perforations  25 . Once the fifth BHA  26  has been deployed to the squeezing depth, the squeeze pump  17  is operated to pump a setting plug (not shown), such as a ball, through the coiled tubing  22  to a seat of the setting tool. Fluid pressure may then be exerted on the seated ball to operate the setting tool, thereby expanding the squeeze packer against an inner surface of the production casing string  7  to thereby seal the annuals between the coiled tubing  22  and the production casing string  7 . In the embodiment, additional fluid pressure is then applied to drive the ball through the seat of the setting tool, thereby reopening the bore of the coiled tubing  22 . 
         [0027]      FIGS. 3A-3C  illustrate operation of the mixing unit  16  to form sealant  28 . The mixing unit  16  in the embodiment includes two or more liquid totes  29   a,b , and a transfer pump  30   a, b  for each liquid tote, a dispensing hopper  31 , and a blender  32 . 
         [0028]    Each transfer pump  30   a,b  is, in the embodiment, a metering pump and the dispensing hopper  31  is a metering hopper. An inlet of each transfer pump  30   a,b  is connected to a respective liquid tote  29   a,b.    
         [0029]    A first liquid tote  29   a  of the liquid totes  29   a,b  includes a resin  33   r.  The resin  33   r  may be an epoxide, such as bisphenol F. The viscosity of the sealant  28  may be adjusted by premixing the resin  33   r  with a diluent, such as alkyl glycidyl ether or benzyl alcohol. The viscosity of the sealant  28  may range between fifty and two thousand centipoise. The epoxide may also be premixed with a bonding agent, such as silane. A second liquid tote  29   b  of the liquid totes  29   a,b  may include a hardener  33   h  selected based on the temperature in the wellbore  4 . The contents of the liquid totes  29   a,  b may be reversed. For low temperature applications, the hardener  33   h  may be an aliphatic amine or polyamine or a cycloaliphatic amine or polyamine, such as tetraethylenepentamine. For high temperature applications, the hardener  33   h  may be an aromatic amine or polyamine, such as diethyltoluenediamine. The dispensing hopper  31  includes a particulate weighting material  34  having a specific gravity of at least two. The weighting material  34  may be barite, hematite, hausmannite ore, or sand. 
         [0030]    Alternatively, wellbore fluid may be non-aqueous and the resin  33   r  may also be premixed with a surfactant to maintain cohesion thereof. Alternatively, the resin  33   r  may also be premixed with a defoamer. 
         [0031]    To form the sealant  28 , the first transfer pump  30   a  is operated to dispense the resin  33   r  into the blender  32 . A motor of the blender  32  is then activated to churn the resin  33   r.  The hopper  31  is then operated to dispense the weighting material  34  into the blender  32 . The weighting material  34  is added, as required, in a proportionate quantity such that a density of the sealant  28  corresponds to a density of the wellbore fluid. The density of the sealant  28  may be equal to, slightly greater than, or slightly less than the density of the wellbore fluid. 
         [0032]    The second transfer pump  30   b  is operated to dispense the hardener  33   h  into the blender  32 . The hardener  33   h  is added in a proportionate quantity such that the thickening time of the sealant  28  corresponds to the time required to pump the sealant through the coiled tubing  22 , plus the time required to squeeze the sealant into the annulus  36  ( FIG. 4 ) formed between the production casing string  7  and the surface casing string  6 , plus a safety factor, such as one hour. Once the blender  32  has formed the components of the sealant  28  into a homogenous mixture, a supply valve  35  connecting the outlet of the blender ultimately to the squeeze pump  17  may be opened. 
