CN112219012A

CN112219012A - Gaseous seal injection in a wellbore

Info

Publication number: CN112219012A
Application number: CN201980035517.5A
Authority: CN
Inventors: 阿迪布·A·阿尔-穆梅恩; 阿哈迈德·阿尔-拉马丹
Original assignee: Saudi Arabian Oil Co
Current assignee: Saudi Arabian Oil Co
Priority date: 2018-05-30
Filing date: 2019-05-13
Publication date: 2021-01-12
Also published as: US20190368305A1; EP3803039A1; WO2019231651A1

Abstract

A method for treating a well, the method comprising: flowing a sealant heated to a gas phase to cement disposed in an annulus of the wellbore, wherein the annulus is formed between a casing installed in the wellbore and a cylindrical wall radially outward of the casing. The cement includes fluid loss openings that form over time. The method comprises the following steps: flowing the sealant in the gas phase through a fluid loss opening in the cement of the annulus and cooling the sealant in the gas phase to produce a phase change of the sealant. The phase change includes deposition of the sealant from a vapor phase to a solid phase or condensation of the sealant from a vapor phase to a liquid phase. Further, the sealant seals the fluid loss opening in response to cooling the sealant.

Description

Gaseous seal injection in a wellbore

Priority requirement

This application claims priority from U.S. patent application No. 15/992,835 filed on 30/5/2018, the entire contents of which are incorporated herein by reference.

Technical Field

The present disclosure relates to well treatments, and more particularly to plugging and sealing fluid openings through tight microcracks and channels in cement within the casing-annulus of an oil and gas well.

Background

Well control fluids may be used in wellbore sealing operations, wellbore testing operations, or other downhole type plugging operations to reduce the permeability of a downhole wall or surface in a wellbore or cemented casing, for example, by plugging cracks or fractures. Sometimes, the well control fluid is a liquid gel or solid material that is injected into the annulus of the wellbore to the annulus location to plug and seal cracks or other fractures in the annulus.

Disclosure of Invention

The present disclosure describes well treatment systems for treating wells, for example, for plugging and sealing cracks or fractures in a cementing annulus of a wellbore.

Certain aspects of the present disclosure include a method for treating a well. The method includes flowing a sealant heated to a gas phase to cement disposed in an annulus of the wellbore, the annulus formed between a casing installed in the wellbore and a radially outer cylindrical wall of the casing, wherein the cement includes fluid loss openings formed in the cement over time. The method further includes flowing the sealant in a gas phase through a fluid leak-off opening in the cement of the annulus, and in response to flowing the sealant through the fluid leak-off opening, cooling the sealant in the gas phase to produce a phase change of the sealant, the phase change including at least one of a deposition of the sealant from the gas phase to a solid phase or a condensation of the sealant from the gas phase to a liquid phase. The method also includes sealing the fluid loss opening with the sealant in response to cooling the sealant.

This and other aspects can include one or more of the following features. The method can comprise the following steps: the sealant is heated in a heated chamber and converted to a vapor phase. Converting the sealant to a vapor phase can include sublimation of the sealant from a solid phase to a vapor phase or sublimation of the sealant from a liquid phase to a vapor phase. At least one of (1) evaporation. The heating chamber may comprise an electrically heated chamber, and heating the sealant may comprise heating the sealant in the electrically heated chamber. The method may include purging the heating chamber with an inert gas chamber in fluid communication with the heating chamber. Flowing the sealant into the cement disposed in the annulus of the wellbore can include pumping the sealant into the cement with a compressor. Flowing the sealant into the cement disposed in the annulus of the wellbore includes continuously flowing the sealant in a gas phase into the cement until a positive pressure test of the annulus occurs. Flowing the sealant into the cement disposed in the annulus of the wellbore can include flowing the sealant in a gas phase from a top wellbore surface of the wellbore down the wellbore through the annulus. The fluid loss opening may include a crack in cement of the wellbore, and sealing the fluid loss opening with the sealant may include pressure sealing the crack in the cement of the wellbore with the sealant. The sealant in the gas phase may include an inert gas.

