A method of chemically sealing the rock surrounding a fracture in a subterranean formation

Abstract

The present application relates to a sealing method for sealing the rock voids around the formation cracks, which forms solid substances in the rock voids around the formation cracks by means of chemical reaction to seal, thereby solving the sealing of the rock voids around the formation cracks without affecting the opening and closing of the formation cracks. Moreover, the present application can greatly expand the applicable scenarios of using the formation cracks to store high-pressure fluids, such as high-permeability sandstone, which can also be used as a carrier for storing high-pressure fluids after being sealed by chemical sealing, greatly reducing the constraints of geological conditions on underground energy storage and deep burial of harmful waste.

Description

Technical Field

[0001] This application belongs to the field of underground energy storage and underground deep burial technology for hazardous waste, specifically involving a method for chemically sealing the rock surrounding geological fissures. Background Technology

[0002] Formation fractures can be used for energy storage, such as by injecting high-pressure fluids (air or water) into them. Formation fractures can also be used to store hazardous waste; for example, Oak Ridge National Laboratory in the United States has for decades injected radioactive fluid waste into artificial formation fractures in shale formations for permanent preservation.

[0003] The condition for high-pressure fluids to be stored long-term in formation fractures is that the fluid will not be lost into the pores of the surrounding rock during the storage process. Therefore, sealing the rock around the formation fractures and reducing the rock permeability is key to preventing fluid loss.

[0004] Currently, rock permeability can be reduced by injecting chemical agents into the rock formation. For example, chemical agents can penetrate the rock's interior, causing a chemical reaction that generates minerals, thus reducing permeability. Another method is to inject reinforcing materials such as polymers into natural fissures or pores in the rock to fill defects and reduce overall permeability. However, these methods either require treating the entire rock formation, which is extremely costly, or while reducing permeability, they may seal existing formation fissures, necessitating the creation of new fissures to store high-pressure fluids.

[0005] Another method involves injecting a fluid into the formation fractures that can react with the original formation fluid to generate precipitates and block the rock pores. However, this method is limited by the high requirements for the composition of the original formation fluid (for example, it needs to contain calcium ions, magnesium ions, etc., and the ion concentration must reach a certain threshold), and it is not suitable for all formations.

[0006] In view of this, there is an urgent need for a method that can seal the rock around the formation fractures, reduce the rock permeability, and does not require the original formation fluids, nor does it seal the fractures themselves. Summary of the Invention

[0007] To address the aforementioned technical problems, this invention presents a method for chemically sealing rocks surrounding formation fractures. This method not only effectively reduces rock permeability without requiring the original fluids in the formation, but also greatly expands the applicable scenarios for storing high-pressure fluids in formation fractures, allowing it to be used in formations with low permeability as in existing technologies.

[0008] The first aspect of this invention discloses a method for chemically sealing rocks surrounding formation fractures, comprising the following steps:

[0009] S1, inject fracturing fluid into the target wellbore to carry out hydraulic fracturing operations, creating formation fractures and / or opening existing formation fractures;

[0010] The fracturing fluid contains a plugging material capable of solidification or gelation to chemically seal the rock voids and / or microfractures surrounding the formation fractures after the fracturing fluid enters the formation fractures.

[0011] In one embodiment, the plugging material comprises at least one main agent and at least one crosslinking agent or curing agent capable of curing or gelling with the main agent to chemically seal rock voids and / or microfractures surrounding formation fractures; or, the plugging material is configured to contact the original fluid within the rock voids and / or microfractures surrounding formation fractures to undergo curing or gelling.

[0012] Based on the aforementioned embodiments, further, after the step of injecting fracturing fluid, the method further includes injecting displacement fluid into the target wellbore to drive the fracturing fluid in the target wellbore into the formation fracture; the ratio of the viscosity of the fracturing fluid to the viscosity of the displacement fluid does not exceed 10; and the density of the fracturing fluid is not less than 70% of the density of the displacement fluid.

