US20170044864A1 - Method of sealing wells by squeezing sealant - Google Patents

Abstract

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.

Description

BACKGROUND OF THE DISCLOSURE
• Field of the Disclosure
• The present disclosure generally relates to a method of sealing wells by squeezing a sealant into an annulus thereof.
• Description of the Related Art
• 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.
• 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
• 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.
• 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
• 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.
• FIG. 1 illustrates delivery of an equipment package to a platform for performing the squeeze operation, according to one embodiment of the present disclosure.
• FIG. 2A illustrates perforation of a production casing string.FIG. 2B illustrates deployment of a sealing string.
• FIGS. 3A-3C illustrate operation of a mixing unit of the equipment package to form sealant.
• FIG. 4 illustrates squeezing of the sealant into an annulus formed between the production casing string and a surface casing string.
• FIGS. 5A and 5B illustrate a first alternative sealing operation, according to another embodiment of the present disclosure.
• FIGS. 6A and 6B illustrate a second alternative sealing operation, according to another embodiment of the present disclosure.
• FIGS. 7A and 7B illustrate a third alternative sealing operation, according to another embodiment of the present disclosure.
DETAILED DESCRIPTION
• FIG. 1 illustrates an illustrative equipment package1 used for performing the squeeze operation, and located on aplatform2, according to one embodiment of the present disclosure. Theplatform2 may be part of a well3 further including asubsea wellbore4, adrive pipe5, asurface casing string6, aproduction casing string7, and aproduction tubing string8. Thedrive pipe5 is commonly set from above asurface9s(aka waterline) of the sea9, through the sea, and into theseafloor9f(aka mudline). Thedrive pipe5 allows the wellhead (not shown) to be located on theplatform2 above thewaterline9s.
• Once thedrive pipe5 has been set, and (if desired cemented10a,thesubsea wellbore4 is drilled into theseafloor9fwithin the envelope of thedrive pipe5. Thesurface casing string6 is then run-in thedrive pipe5 and into thewellbore4 and cemented into place by forming acement sheath10b.When thewellbore4 reaches a hydrocarbon-bearing formation11, i.e., crude oil and/or natural gas, theproduction casing7 is run-into thewellbore4 and cemented into place withcement sheath10c. Thereafter, theproduction casing string7 is perforated12 to permit the fluid hydrocarbons (not shown) to flow into the interior thereof. The hydrocarbons are transported from the formation11 through theproduction tubing string8. Anannulus13 defined between theproduction casing string7 and theproduction tubing string8 is commonly isolated from the producing formation11 with aproduction packer14.
• During production of hydrocarbons from thewell3, it may become necessary to workover the well, install an artificial lift system, and/or stimulate or treat the formation11. To facilitate any of these operations, it is typically desirable to temporarily plug thewell3. Also, once the formation11 has been produced to depletion, regulations often require permanently plugging the well3 prior to abandoning thewell3. If either or both of thecement sheathes10b,chave become compromised, they will need to be repaired during either the temporary or permanent plugging and abandonment operation, using the squeeze operation.
• In order to prepare for the squeeze operation, the equipment package1 is delivered to theplatform2 via a transport vessel (not shown). The equipment package includes a coiledtubing unit15, amixing unit16, and asqueeze pump17. The coiledtubing unit15 includes a drum having coiled tubing22 (FIG. 2B) wrapped therearound, a gooseneck, an injector head for driving the coiled tubing, controls, and a hydraulic power unit. Awireline winch18 onboard theplatform2 may also be used to facilitate the squeeze operation. Thewireline winch18 typically includes a drum having wireline19 (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 theplatform2.
• FIG. 2A illustrates perforation of theproduction casing string7.FIG. 2A shows the condition of the well during an abandonment or closing in operation, wherein alower cement plug21 has been set and theproduction tubing string8 has been cut. To establish this condition, the well3 abandonment operation commences by connecting a bottomhole assembly (BHA) (not shown) to thewireline19 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.