         [0033]      FIG. 4  illustrates squeezing of the sealant  28  into the annulus  36 . The squeeze pump  17  is operated to pump the sealant  28  from the blender  32  and into the coiled tubing  22 . The pumping may be monitored using the pressure gauge  37  of the equipment package  1 . Once the sealant  28  has been pumped into the coiled tubing  22  downstream of the squeeze pump  17 , the inlet of the squeeze pump  17  is then connected to a supply of chaser fluid (not shown), such as seawater, and the squeeze pump  17  is operated to pump the chaser fluid into the coiled tubing  22 , thereby driving the sealant  28  through the coiled tubing  22  and into the annulus  36  via the casing perforations  25 . The sealant  28  flows into or through voids in the cement sheath  10   c  present in the annulus  36 , thereby filling the voids and restoring the integrity of the cement sheath  10   c.  As the stroke volume of the squeeze pump may be known or calculated, a stroke counter of the squeeze pump  17  may be monitored during pumping and the squeeze pump shutoff once a desired volume of the chaser fluid has been pumped based on a certain number of strokes, corresponding to the internal volume of the coiled tubing  22  extending from the squeeze pump  17 , thereby ensuring that all of the sealant  28  has been discharged from the coiled tubing  22 . A portion of the sealant  28  also typically forms a bore plug in the production casing string  7 . The sealant  28  may also plug a portion of the cement sheath  10   c  adjacent to the surface casing string  6 . 
         [0034]    The squeeze packer is then unset, such as by exerting tension on (pulling on) the coiled tubing  22 . The coiled tubing  22  and the fifth BHA  26  is retrieved to the platform  2  and the sealant is allowed to cure for a time, such as between one to five days. If the abandonment operation is permanent, once the sealant  28  has cured, the drive pipe  5 , surface casing string  6 , and production casing string  7  will typically be cut at or just below the seafloor  9   f,  thereby completing the abandonment operation. 
         [0035]      FIGS. 5A and 5B  illustrate a first alternative sealing operation, according to another embodiment of the present disclosure. In this alternative method of sealing, a sixth BHA  27  is deployed instead of the fourth BHA  24 . The sixth BHA  27  is deployed to the firing depth adjacent to and above the bridge plug  23 . The sixth BHA  27  is similar to the fourth BHA  24  except for having a deep casing perforator, such as a perforating gun, instead of the casing perforator. The deep casing perforating gun has a charge strength sufficient to form deep perforations  38  through the walls of the production  7  and surface  6  casing strings and the cement sheath  10   c  without damaging the wall of the drive pipe  5 , thereby establishing access to the cement sheath  10   b  in an annulus  39  formed between the production and surface casing strings. After performing the perforation step, the sixth BHA  27  is retrieved to the lubricator and the lubricator is removed from the wellhead. 
         [0036]    The fifth BHA  26  is then connected to the coiled tubing  22  and the injector head of the coiled tubing unit  15  is operated to lower the fifth BHA to the squeezing depth adjacent to and above the deep perforations  38 . Once the fifth BHA  26  has been deployed to the squeezing depth, the squeeze packer of the fifth BHA  26  is set. The squeeze pump  17  is operated to pump the sealant  28  from the blender  32  and into the coiled tubing  22  and then to chase the sealant with a secondary fluid such as seawater, thereby driving the sealant  28  through the coiled tubing  22  and into the annuli  36 ,  39  via the casing perforations  38 . The sealant  28  flows into and through voids in the cement sheathes  10   b,c  present in the respective annuli  36 ,  39 , thereby filling the voids and restoring the integrity thereof. The sealant  28  may also plug a portion of the cement sheath  10   c  adjacent to the surface casing string  6  and a portion of the cement sheath  10   b  adjacent to the drive pipe  5 . 
         [0037]      FIGS. 6A and 6B  illustrate a second alternative sealing operation, according to another embodiment of the present disclosure. In this second alternative sealing method, the third BHA is deployed into the production casing string  7  to an alternative setting depth adjacent to a top of the severed production tubing string  8  and adjacent to the wellbore wall instead of along a portion of the production casing string  7  adjacent to the surface casing string  6 . Once the third BHA has been deployed to the alternative setting depth, the bridge plug  23  is set and released from the setting tool. The third BHA (minus the bridge plug  23 ) is then be retrieved to the lubricator and the lubricator is then removed from the wellhead. 