Certain aspects of the present disclosure include a well treatment system for treating a well, the well treatment system including a heating chamber connected in fluid communication to an annulus of a wellbore, the heating chamber for heating a sealant to a vapor phase. The sealant in the gas phase is for engaging a fluid loss opening in cement disposed in the annulus of the wellbore, and upon cooling of the sealant, the sealant changes phase from the gas phase to at least one of a liquid or solid phase and blocks the fluid loss opening.

This and other aspects can include one or more of the following features. The well treatment system can include a gas compressor for flowing sealant in a gas phase from the heating chamber to an annulus of the wellbore. The well treatment system can include a casing four-way flange for receiving a flow of sealant from the heating chamber and directing the flow of sealant into an annulus of the wellbore. The fluid loss openings in the cement disposed in the annulus of the wellbore may include cracks in the cement. The cracks in the cement of the annulus may include microcracks in the cement. The heating chamber may comprise an electrically heated chamber. The well treatment system may include an inert gas chamber coupled in fluid communication to the heating chamber to purge the heating chamber. An annulus may be formed between a casing installed in the wellbore and a cylindrical wall radially outward of the casing. The cylindrical wall may comprise a second casing installed in the wellbore radially outward from the first casing or an inner wall of the wellbore.

Certain aspects of the present disclosure include a method for treating a well. The method comprises the following steps: flowing the sealing composition in a gas phase through a fluid loss opening in the well; cooling the sealing composition to produce a phase change of the sealing composition, the phase change comprising at least one of deposition of the sealing composition from a vapor phase to a solid phase or condensation of the sealing composition from a vapor phase to a liquid phase; and sealing the fluid loss opening with the sealing composition in response to cooling the sealing composition to a phase change that results in the sealing composition.

This and other aspects can include one or more of the following features. The fluid loss opening may comprise an opening in cement disposed in the wellbore annulus of the well. The method may include heating the sealing composition in the gas phase in a heating chamber and converting the sealing composition to the gas phase prior to flowing the sealing composition in the gas phase through the fluid loss opening in the well.

The details of one or more implementations of the subject matter described in this disclosure are set forth in the accompanying drawings and the description. Other features, aspects, and advantages of the subject matter will become apparent from the description, the drawings, and the claims.

Drawings

FIG. 1 is a schematic partial cross-sectional view of an exemplary well system including a well treatment system;

FIG. 2 is a schematic diagram of an exemplary well treatment system; and

fig. 3 and 4 are flow charts illustrating exemplary processes for treating a wellbore.

Like reference numbers and designations in the various drawings indicate like elements.

Detailed Description

The present disclosure describes systems and methods for sealing cracks, fissures, or other openings in a wellbore, such as in a cement sheath space near a casing of the wellbore. The well treatment system provides the sealant in gaseous form to the one or more openings, and the sealant cools to undergo a phase change from a gas phase to a solid or liquid phase to plug and seal the one or more openings. The present disclosure describes sealing microcracks, including cracks or other openings that are too small to fill with conventional liquid or solid sealants. Many wellbores include: a casing lining at least a portion of a length of the wellbore; and cement filling an annulus formed between the casing and another outer cylindrical wall (e.g., a wellbore wall or another casing). Since cement is prone to cracking and wear over time, migration of well or formation fluids (or both) may occur through fluid loss openings in the cement, such as through cracks and microchannels in the cement that communicate with the open area of the fluid. The present disclosure describes injecting a gaseous sealant into cracks and microchannels and other fluid loss openings, and describes a phase change of the sealant to a solid or liquid form when the sealant is disposed within the fluid loss opening, thereby plugging and sealing the fluid loss opening to prevent fluid loss or other fluid migration. Although the present disclosure describes microcracking or other fluid loss openings in the cement in the annulus of the wellbore, fluid loss openings may be present in other areas of the wellbore. For example, fluid loss openings may be present in an open hole portion of a wellbore, in a downhole-type well tool disposed within the wellbore, in a wellbore casing, in a combination of these, or other surfaces within the wellbore. The present disclosure is also applicable to the sealing of these additional fluid loss openings.