• 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 thewellbore4 using thewireline19. The BHA is deployed to a depth adjacent to and above theproduction packer14. Once the BHA has been deployed to the desired depth, electrical power or an electrical signal is supplied to the BHA via thewireline19 to fire the perforating gun into theproduction tubing string8, thereby formingtubing perforations20 through the wall thereof. The BHA is retrieved to the lubricator and the lubricator is then removed from the production tree.
• Cement slurry (not shown) is then pumped through the production tree head, down theproduction tubing string8, and into theannulus13 via the createdtubing perforations20. Wellbore fluid displaced by the cement slurry will flow up theannulus13, through the wellhead and to theplatform2. Once a desired quantity of cement slurry has been pumped into theannulus13, an annulus valve of the wellhead is closed while continuing to pump the cement slurry, thereby forcing or “squeezing” cement slurry into the adjacent formation11. 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 thecement plug21 in the annulus, the surrounding formation, and within the lower portion of theproduction tubing string8.
• Once thecement plug21 has cured, a second BHA (not shown) is connected to thewireline19 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 theproduction tubing string8 to a depth adjacent to and above theproduction packer14. Once the second BHA has been deployed to the cutting depth, the HPU is operated by supplying electrical power via thewireline19 to extend blades of the tubing cutter and operate the motor to rotate the extended blades, thereby severing an upper portion of theproduction tubing string8 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 theproduction tubing string8 is removed from thewellbore4, leaving the wellbore in the state shown inFIG. 2A.
• Once the severed portion of theproduction tubing string8 has been removed, a third BHA (not shown) is connected to thewireline19 in the lubricator and deployed through the wellhead. The third BHA commonly includes a cablehead, a collar locator, a setting tool, and abridge plug23. The third BHA is deployed to a setting depth along a portion of theproduction casing string7 adjacent, and above, the lower terminus of thesurface casing string6. Once the third BHA has been deployed to the setting depth, electrical power is supplied to the third BHA via thewireline19 to operate the setting tool, thereby expanding thebridge plug23 against an inner surface of theproduction casing string7. Once thebridge plug23 has been set as shown inFIG. 2A, thebridge plug23 is released from the setting tool. The third BHA (minus the bridge plug23) is then retrieved to the lubricator and the lubricator is removed from the wellhead.
• Afourth BHA24 is then connected to thewireline19 in the lubricator and deployed through the wellhead. Thefourth BHA24 commonly includes a cablehead, a collar locator, and a casing perforator, such as a perforating gun. Thefourth BHA24 is deployed to a firing depth adjacent to and above thebridge plug23. Once thefourth BHA24 has been deployed to the firing depth, electrical power or an electrical signal is supplied to the fourth BHA via thewireline19 to fire the perforating gun into theproduction casing string7, thereby formingcasing perforations25 through a wall thereof as shown inFIG. 2A. Thefourth BHA24 is then retrieved to the lubricator and the lubricator is removed from the wellhead.
• FIG. 2B illustrates deployment of a sealing string. Afifth BHA26 is connected to the coiledtubing22 in a snubbing unit (not shown) and deployed through the wellhead. Thefifth BHA26 includes a squeeze packer and a setting tool. The injector head of the coiledtubing unit15 is operated to lower thefifth BHA26 to a squeezing depth adjacent to and above thecasing perforations25. Once thefifth BHA26 has been deployed to the squeezing depth, thesqueeze pump17 is operated to pump a setting plug (not shown), such as a ball, through the coiledtubing22 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 theproduction casing string7 to thereby seal the annuals between thecoiled tubing22 and theproduction casing string7. 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 coiledtubing22.
• FIGS. 3A-3C illustrate operation of the mixingunit16 to formsealant28. The mixingunit16 in the embodiment includes two or moreliquid totes29a,b, and atransfer pump30a, bfor each liquid tote, adispensing hopper31, and ablender32.
• Each transfer pump30a,bis, in the embodiment, a metering pump and thedispensing hopper31 is a metering hopper. An inlet of each transfer pump30a,bis connected to a respectiveliquid tote29a,b.