         [0038]    The fourth BHA  24  is then connected to the wireline  19  in the lubricator and deployed through the wellhead. The fourth BHA  24  is deployed to an alternative firing depth adjacent to and above the bridge plug  23 . Once the fourth BHA  24  has been deployed to the alternative firing depth, electrical power or an electrical signal is supplied to the fourth BHA via the wireline  19  to fire the perforating gun into the production casing string  7 , thereby forming alternative casing perforations  40  through a wall thereof. The fourth BHA  24  is then retrieved to the lubricator and the lubricator is removed from the wellhead. 
         [0039]    The fifth BHA  26  is then connected to the coiled tubing  22  and the injector head of the coiled tubing unit  15  is operated to lower the fifth BHA to an alternative squeezing depth adjacent to and above the alternative casing perforations  40 . Once the fifth BHA  26  has been deployed to the alternative squeezing depth, the squeeze packer of the fifth BHA  26  is set. The squeeze pump  17  is operated to pump the sealant  28  from the blender  32  and into the coiled tubing  22  and then to chase the sealant with a secondary fluid such as seawater, thereby driving the sealant  28  through the coiled tubing  22  and into the annulus  36  via the alternative casing perforations  40 . The sealant  28  flows into and through the voids in the cement sheath  10   c  present in the annulus  36  thereby filling the voids and restoring the integrity of the cement sheath. The sealant  28  thus plugs a portion of the cement sheath  10   c  adjacent to the wellbore wall. 
         [0040]      FIGS. 7A and 7B  illustrate a third alternative sealing operation, according to another embodiment of the present disclosure. In this alternative, the bridge plug  23  is set at the alternative setting depth. The sixth BHA  27  is then deployed to a second alternative firing depth adjacent to and above a shoe of the surface casing string  6  and fired to form alternative deep perforations  41  through walls of the production  7  and surface  6  casing strings and the cement sheath  10   c.    
         [0041]    The fifth BHA  26  is then connected to the coiled tubing  22  and the injector head of the coiled tubing unit  15  is operated to lower the fifth BHA to a second alternative squeezing depth adjacent to and above the alternative deep perforations  41 . Once the fifth BHA  26  has been deployed to the second alternative squeezing depth, the squeeze packer of the fifth BHA  26  is set. The squeeze pump  17  is operated to pump the sealant  28  from the blender  32  and into the coiled tubing  22  and then to chase the sealant with an alternative fluid such as seawater, thereby driving the sealant  28  through the coiled tubing  22  and into the annuli  36 ,  39  via the casing perforations  38 . The sealant  28  flows into and through voids in the cement sheathes  10   b,c  present in the respective annuli  36 ,  39 , thereby filling the voids and restoring the integrity thereof. The sealant  28  plugs a portion of the cement sheath  10   c  adjacent to the surface casing string  6  and a portion thereof adjacent to the wellbore wall. The sealant  28  may also plug a portion of the cement sheath  10   b  adjacent to the wellbore wall. 
         [0042]    Alternatively, a pipe string is used instead of the coiled tubing  22  to transport the sealant into the wellbore  4 . The pipe string typically includes joints of drill pipe or production tubing connected together, such as by threaded couplings. 
         [0043]    Alternatively, a cement plug is used instead of or in addition to the bridge plug  23 . 
         [0044]    Alternatively, the well  2  may further include one or more intermediate casing strings between the surface  6  and production  7  casing strings and the sealant is squeezed into one or more annuli formed between the production casing string and the intermediate casing strings. Alternatively, the sealant is squeezed into an annulus formed between a liner string and a casing string and/or between the liner string and the wellbore wall. 
         [0045]    Alternatively, the wellbore  4  may be subsea having a wellhead located adjacent to the seafloor and any of the sealing operations may be staged from an offshore drilling unit or an intervention vessel. Alternatively, the wellbore  4  may be subterranean and any of the sealing operations may be staged from drilling or workover rig located on a terrestrial pad adjacent thereto. 
         [0046]    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.

Summary:
A method for sealing a well includes: placing an obstruction in a bore of an inner tubular string disposed in a wellbore; forming an opening through a wall of the inner tubular string above the obstruction; mixing a resin and a hardener to form a sealant; and squeezing the sealant into the bore, through the opening, and into an annulus formed between the inner tubular string and an outer tubular string, thereby repairing a cement sheath present in the annulus.