In conventional sealing systems, a liquid or solid phase sealing fluid (e.g., a gel fluid or cement slurry) is pumped into a wellbore at the location of a crack or other fluid loss opening to seal the opening. Fluid loss openings may include cracks, fractures, perforations, or other openings in components in the wellbore (e.g., casing, cement in the wellbore annulus, well tools, formations, or other components of the well system). However, in some cases, it may be difficult or impossible to flow the sealant in its liquid or solid phase to the fluid loss opening due to insufficient permeability of the medium forming the opening. Conversely, it is easier to flow the sealant in a gaseous form because the sealant in the gaseous phase is able to flow through a medium having a permeability that may restrict the flow of a liquid or solid phase sealant through the medium. For example, liquid or solid phase sealing fluids are too large to penetrate and seal some small (e.g., miniature) fluid leak-off openings. For example, the microcracks may be ten to fifty microns in size. Cement has natural porosity but limited permeability unless micro-cracks or larger cracks form, for example, throughout the life of an oil or gas well, and the micro-cracks or larger cracks interconnect and cause pressure transmission from the high pressure formation to the surface wellhead. In the present disclosure, the seal component is heated to the vapor phase, for example in a heated chamber at the surface of the wellbore, and then pumped to the location of the fluid loss opening(s). The sealing component in its gas phase may enter the fluid loss opening, including the small openings and micro-cracks, and then cool to its solid phase or its liquid phase to plug the fluid loss opening. Sealant in the gas phase can enter smaller openings such as microcracks into which sealant in the liquid or solid phase cannot enter or flow. For example, in the cement sheath void, the sealant may flow into and seal one or more fluid communication channels created by microcracks formed in the cement. The sealant or sealing composition will be described in more detail later. Sealing microcracks and other fluid loss openings in the cement of the wellbore annulus can reduce or eliminate unwanted fluid flow in the annulus, such as oil or natural gas flow, and reduce or eliminate pressure buildup in the annulus and the corresponding wellhead. The sealing of microcracks and other fluid loss openings in the cement may help reduce or eliminate the presence of high pressure at the wellhead and possible blow-by behind the well casing.

FIG. 1 is a schematic, partial cross-sectional side view of an exemplary well system 100, the well system 100 including a generally cylindrical wellbore 102 extending from a wellhead 104 at the surface 105 down into the earth into one or more subterranean zones of interest. In the exemplary well system, the one or more subterranean zones of interest include a first subterranean zone 106 and a second subterranean zone 107. The well system 100 includes a vertical well in which a wellbore 102 extends substantially vertically from a surface 105 to a first subterranean zone 106 and a second subterranean zone 107. However, the concepts described herein may be applied to many different configurations of wells, including vertical wells, horizontal wells, slant wells, or wells that are otherwise deviated.

After drilling part or all of the wellbore 102, a portion of the wellbore 102 extending from the wellhead 104 to the subterranean zone 106 or zone 107 may be lined with a length of tubing known as casing or liner. The wellbore 102 may be drilled in sections, a casing may be installed between the sections, and a cementing operation may be performed to inject cement in sections between the casing and a cylindrical wall located radially outward from the casing. The cylindrical wall may be an inner wall of the wellbore 102 such that cement is disposed between the casing and the wellbore wall, the cylindrical wall may be a second casing such that cement is disposed between the two tubular casings, or the cylindrical wall may be a different generally tubular or cylindrical surface radially outward of the casings. In the example well system 100 of fig. 1, the system 100 includes a first liner or first casing 108, such as a surface casing, defined by a length of a first portion of the lined wellbore 102 of tubulars extending from the surface 105 into the earth. The first casing 108 is shown extending only partially along the wellbore 102 and into the subterranean zone 106; however, the first casing 108 may extend further into the wellbore 102 or terminate further uphole in the wellbore 102 than schematically shown in fig. 1. A first annulus 109 between the first casing 108 and the inner wall of the wellbore 102 and radially outward of the first casing 108 is shown filled with cement. The example well system 100 also includes a second liner or second casing 110, the second liner or second casing 110 being positioned radially inward from the first casing 108 and defined by a length of a second portion of the tubular lining the wellbore 102, the second liner or second casing 110 extending further downhole of the wellbore 102 than the first casing 108. The second casing 110 is shown extending only partially along the wellbore 102 and into the second subterranean zone 107, with the remainder of the wellbore 102 shown open hole (e.g., without a liner or casing); however, the second casing 110 may extend further into the wellbore 102 or terminate further uphole in the wellbore 102 than the second casing 110 schematically shown in fig. 1. A second annulus 111 radially outward of the second casing 110 and between the first casing 108 and the second casing 110 is shown filled with cement. The second annulus 111 may be partially or completely filled with cement. In some cases, this second annulus 111 is, for example, a casing-casing annulus (CCA), as a casing-casing annulus is an annulus between two tubular casings in a wellbore. Although fig. 1 illustrates that the example well system 100 includes two casings (the first casing 108 and the second casing 110), the well system 100 may include more casings or fewer casings, such as one, three, four, or more casings. In some examples, the well system 100 does not include casing and the wellbore 102 is an at least partially or fully open-hole wellbore.