• A firstliquid tote29aof the liquid totes29a,bincludes aresin33r.Theresin33rmay be an epoxide, such as bisphenol F. The viscosity of thesealant28 may be adjusted by premixing theresin33rwith a diluent, such as alkyl glycidyl ether or benzyl alcohol. The viscosity of thesealant28 may range between fifty and two thousand centipoise. The epoxide may also be premixed with a bonding agent, such as silane. A secondliquid tote29bof the liquid totes29a,bmay include ahardener33hselected based on the temperature in thewellbore4. The contents of the liquid totes29a,b may be reversed. For low temperature applications, thehardener33hmay be an aliphatic amine or polyamine or a cycloaliphatic amine or polyamine, such as tetraethylenepentamine. For high temperature applications, thehardener33hmay be an aromatic amine or polyamine, such as diethyltoluenediamine. Thedispensing hopper31 includes aparticulate weighting material34 having a specific gravity of at least two. Theweighting material34 may be barite, hematite, hausmannite ore, or sand.
• Alternatively, wellbore fluid may be non-aqueous and theresin33rmay also be premixed with a surfactant to maintain cohesion thereof. Alternatively, theresin33rmay also be premixed with a defoamer.
• To form thesealant28, thefirst transfer pump30ais operated to dispense theresin33rinto theblender32. A motor of theblender32 is then activated to churn theresin33r.Thehopper31 is then operated to dispense theweighting material34 into theblender32. Theweighting material34 is added, as required, in a proportionate quantity such that a density of thesealant28 corresponds to a density of the wellbore fluid. The density of thesealant28 may be equal to, slightly greater than, or slightly less than the density of the wellbore fluid.
• Thesecond transfer pump30bis operated to dispense thehardener33hinto theblender32. Thehardener33his added in a proportionate quantity such that the thickening time of thesealant28 corresponds to the time required to pump the sealant through the coiledtubing22, plus the time required to squeeze the sealant into the annulus36 (FIG. 4) formed between theproduction casing string7 and thesurface casing string6, plus a safety factor, such as one hour. Once theblender32 has formed the components of thesealant28 into a homogenous mixture, asupply valve35 connecting the outlet of the blender ultimately to thesqueeze pump17 may be opened.
• FIG. 4 illustrates squeezing of thesealant28 into theannulus36. Thesqueeze pump17 is operated to pump thesealant28 from theblender32 and into the coiledtubing22. The pumping may be monitored using thepressure gauge37 of the equipment package1. Once thesealant28 has been pumped into the coiledtubing22 downstream of thesqueeze pump17, the inlet of thesqueeze pump17 is then connected to a supply of chaser fluid (not shown), such as seawater, and thesqueeze pump17 is operated to pump the chaser fluid into the coiledtubing22, thereby driving thesealant28 through the coiledtubing22 and into theannulus36 via thecasing perforations25. Thesealant28 flows into or through voids in thecement sheath10cpresent in theannulus36, thereby filling the voids and restoring the integrity of thecement sheath10c.As the stroke volume of the squeeze pump may be known or calculated, a stroke counter of thesqueeze pump17 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 coiledtubing22 extending from thesqueeze pump17, thereby ensuring that all of thesealant28 has been discharged from the coiledtubing22. A portion of thesealant28 also typically forms a bore plug in theproduction casing string7. Thesealant28 may also plug a portion of thecement sheath10cadjacent to thesurface casing string6.
• The squeeze packer is then unset, such as by exerting tension on (pulling on) the coiledtubing22. The coiledtubing22 and thefifth BHA26 is retrieved to theplatform2 and the sealant is allowed to cure for a time, such as between one to five days. If the abandonment operation is permanent, once thesealant28 has cured, thedrive pipe5,surface casing string6, andproduction casing string7 will typically be cut at or just below theseafloor9f,thereby completing the abandonment operation.
• FIGS. 5A and 5B illustrate a first alternative sealing operation, according to another embodiment of the present disclosure. In this alternative method of sealing, asixth BHA27 is deployed instead of thefourth BHA24. Thesixth BHA27 is deployed to the firing depth adjacent to and above thebridge plug23. Thesixth BHA27 is similar to thefourth BHA24 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 formdeep perforations38 through the walls of theproduction7 andsurface6 casing strings and thecement sheath10cwithout damaging the wall of thedrive pipe5, thereby establishing access to thecement sheath10bin anannulus39 formed between the production and surface casing strings. After performing the perforation step, thesixth BHA27 is retrieved to the lubricator and the lubricator is removed from the wellhead.