[0013] Furthermore, in another embodiment, step S1 includes the step of sequentially and separately injecting fracturing fluid and subsequent fluid into the target wellbore, wherein the subsequent fluid is either subsequent fracturing fluid or subsequent additional fluid.

[0014] The fracturing fluid and the subsequent fluid each contain different plugging materials, and can undergo a solidification or gelation reaction upon contact; or, the plugging material is configured to undergo a solidification or gelation reaction based on its own temperature increase; the subsequent fluid is configured as a high-temperature fluid, so that the plugging material in the fracturing fluid undergoes a solidification or gelation reaction; or, the plugging material is configured to undergo a solidification or gelation reaction based on pH changes, the fracturing fluid and the subsequent fluid each contain plugging materials with different pH values, and solidify or gel due to pH changes upon contact; or, the plugging material is configured to undergo a solidification or gelation reaction based on salinity changes, the fracturing fluid and the subsequent fluid each contain plugging materials with different salinities, and solidify or gel due to salinity changes upon contact.

[0015] Based on the aforementioned additional embodiments, further, after the step of injecting fracturing fluid and before the step of injecting subsequent fluid, a release fluid is injected to prevent the two fluids from prematurely contacting and reacting; in the fracturing fluid, release fluid, and subsequent fluid, the ratio of the viscosity of the first injected fluid to the viscosity of the subsequently injected fluid does not exceed 10; in the fracturing fluid, release fluid, and subsequent fluid, the density of the first injected fluid is not less than 70% of the density of the subsequently injected fluid.

[0016] Based on all the foregoing embodiments, the plugging material is further described as a liquid plugging material, which is added directly to the fluid; or, the plugging material in the fluid is at least partially added to the fluid in a manner encapsulated in a biodegradable capsule, and the plugging material can be a solid or liquid plugging material.

[0017] A second aspect of the present invention discloses another method for chemically sealing rocks surrounding formation fractures, comprising the following steps:

[0018] S1, inject fracturing fluid into the target wellbore to carry out hydraulic fracturing operations, creating formation fractures and / or opening existing formation fractures;

[0019] S2, inject sealing fluid into the formation fracture;

[0020] The sealing fluid contains a plugging substance capable of solidification or gelation to chemically seal the rock voids and / or microfractures surrounding the formation fractures after the sealing fluid enters the formation fractures.

[0021] In one embodiment, the plugging material includes at least one main agent and at least one crosslinking agent or curing agent capable of curing or gelling with the main agent to chemically seal rock voids and / or microfractures around formation fractures.

[0022] Based on the aforementioned embodiments, further, after the step of injecting the plugging fluid, a displacement fluid is injected into the target wellbore to drive the plugging fluid in the target wellbore into the formation fracture; the ratio of the viscosity of the plugging fluid to the viscosity of the displacement fluid does not exceed 10; the density of the plugging fluid is not less than 70% of the density of the displacement fluid.

[0023] In one embodiment, the plugging material is configured to undergo a solidification or gelation reaction based on its own temperature rise, and the fracturing fluid in step S1 is configured to be a high-temperature fluid, so that the plugging material in the sealing fluid undergoes a solidification or gelation reaction.

[0024] In another embodiment, step S2 includes sequentially injecting a pre-sealing fluid and a post-sealing fluid into the target wellbore; the pre-sealing fluid and the post-sealing fluid each contain different plugging substances and are capable of solidification or gelation upon contact; or, the plugging substance is configured to solidify or gel based on its own temperature increase; one of the pre-sealing fluid and the post-sealing fluid contains a plugging substance, while the other is a high-temperature fluid, so that the plugging substance solidifies or gels. The sealing material is configured to undergo a curing or gelling reaction based on pH changes, wherein the initial sealing fluid and the subsequent sealing fluid each contain sealing materials with different pH values, and the sealing material undergoes a curing or gelling reaction due to pH changes upon contact with each other; or, the sealing material is configured to undergo a curing or gelling reaction based on salinity changes, wherein the initial sealing fluid and the subsequent sealing fluid each contain sealing materials with different salinities, and the sealing material undergoes a curing or gelling reaction due to salinity changes upon contact with each other.