Wellhead 104 defines an attachment point for other equipment of well system 100 to attach to well 102. For example, the wellhead 104 may include a christmas tree structure including valves for regulating flow into or out of the wellbore 102, casing attachments (e.g., a casing four-way outlet connected to the casing annulus (s)), combinations of these elements, or other structures incorporated into the wellhead 104. In the exemplary well system 100 of fig. 1, a well string 112 is shown as having been lowered into the wellbore 102 from a wellhead 104 at the surface 105. In some cases, the well string 112 is a string of connected lengths of end-to-end tubulars or continuous (or unconnected) coiled tubing. Well string 112 may constitute a work string, test string, production string, drill string, or other well string used during the life of well system 100. Well string 112 may include a number of different well tools that may drill, test, produce, intervene, or otherwise engage wellbore 102. For example, fig. 1 shows the well string 112 as including a well tool 114 at a bottom-most downhole end of the well string 112.

The example well system 100 also includes a well treatment system 116 that is coupled in fluid communication to the wellhead 104, such as by a fluid conduit 118. The well treatment system 116 provides a sealant material to the wellhead 104, which directs the sealant to a location within the well system 100. For example, components of the well system 100 (e.g., cement of the first annulus 109 or cement of the second annulus 111) may include fluid loss openings that allow undesired fluid migration within the wellbore 102, annulus, or other locations in the well system 100. Fluid loss openings may include cracks, fissures, perforations, or other openings that allow undesirable fluid flow or leakage. The well treatment system 116 provides a sealant material to one or more of these fluid loss openings to partially or completely seal the one or more fluid loss openings to reduce or prevent fluid migration through the one or more fluid loss openings.

Fig. 2 is a schematic diagram of an exemplary well treatment system 116, which well treatment system 116 may be used in the well system 100 of fig. 1. The well treatment system 116 produces the sealant composition in gaseous form and provides the gaseous sealant to a desired portion of the wellbore (e.g., wellbore 102). For example, referring to fig. 1 and 2, the example well treatment system 116 may provide a gaseous sealant to the wellhead 104, particularly a casing four-way side flange of the wellhead 104, and the wellhead 104 may direct the gaseous sealant to an annulus of the wellbore 102, such as the first annulus 109, the second annulus 111, or another annulus of the wellbore 102 or a CCA. As the first and

second annuli

109, 111 are cemented, a gaseous sealant may be injected into one or more of these annuli and any fluid leak-off openings in the cement of these annuli may flow through and past them and may cool to a solid or liquid phase sealant to fill, plug, block or otherwise seal the fluid leak-off openings in the cement. For example, high pressure build-up in the air of the cement sheath monitored by a pressure gauge at the casing four-way outlet flange may indicate the presence of microcracks formed in the cement. In response to such monitored high pressure, the sealant injection process may continue to partially or fully seal the fluid communication channel in the cement in the annulus.