• Thefifth BHA26 is then connected to the coiledtubing22 and the injector head of the coiledtubing unit15 is operated to lower the fifth BHA to the squeezing depth adjacent to and above thedeep perforations38. Once thefifth BHA26 has been deployed to the squeezing depth, the squeeze packer of thefifth BHA26 is set. Thesqueeze pump17 is operated to pump thesealant28 from theblender32 and into the coiledtubing22 and then to chase the sealant with a secondary fluid such as seawater, thereby driving thesealant28 through the coiledtubing22 and into theannuli36,39 via thecasing perforations38. Thesealant28 flows into and through voids in the cement sheathes10b,cpresent in therespective annuli36,39, thereby filling the voids and restoring the integrity thereof. Thesealant28 may also plug a portion of thecement sheath10cadjacent to thesurface casing string6 and a portion of thecement sheath10badjacent to thedrive pipe5.
• 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 theproduction casing string7 to an alternative setting depth adjacent to a top of the severedproduction tubing string8 and adjacent to the wellbore wall instead of along a portion of theproduction casing string7 adjacent to thesurface casing string6. Once the third BHA has been deployed to the alternative setting depth, thebridge plug23 is set and released from the setting tool. The third BHA (minus the bridge plug23) is then be retrieved to the lubricator and the lubricator is then removed from the wellhead.
• Thefourth BHA24 is then connected to thewireline19 in the lubricator and deployed through the wellhead. Thefourth BHA24 is deployed to an alternative firing depth adjacent to and above thebridge plug23. Once thefourth BHA24 has been deployed to the alternative firing depth, electrical power or an electrical signal is supplied to the fourth BHA via thewireline19 to fire the perforating gun into theproduction casing string7, thereby formingalternative casing perforations40 through a wall thereof. Thefourth BHA24 is then retrieved to the lubricator and the lubricator is removed from the wellhead.
• Thefifth BHA26 is then connected to the coiledtubing22 and the injector head of the coiledtubing unit15 is operated to lower the fifth BHA to an alternative squeezing depth adjacent to and above thealternative casing perforations40. Once thefifth BHA26 has been deployed to the alternative squeezing depth, the squeeze packer of thefifth BHA26 is set. Thesqueeze pump17 is operated to pump thesealant28 from theblender32 and into the coiledtubing22 and then to chase the sealant with a secondary fluid such as seawater, thereby driving thesealant28 through the coiledtubing22 and into theannulus36 via thealternative casing perforations40. Thesealant28 flows into and through the voids in thecement sheath10cpresent in theannulus36 thereby filling the voids and restoring the integrity of the cement sheath. Thesealant28 thus plugs a portion of thecement sheath10cadjacent to the wellbore wall.
• FIGS. 7A and 7B illustrate a third alternative sealing operation, according to another embodiment of the present disclosure. In this alternative, thebridge plug23 is set at the alternative setting depth. Thesixth BHA27 is then deployed to a second alternative firing depth adjacent to and above a shoe of thesurface casing string6 and fired to form alternativedeep perforations41 through walls of theproduction7 andsurface6 casing strings and thecement sheath10c.
• Thefifth BHA26 is then connected to the coiledtubing22 and the injector head of the coiledtubing unit15 is operated to lower the fifth BHA to a second alternative squeezing depth adjacent to and above the alternativedeep perforations41. Once thefifth BHA26 has been deployed to the second alternative squeezing depth, the squeeze packer of thefifth BHA26 is set. Thesqueeze pump17 is operated to pump thesealant28 from theblender32 and into the coiledtubing22 and then to chase the sealant with an alternative fluid such as seawater, thereby driving thesealant28 through the coiledtubing22 and into theannuli36,39 via thecasing perforations38. Thesealant28 flows into and through voids in the cement sheathes10b,cpresent in therespective annuli36,39, thereby filling the voids and restoring the integrity thereof. Thesealant28 plugs a portion of thecement sheath10cadjacent to thesurface casing string6 and a portion thereof adjacent to the wellbore wall. Thesealant28 may also plug a portion of thecement sheath10badjacent to the wellbore wall.
• Alternatively, a pipe string is used instead of the coiledtubing22 to transport the sealant into thewellbore4. The pipe string typically includes joints of drill pipe or production tubing connected together, such as by threaded couplings.
• Alternatively, a cement plug is used instead of or in addition to thebridge plug23.
• Alternatively, thewell2 may further include one or more intermediate casing strings between thesurface6 andproduction7 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.
• Alternatively, thewellbore4 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, thewellbore4 may be subterranean and any of the sealing operations may be staged from drilling or workover rig located on a terrestrial pad adjacent thereto.
• 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.