[0025] Building upon the aforementioned additional embodiments, further, after the step of injecting the pre-sealing fluid and before the step of injecting the subsequent sealing fluid, an isolation fluid capable of preventing premature contact and reaction between the two fluids is injected; among the pre-sealing fluid, the isolation fluid, and the subsequent sealing fluid, the ratio of the viscosity of the pre-injected fluid to the viscosity of the subsequent injected fluid does not exceed 10; among the pre-sealing fluid, the isolation fluid, and the subsequent sealing fluid, the density of the pre-injected fluid is not less than 70% of the density of the subsequent injected fluid; the injection flow rates of the isolation fluid and the subsequent sealing fluid must be lower than a threshold flow rate, which is determined by comparing whether the calculated Reynolds number obtained from the pre-sealing fluid, the subsequent sealing fluid, and the isolation fluid satisfies the critical value for turbulence.

[0026] Based on the aforementioned other embodiments, further, after the injection of the first sealing fluid, the formation fracture is judged to be closed by monitoring whether the bottom hole pressure is less than the fracture closure pressure. After the formation fracture is judged to be closed, it is determined that the first sealing fluid in the formation fracture has been filtered out into the formation, and then the work of injecting the second sealing fluid is started; or, the first sealing fluid is backflowed and drained until the formation fracture is closed, and then the second sealing fluid is injected.

[0027] Based on all embodiments disclosed in the second aspect above, wherein the plugging material is a liquid plugging material and is added directly to the fluid; or, the plugging material in the fluid is added at least partially in a manner encapsulated in a biodegradable capsule, and the plugging material can be a solid or liquid plugging material.

[0028] Beneficial effects: Storing high-pressure fluids using formation fractures requires extremely low permeability of the surrounding rocks. Therefore, current applications are limited to low-permeability strata (such as shale and granite). The method of chemically sealing the rocks surrounding formation fractures proposed in this invention can greatly expand the applicable scenarios for storing high-pressure fluids using formation fractures. For example, high-permeability sandstone can also be used as a carrier for storing high-pressure fluids after chemical sealing, greatly reducing the constraints of geological conditions on the selection of underground energy storage and deep underground burial sites for hazardous wastes.

[0029] The method and system for chemically sealing rock around formation fractures according to the present invention are disclosed in detail below with reference to the embodiments shown in the accompanying drawings and the reference numerals. Attached Figure Description

[0030] Figure 1 A flowchart illustrating the steps of a method for chemically sealing rock around a formation fracture, as disclosed in the first aspect of the present invention, is shown.

[0031] Figure 2 A flowchart illustrating the steps of a method for chemically sealing rock around a formation fracture, as disclosed in the second aspect of the present invention, is shown. Detailed Implementation

[0032] It should be noted that the term "liquid fluid" in this article can be, but is not limited to, liquids, emulsions, slurries, and solid particle flows with flow characteristics similar to those of liquids; while the term "fluid" in this article can be, but is not limited to, gases, liquids, emulsions, slurries, and solid particle flows with flow characteristics similar to those of liquids.

[0033] In this article, "strata" refers to porous and permeable rock formations underground (e.g., shale, sandstone, carbonate, hot dry rock, etc.) that can serve as storage spaces for fluids. These fluids can typically be water, hydrocarbons, or gases.

[0034] In this article, "hydraulic fracturing" or "fracture" refers to the formation and propagation of cracks in rock formations under the influence of external forces (such as high-pressure fluids).