The example well treatment system 116 of FIG. 2 includes a heater 202, a compressor 204, and a purge assembly 206 connected in fluid communication with each other, and a fluid conduit 118 connecting the well treatment system 116 in fluid communication and allowing a flow of a sealant to the wellhead 104. The heater 202 includes a heating chamber 208 for heating the sealant to a vapor phase. In some embodiments, the heater 202 includes an electrically heated chamber 208 that is sealed from the atmosphere during the heating process of the sealant. In other embodiments, the heater 202 may comprise a combustion type heater or other non-electrically heated chamber. However, in embodiments where the example well treatment system 116 is part of a well system and may be exposed to hydrocarbons or other combustible materials present at the well system, a fired heater may be hazardous, while an electric heater is preferred.

The sealant can be in a solid phase, a liquid phase, or a combination of both, such as a mixed phase gel-type material, prior to being heated in the heating chamber 208. The solid or liquid phase sealant 212 is shown in fig. 2 as being disposed in the heating chamber 208 prior to phase change into a gaseous sealant. Examples of the sealant may vary, and the sealant may be converted into a gas phase in the heater 202 by vaporization or sublimation. In some embodiments, the sealant is inert in that it does not chemically react with steel, cement, or formation fluids including water or hydrocarbons. In certain embodiments, the sealant may vaporize or sublimate at relatively low temperatures (e.g., between 250 degrees Celsius and 300 degrees Celsius), and the boiling point changes less with the application of pressure. For example, while within the compressor 204, the heated sealant in the vapor phase maintains its phase and does not return to its initial phase, e.g., solid or liquid phase, during injection due to the pressure inside the compressor 204. In some examples, the sealant may include kevlar fibers, tar, naphthalene, other chemicals or chemical mixtures, or combinations of these.

The heater 202 heats the sealant in its heating chamber 208 to a temperature above the vaporization temperature or sublimation temperature of the sealant material to cause a phase change of the sealant to its vapor phase. With the sealant in the gas phase, the well treatment system 116 can flow the sealant to and through the fluid leak-off opening(s) of the well system, and after the sealant cools, when the sealant is disposed in the fluid leak-off opening(s), the sealant can return to its original solid, liquid, or mixed phase, thereby sealing (partially or fully) the fluid leak-off opening to prevent fluid migration. The heating temperature and the cooling temperature of the sealant depend on the boiling point temperature of the sealant. In one example, if the boiling and evaporation temperatures of the sealant are 250 degrees celsius (° c), the sealant should be heated to 300 ℃ -350 ℃ in the heater 202 before being injected down into the cracks of the cement in the annulus. As the sealant travels through the cement crack, it will gradually lose heat and return to its initial phase at the same boiling point of 250 ℃. In some examples, the sealant may be heated in the heater 202 to 50-100 ℃ above its boiling, evaporating or sublimating temperature and then injected into the cement sheath void to fill the fluid loss openings and channels created by the microcracks. The sealant may then gradually cool below its boiling, evaporating or sublimating temperature while remaining in the fluid loss openings and passages, thereby sealing the fluid loss openings and passages. The seal created by the sealant can be a partial or full pressure seal, a partial or full fluid seal, a partial or full obstruction, or other type of seal. In some examples, the temperature of the wellbore and surrounding earth is much lower than the injected gaseous sealant. Thus, the sealant cools down and returns to its solid or liquid phase after a cooling time. As more injections are performed, more solid or liquid sealant fills the crack and prevents any further injections. The injection may be stopped once the injection pressure reaches a predetermined maximum level. Since the temperature of the annulus is less than the vaporization or sublimation temperature of the sealant, cooling of the sealant from its gas phase to its initial liquid or solid phase can occur naturally. The sealant is injected into the cement and occupies the space present in the cement in cracks, leak-off points or other fluid loss openings, and naturally cools down, which causes the sealant to change phase back to its solid or liquid phase.

In some embodiments, as shown in fig. 2, compressor 204 pumps gaseous sealant from heater 202 to a fluid loss opening of the well system. The compressor 204 is a gas compressor and provides a controlled injection pressure of the gaseous sealant to the fluid conduit 118. The compressor 204 may pump the gaseous sealant to the annulus of the wellbore 102 via the fluid conduit 118 at continuous pressure in cycles of higher and lower pressure or in another injection mode.