Claims (20)

1. A method for sealing a well, comprising:

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.

2. The method ofclaim 1, wherein:

the annulus is an inner annulus,

the opening is also formed through a wall of the outer tubular string, and

the sealant is also squeezed into an outer annulus, thereby repairing a cement sheath present in the outer annulus.

3. The method ofclaim 1, wherein the inner and outer tubular strings are both casing strings.

4. The method ofclaim 1, further comprising squeezing at least a portion of the sealant into a formation into which the inner tubular sting extends.

5. The method ofclaim 1, further comprising squeezing at least a portion of the sealant into a formation into which the outer tubular sting extends.

6. The method ofclaim 1, wherein the squeezing of the sealant into the bore, through the opening, and into an annulus formed between the inner tubular string and an outer tubular string comprises;

pumping the sealant through a tubular extending into the inner tubular string and having a fluid volume; and

thereafter pumping a quantity of chaser fluid into the tubular having at least the volume of the tubular.

7. The method ofclaim 1, wherein:

the sealant is squeezed into the bore through coiled tubing, and

the method further comprises:

lowering the coiled tubing and a bottom hole assembly (BHA) through the bore; and

forming the obstruction by setting a squeeze packer of the BHA against an inner surface of the inner tubular string.

8. The method ofclaim 1, wherein:

the wellbore is a subsea wellbore,

the method further comprises, prior to placing the obstruction:

severing an upper portion of a production tubing string disposed in the wellbore from a lower portion thereof; and

removing the upper portion of the production tubing string from the wellbore.

9. The method ofclaim 1, wherein:

the resin is bisphenol F epoxide,

the hardener is selected from a group consisting of tetraethylenepentamine for a low temperature well and diethyltoluenediamine for a high temperature well, and the resin is premixed with a diluent selected from a group consisting of alkyl glycidyl ether and benzyl alcohol, and

a weighting material having a specific gravity of at least 2 is mixed with the resin and the hardener.

10. A method for sealing a well, comprising:

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.

11. The method ofclaim 10, wherein:

the annulus is an inner annulus,

the opening is also formed through a wall of an outer tubular string, and

the sealant is also squeezed into an outer annulus, thereby repairing a cement sheath present in the outer annulus.

12. The method ofclaim 10, wherein the inner tubular string is a casing string.

13. The method ofclaim 10, wherein:

the sealant is squeezed into the bore through coiled tubing, and

the method further comprises:

lowering the coiled tubing and a bottom hole assembly (BHA) through the bore; and

setting a squeeze packer of the BHA against an inner surface of the inner tubular string.

14. The method ofclaim 10, wherein:

the wellbore is a subsea wellbore,

the method further comprises, prior to placing the obstruction:

severing an upper portion of a production tubing string disposed in the wellbore from a lower portion thereof; and

removing the upper portion of the production tubing string from the wellbore.

15. The method ofclaim 1, wherein:

the resin is bisphenol F epoxide,

the hardener is selected from a group consisting of tetraethylenepentamine for a low temperature well and diethyltoluenediamine for a high temperature well, and

the resin is premixed with a diluent selected from a group consisting of alkyl glycidyl ether and benzyl alcohol.

16. The method ofclaim 10, wherein the density of the sealant corresponds to the density of fluid present in the well.

17. The method ofclaim 10, wherein a viscosity of the sealant is between 50-2,000 cp.

18. The method ofclaim 10, wherein:

the resin is premixed with a bonding agent, and

the bonding agent is silane.

19. A method of infiltrating openings in a cement liner on the exterior of a subsurface tubular, comprising:

preparing a sealant comprising:

an epoxide resin,

a hardener selected from a group consisting of tetraethylenepentamine for a low temperature well and diethyltoluenediamine for a high temperature well, wherein;

extending a conduit inwardly of the subsurface tubular to a location therein having at least one opening extending through the wall thereof, the opening located above an obstruction in the tubular and extending through the tubular in a location where a cement is present on the exterior of the tubular; and

pumping the sealant through the conduit and through the at least one opening in the wall of the tubular, and thence into openings in the cement.

20. The method ofclaim 19, further comprising an obstruction between the conduit and the wall of the tubular in a location above the openings in the wall of the tubular before pumping the sealant.

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