[0035] In this article, "formation fracture" or "fracture" refers to rock openings or fissures created within the formation after hydraulic fracturing operations, or natural fractures or fault fractures that already exist in the formation. The terms "formation fracture" and "fracture" are used interchangeably. "Fractured" can refer to a single fracture, or multiple fractures or fracture swarms located at the same location.

[0036] In this article, "wellbore" refers to a hole formed by drilling or inserting a guide pipe into the formation. Generally, wellbores are cylindrical, and therefore their cross-section may be circular. Alternatively, wellbores may have any other cross-section. Wellbores can be open-hole (open-hole wellbore) or casing wellbores (cased wellbore) with a cemented casing bonded to the inner wall. Wellbores can be vertical, horizontal, or inclined.

[0037] The technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings and the above-mentioned definitions. Obviously, the described embodiments are only a part of the embodiments of the present invention, and not all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those of ordinary skill in the art without creative effort are within the scope of protection of the present invention.

[0038] It should be noted that, unless otherwise specified, the embodiments and features described in this application can be combined with each other.

[0039] Figure 1 A flowchart illustrating the steps of a method for chemically sealing rock surrounding formation fractures, as disclosed in the first aspect of this invention, is shown. (Combined with...) Figure 1 As shown, this invention discloses a method for chemically sealing a pair of rock fractures in a formation, comprising the following steps:

[0040] S1, inject fracturing fluid into the target wellbore to perform hydraulic fracturing to create formation fractures and / or open existing formation fractures; wherein the fracturing fluid contains plugging materials that can undergo solidification or gelation reactions to chemically seal the rock voids and / or microfractures around the formation fractures after the fracturing fluid enters the formation fractures.

[0041] That is, in the method disclosed in the first aspect of this invention, the chemical sealing work is completed simultaneously with the hydraulic fracturing operation. In other words, while hydraulic fracturing using fracturing fluid creates formation fractures, the surrounding rock pores and / or microfractures are simultaneously chemically sealed. In other words, in the method disclosed in the first aspect of this invention, the formation fracture creation step based on hydraulic fracturing simultaneously completes the dual tasks of generating or opening formation fractures and chemically sealing the surrounding rock pores and / or microfractures.

[0042] In step S1, the target wellbore can be a new energy storage wellbore or an abandoned wellbore. The wellbore can be a vertical well or a horizontal well. Multiple formation fractures can also be created at different locations within the wellbore.

[0043] In addition, a curing reaction is a reaction that can produce a solid, such as the reaction of epoxy resin and curing agent to produce a solid, or it can refer to a reaction that can produce a precipitate, such as the reaction of sodium chloride liquid and calcium carbonate liquid to produce a precipitate; a gelling reaction is a reaction that produces a colloid.

[0044] Specifically, the plugging material can be configured to chemically seal the rock pores and / or microfractures around the formation fractures by solidification or gelation reactions between its own components, or by solidification or gelation reactions between different liquid plugging materials, or by solidification or gelation reactions by contact with the original fluids in the rock pores and / or microfractures around the formation fractures, or by solidification or gelation reactions by changes in salinity, pH or temperature after entering the formation.

[0045] It should be noted that any substance that can trigger a chemical reaction to form a solid under certain conditions can be called a leak-sealing substance. This condition also applies to all embodiments of this invention.

[0046] The following describes the process of simultaneously performing chemical sealing of fractures during hydraulic fracturing, using specific examples.

[0047] Example 1

[0048] The fracturing fluid serves as the sole working fluid, and its plugging material includes at least one main agent and at least one crosslinking agent or curing agent capable of solidifying or gelling with the main agent to chemically seal the rock pores and / or microfractures surrounding the formation fractures. In this embodiment, the fracturing fluid alone can chemically seal the rock pores and / or microfractures surrounding the formation fractures simultaneously with hydraulic fracturing operations.

[0049] For example, polyacrylamide is used as the main plugging agent, while chromium salts and zirconium salts act as crosslinking / curing agents. The plugging agent is a liquid when injected into the wellbore, and it gels / cures after entering the formation to form a three-dimensional network structure. The complete gelation / curing reaction usually takes tens of minutes to several hours.