In some cases, the well treatment system 116, the wellhead 104, or both, include pressure sensors (not shown) to monitor the pressure in the first annulus 109, the second annulus 111, the wellbore 102, the work string 112, or a combination of these. For example, where the well treatment system 116 provides a gaseous sealant to the second annulus 111(CCA), the pressure sensor may monitor the pressure in the second annulus 111. The monitoring data from the pressure sensor may be used to determine injection pressure, injection process cycles, pressure test cycles, and combinations of these. In some examples, when the well treatment system 116 provides gaseous sealant to the second annulus 111 during an injection process cycle, positive pressure test results from the pressure sensors may indicate that no further sealant injection is possible, that the fluid loss openings in the cement of the second annulus 111 are sealed, or both.

As previously mentioned, the cement in the first annulus 109, the cement in the second annulus 111, or the cement in both annuli are prone to cracking or other wear that would allow fluid leakage and unwanted migration of fluid through the cement. A sealant in the gas phase has a higher infusion potential or permeability than a sealant in the solid or liquid phase. With the well treatment system 116, a gaseous sealant can be introduced and injected into the fluid loss opening with a higher injection probability and permeability than a solid or liquid sealant, which can still cool and phase change to its initial solid or liquid phase once the sealant has been disposed within the fluid loss opening.

In some embodiments, the heating chamber 208 of the heater 202 is purged by the purge assembly 206 before or upon completion (or both) of the heating and injection processes of the sealant. The example purge assembly 206 of fig. 2 includes one or more inert gas cylinders 210 (five shown), with each inert gas cylinder 210 having a controlled valve that controls the supply of inert gas from the cylinder 210 to the heating chamber 208 of the heater 202. The inert gas supplied to the heating chamber 208 purges the heating chamber 208, for example, to reduce the risk of or prevent undesirable combustion of any residual material in the heating chamber 208 at high temperatures. In some examples, the inert gas is used to push all of the air out of the heating chamber 208 through an exhaust valve (not shown) in the fluid conduit 118 and release the air to the atmosphere, or direct the air to a separate purge reservoir, prior to the heating process of the sealant. During the heating process, the inert gas may be used to purge the heating chamber 208 and push the gaseous sealant 212 within the chamber 208 into the compressor 204 to be injected into the casing annulus. In some embodiments, the heating, purging, and injection processes are repeated in a periodic manner until a desired pressure lock is reached in the annulus and injection is no longer possible. The inert gas cylinder 210 may include an inert gas supply of nitrogen, helium, or other inert gas.

FIG. 3 is a flow chart depicting an example method 300 for treating a well, such as performed by the example well treatment system 116 of FIG. 2. At 302, the sealant heated to a gas phase is flowed to cement disposed in an annulus of the wellbore. An annulus is formed between a casing installed in the wellbore and the cylindrical wall radially outward of the casing, wherein the cement includes fluid loss openings formed in the cement over time. At 304, the sealant in the gas phase flows through a fluid loss opening in the cement of the wellbore. At 306, the sealant in the vapor phase is cooled to produce a phase change of the sealant. The phase change includes at least one of deposition of the sealant from a vapor phase to a solid phase or condensation of the sealant from the vapor phase to a liquid phase. At 308, the sealant seals the fluid loss opening in response to cooling the sealant.

FIG. 4 is a flow chart depicting an exemplary method 400 for treating a well, such as performed by the exemplary well treatment system 116 of FIG. 2. At 402, a sealing composition in a gas phase flows through a fluid loss opening in a well. At 404, the sealing composition is cooled to produce a phase change of the sealing composition. The phase change comprises at least one of deposition of the sealing composition from a gas phase to a solid phase or condensation of the sealing composition from a gas phase to a liquid phase. At 406, the sealing composition seals the fluid loss opening in response to cooling the sealing composition to a phase change that results in the sealing composition.

A number of embodiments have been described. Nevertheless, it will be understood that various modifications may be made without departing from the spirit and scope of the disclosure.