[0050] Example 2

[0051] The fracturing fluid is used as the sole working fluid, and the plugging material it contains is designed to contact the original fluid within the rock pores and / or microfractures surrounding the formation fractures, causing a solidification or gelation reaction. In this embodiment, the fracturing fluid alone can chemically seal the rock pores and / or microfractures surrounding the formation fractures simultaneously with hydraulic fracturing operations.

[0052] The term "original fluid" refers to the primordial fluid already present in the rock pores and / or microfractures surrounding the formation fractures before the injection of fracturing fluid. The chemical properties of the original fluid can be obtained in advance, which is existing technology and will not be elaborated upon here. Based on the pre-obtained chemical properties of the original fluid, the plugging material in the fracturing fluid is selectively configured to allow it to contact the original fluid in the rock pores and / or microfractures surrounding the formation fractures and undergo a solidification or gelation reaction.

[0053] Furthermore, based on the aforementioned Embodiments 1 and 2, after the step of injecting fracturing fluid, a displacement fluid is further injected into the target wellbore to drive the fracturing fluid in the target wellbore into the formation fractures. That is, to prevent the plugging material from gelling / solidifying and clogging the wellbore, a displacement fluid needs to be injected into the wellbore before the plugging material completes its gelling / solidification reaction, driving all the fluid containing the plugging material in the wellbore into the formation fractures. The injection of displacement fluid into the target wellbore is stopped, and the wellhead is sealed, allowing the plugging material to continuously filter out into the formation and complete its gelling / solidification reaction. Any liquid that does not generate solids or chemically react with the plugging material can be used as a displacement fluid. The volume of the injected displacement fluid can be determined by calculating the volume of the wellbore.

[0054] To ensure better displacement of the fracturing fluid by the displacement fluid, avoid viscous fingering, and reduce mixing of the displacement fluid and the fracturing fluid containing plugging material in the wellbore, the viscosity ratio of the fracturing fluid containing plugging material to the viscosity of the displacement fluid should not exceed 10.

[0055] To prevent Rayleigh-Taylor instability caused by density differences between displacement fluid and fracturing fluid containing plugging material in the wellbore, the density of the fracturing fluid must not be less than 70% of the density of the displacement fluid.

[0056] It should be noted that the injection of displacement fluid is only applicable to cases where a single fluid (such as the fracturing fluid mentioned above, and the plugging fluid mentioned below) is used to form a seal. This is because, when using a single fluid, although the injected fluid is in a liquid state, it has already begun to undergo a solidification or gelation reaction, and it usually takes several tens of minutes or more to become solid. In this case, injecting displacement fluid can help inject the plugging fluid into the fracture. It is not applicable to cases where different plugging fluids are injected sequentially, because solidification or gelation reactions will not occur in the wellbore when different plugging fluids are injected sequentially.

[0057] Example 3

[0058] Step S1 includes the steps of sequentially injecting fracturing fluid and subsequent fluid into the target wellbore, wherein the subsequent fluid is either the subsequent fracturing fluid or a subsequent additional fluid; that is, the subsequent fluid can be either the fracturing fluid used for fracturing or an additional fluid not used for fracturing.

[0059] In this embodiment, the fracturing fluid and the subsequent fluid each contain different plugging materials, and they can undergo a solidification or gelation reaction upon contact. That is, the fracturing fluid contains a first plugging material, while the subsequent fluid contains a second plugging material; the two plugging materials are different but can undergo a solidification or gelation reaction upon contact.

[0060] For example, the plugging material can be one or more metal cations, such as calcium ions, magnesium ions, aluminum ions, iron ions, etc. When the fracturing fluid used as the plugging fluid is injected into the formation fracture, the metal cations can diffuse into the rock pores around the fracture. Then, a subsequent fluid that can chemically react with the metal cations to generate solid precipitates is injected into the formation fracture.

[0061] Example 4

[0062] Step S1 includes the sequential injection of fracturing fluid and subsequent fluid into the target wellbore, wherein the subsequent fluid is either the subsequent fracturing fluid or a subsequent additional fluid; the plugging material is configured to undergo a solidification or gelation reaction based on its own temperature rise; the subsequent fluid is configured to be a high-temperature fluid, so that the plugging material in the fracturing fluid undergoes a solidification or gelation reaction.

[0063] In other words, a separate fluid, independent of the fracturing fluid, is injected into the formation fractures. The fracturing fluid contains plugging material, while the other fluid is a high-temperature fluid. The fracturing fluid containing the plugging material can fuse and come into contact with the high-temperature fluid, causing the plugging material to solidify or colloid upon heating, thus achieving chemical sealing. For example, high-temperature water can be used as the other fluid, while a room-temperature liquid containing zinc chloride can be used as the fracturing fluid. When they come into contact, the temperature of the fracturing fluid rises, resulting in the formation of zinc hydroxide solid precipitate.

[0064] Example 5

[0065] Step S1 includes the sequential injection of fracturing fluid and subsequent fluid into the target wellbore, wherein the subsequent fluid is either the subsequent fracturing fluid or a subsequent additional fluid; the plugging material is configured to undergo a solidification or gelation reaction based on pH changes, and the fracturing fluid and subsequent fluid each contain plugging materials with different pH values, and undergo a solidification or gelation reaction due to pH changes after they come into contact with each other.

[0066] Specifically, the fracturing fluid contains a first pH value plugging material, while the subsequent fluid contains a second pH value plugging material. First, hydraulic fracturing is performed using the fracturing fluid. At this time, the first pH value plugging material diffuses into the rock pores around the fracture. Then, the subsequent fluid with the second pH value is injected into the formation fracture. After the fracturing fluid and the subsequent fluid come into contact, the pH value changes, thereby forming a fixed structure and achieving chemical sealing.

[0067] Example 6

[0068] Step S1 includes the sequential injection of fracturing fluid and subsequent fluid into the target wellbore, wherein the subsequent fluid is either the subsequent fracturing fluid or a subsequent additional fluid; the plugging material is configured to undergo a solidification or gelation reaction based on salinity changes, and the fracturing fluid and subsequent fluid each contain plugging materials with different salinities, and upon contact with each other, they undergo a solidification or gelation reaction due to salinity changes (for example, the fracturing fluid contains barium nitrate, and the subsequent fluid contains sulfate, which can generate barium sulfate upon contact).

[0069] In Examples 3 to 6, since the fracturing fluid containing plugging material and the subsequent fluid containing or not containing plugging material can be injected into the formation fractures in batches, the premature occurrence or completion of chemical reaction of the liquid plugging material can be better avoided.

[0070] Furthermore, based on the aforementioned Examples 3 to 6, after the injection of the fracturing fluid and before the injection of the subsequent fluid, a spacer fluid is injected to prevent premature contact and reaction between the two fluids. By injecting the spacer fluid, premature contact and chemical reaction between the fracturing fluid and the subsequent fluid in the wellbore can be prevented. The spacer fluid can be any liquid that does not chemically react with either the fracturing fluid or the subsequent fluid.

[0071] To prevent viscous fingering, the viscosity ratio of the first injected fluid to the subsequent injected fluid in the fracturing fluid, the spacer fluid, and the subsequent fluid should not exceed 10.

[0072] In some embodiments, in order to prevent Rayleigh-Taylor instability and stratification in formation fractures caused by density differences between the isolation fluid and fracturing fluid in the wellbore, the density of the first-injected fluid is not less than 70% of the density of the second-injected fluid in the fracturing fluid, isolation fluid, and subsequent fluid.