Claims

1. A method for treating a well, the method comprising:

flowing a sealant heated to a gas phase into a cement disposed in an annulus of a wellbore, the annulus formed between a casing installed in the wellbore and a cylindrical wall radially outward of the casing, wherein the cement includes fluid loss openings formed in the cement over time;

flowing the sealant in a gas phase through the fluid loss openings in the cement of the annulus;

in response to flowing the sealant through the fluid leak-off opening, cooling the sealant in a vapor phase to produce a phase change of the sealant, the phase change including at least one of deposition of the sealant from the vapor phase to a solid phase or condensation of the sealant from the vapor phase to a liquid phase; and

sealing the fluid loss opening with the sealant in response to cooling the sealant.

2. The method of claim 1, comprising:

heating the sealant in a heating chamber and converting the sealant to the vapor phase.

3. The method of claim 2, wherein converting the sealant to the vapor phase comprises at least one of sublimation of the sealant from a solid phase to a vapor phase or evaporation of the sealant from a liquid phase to a vapor phase.

4. The method of claim 2, wherein the heating chamber comprises an electrically heated chamber and heating the sealant comprises:

heating the sealant in the electrically heated chamber.

5. The method of claim 2, further comprising:

purging the heating chamber with an inert gas chamber connected in fluid communication to the heating chamber.

6. The method of claim 1, wherein flowing the sealant to cement disposed in an annulus of the wellbore comprises:

pumping the sealant into the cement with a compressor.

7. The method of claim 1, wherein flowing the sealant to cement disposed in an annulus of a wellbore comprises:

continuously flowing a sealant in the gas phase into the cement until a positive pressure test of the annulus occurs.

8. The method of claim 1, wherein flowing the sealant to cement disposed in an annulus of the wellbore comprises:

flowing the sealant in the gas phase downhole through the annulus from a top wellbore surface of the wellbore.

9. The method of claim 1, wherein the fluid loss opening comprises a crack in cement of the wellbore, and sealing the fluid loss opening with the sealant comprises:

pressure sealing the crack in the cement of the wellbore with the sealant.

10. The method of claim 1, wherein the sealant in a gas phase comprises an inert gas.

11. A well treatment system for treating a well, the well treatment system comprising:

a heating chamber connected in fluid communication to an annulus of the wellbore, the heating chamber for heating the sealant to a vapor phase; and

a sealant in a gas phase for engaging a fluid loss opening in cement disposed in the annulus of the wellbore, and upon cooling the sealant, the sealant changes phase from the gas phase to at least one of a liquid or solid phase and blocks the fluid loss opening.

12. The well treatment system of claim 11, comprising a gas compressor for flowing the sealant in a gas phase from the heating chamber to the annulus of the wellbore.

13. The well treatment system of claim 11, comprising a casing four-way flange for receiving a flow of sealant from the heating chamber and directing the flow of sealant into the annulus of the wellbore.

14. The well treatment system of claim 11, wherein the fluid loss opening in the cement disposed in the annulus of the wellbore comprises a crack in the cement.

15. The well treatment system of claim 14, wherein the cracks in the cement of the annulus comprise micro cracks in the cement.

16. The well treatment system of claim 11, wherein the heating chamber comprises an electrically heated chamber.

17. The well treatment system of claim 11, comprising an inert gas chamber fluidly connected to the heating chamber to purge the heating chamber.

18. The well treatment system of claim 11, wherein the annulus is formed between a casing installed in the wellbore and a cylindrical wall radially outward of the casing.

19. The well treatment system of claim 18, wherein the cylindrical wall comprises a second casing mounted in the wellbore radially outward of the first casing or an inner wall of the wellbore.

20. A method for treating a well, comprising:

flowing the sealing composition in a gas phase through a fluid loss opening in the well;

cooling the sealing composition to produce a phase change of the sealing composition, the phase change comprising at least one of deposition of the sealing composition from the vapor phase to a solid phase or condensation of the sealing composition from the vapor phase to a liquid phase; and

sealing the fluid loss opening with the sealing composition in response to cooling the sealing composition to a phase change that produces the sealing composition.

21. The method of claim 20, wherein the fluid loss opening comprises an opening in cement disposed in a wellbore annulus of the well.

22. The method of claim 20, comprising:

heating the sealing composition in a heating chamber and converting the sealing composition to the gas phase prior to flowing the sealing composition in the gas phase through the fluid loss opening in the well.