[0073] In this embodiment, to prevent turbulence in the wellbore or formation fractures due to excessive flow rates of the fracturing fluid, post-fracturing fluid, and isolation fluid during injection, which could lead to mixing of different liquids, the flow rates of the injected isolation fluid and post-fracturing fluid need to be below a threshold flow rate. The threshold flow rate can be calculated using empirical formulas, theoretical models, or numerical simulations based on information such as the hydrodynamic properties of the fracturing fluid, post-fracturing fluid, and isolation fluid, wellbore and fracture dimensions, and wellbore and fracture surface roughness. For example, the threshold flow rate can be determined by comparing whether the calculated Reynolds number meets the critical value for turbulence.

[0074] In addition, based on the aforementioned Examples 1 to 6, the plugging material is a liquid plugging material and is added directly to the fluid; or, the plugging material in the fluid is at least partially added to the fluid in a manner encapsulated in a biodegradable capsule, and the plugging material can be a solid or liquid plugging material.

[0075] In some cases, the chemical reaction rate of the different components of the plugging material is too fast, posing a risk of wellbore blockage. Alternatively, different fluids may be difficult to match in terms of density or viscosity with the isolation fluid, or the isolation fluid may infiltrate formation pores and hinder the chemical reaction between the different fluids. Therefore, a method is used to inject the plugging material into formation fractures by encapsulating it in biodegradable (also referring to soluble) capsules (referring to containers of any shape that can store liquids or powders). After the capsules degrade, the released plugging material can undergo chemical reactions with each other and / or with the injected fluids, generating solids or colloids that chemically seal the rock pores and / or microfractures surrounding the formation fractures.

[0076] The biodegradable capsule can be made of materials such as water-soluble polymers, biodegradable polylactic acid films, and soluble carboxymethyl cellulose. The material ratio of the capsule can be selected according to the formation temperature and construction time, and the degradation time of the capsule can be designed. In some embodiments, the capsule will degrade within 30 to 60 minutes after contact with water, thereby allowing the reactants inside the capsule to be released from the capsule within 30 to 60 minutes after entering the formation.

[0077] In one specific implementation, in conjunction with Example 1, the fracturing fluid is configured as a fluid containing biodegradable capsules. The biodegradable capsules contain plugging material, which, after being released from the capsules after degradation, undergoes chemical reactions with each other and / or with other components of the fracturing fluid to generate solids or colloids, thereby chemically sealing the rock voids and / or microfractures around the formation fractures.

[0078] In one specific implementation, in conjunction with Example 2, the fracturing fluid is configured as a fluid containing biodegradable capsules. The biodegradable capsules contain plugging material. After the capsules degrade, the plugging material released reacts chemically with the original fluid in the rock fissures surrounding the formation to generate solids or colloids, which chemically seal the rock voids and / or microfractures around the formation fissures.

[0079] In one specific embodiment, in conjunction with Embodiments 3, 5 and 6, both the fracturing fluid and / or the post-fracturing fluid contain biodegradable capsules, and the biodegradable capsules contain at least one plugging material; after the capsules degrade, the plugging material released reacts chemically with the components in the fracturing fluid to generate a solid or colloid, which chemically seals the rock voids and / or microfractures around the formation fractures.

[0080] In one specific embodiment, in conjunction with Embodiment 4, the fracturing fluid is configured as a fluid containing biodegradable capsules, wherein the biodegradable capsules contain plugging material. After the capsules degrade, the plugging material released is converted into a solid or colloid due to the high temperature of the subsequent fluid, thereby chemically sealing the rock voids and / or microfractures around the formation fractures.

[0081] Furthermore, based on the aforementioned embodiments three to six, after the fracturing fluid is injected, the closure of the formation fracture is determined by monitoring whether the bottom hole pressure is less than the fracture closure pressure. If the formation fracture is determined to be closed, it is determined that the fracturing fluid within the formation fracture has been filtered out into the formation, and then the injection of subsequent fluids is initiated; alternatively, the fracturing fluid is backflowed until the formation fracture is closed before injecting subsequent fluids. This is to avoid chemical reactions between the initial fracturing fluid and subsequent fluids during their migration within the fracture. Fluids containing plugging material and other fluids need to be injected into the formation fracture separately. That is, the well needs to be shut in to wait for all fluids containing plugging material to be filtered out into the formation before injecting other fluids, or the well needs to be shut in to wait for all other fluids to be filtered out into the formation before injecting fluids containing plugging material.

[0082] A second aspect of the present invention discloses another method for chemically sealing rocks surrounding formation fractures, comprising the following steps:

[0083] S1, inject fracturing fluid into the target wellbore to carry out hydraulic fracturing operations, creating formation fractures and / or opening existing formation fractures;

[0084] S2, inject sealing fluid into the formation fracture;

[0085] The sealing fluid contains a plugging substance capable of solidification or gelation to chemically seal the rock voids and / or microfractures surrounding the formation fractures after the sealing fluid enters the formation fractures.

[0086] The interpretations of "target wellbore," "solidification reaction," and "plugging material" mentioned in the method disclosed in the first aspect of this invention also apply to the method disclosed in the second aspect of this invention, and will not be repeated here.

[0087] By introducing a plugging fluid for chemical sealing after fracturing, the following advantages are achieved: Due to the filtration of fracturing fluid during fracturing, the original fluids (including formation mineral cations) in the rock pores surrounding the fracture have been displaced to a distance. That is, the rock pores around the fracture are now filled with fracturing fluid. When the plugging fluid containing the plugging material enters the fracture, the plugging material will no longer react chemically with the original fluids (including formation mineral cations) in the rock pores. In other words, this avoids chemical reactions between the plugging material and the original fluids or substances in the rock pores.

[0088] The process of achieving chemical blocking based on the method disclosed in the second aspect of the present invention will be described below with reference to specific embodiments.

[0089] Example 7

[0090] The sealing fluid serves as the sole sealing working fluid, containing at least one main agent and at least one crosslinking agent or curing agent capable of curing or gelling with the main agent to chemically seal the rock voids and / or microfractures surrounding formation fractures. In this embodiment, the sealing fluid itself is sufficient to chemically seal the rock voids and / or microfractures surrounding formation fractures after hydraulic fracturing. Similarly, for example, polyacrylamide is used as the main sealing agent, and chromium salts, zirconium salts, etc., are used as crosslinking agents / curing agents.

[0091] Building upon this embodiment, further, after the injection of the plugging fluid, a displacement fluid is injected into the target wellbore to drive the plugging fluid in the target wellbore into the formation fractures; that is, to prevent the plugging material from gelling / solidifying and clogging the wellbore, a displacement fluid needs to be injected into the wellbore before the plugging material completes its gelling / solidification reaction, displacing all the fluid containing the plugging material in the wellbore into the formation fractures. The injection of displacement fluid into the target wellbore is stopped, and the wellhead is sealed, allowing the plugging material to continuously filter out into the formation and complete its gelling / solidification reaction. Any liquid that does not generate solids or chemically react with the plugging material can be used as a displacement fluid. The volume of the injected displacement fluid can be determined by calculating the volume of the wellbore.

[0092] To ensure that the displacement fluid has a better displacing effect on the plugging fluid, avoid viscous fingering, and reduce the mixing of the displacement fluid and the fracturing fluid containing plugging material in the wellbore, the viscosity ratio of the plugging fluid to the displacement fluid should not exceed 10.

[0093] To prevent Rayleigh-Taylor instability caused by density differences between the displacement fluid and the plugging fluid containing plugging material in the wellbore, the density of the plugging fluid must not be less than 70% of the density of the displacement fluid.

[0094] Similarly, in the method provided in the second aspect of the present invention, the injection of displacement fluid is only applicable to the case where plugging is formed based on a single fluid (such as the fracturing fluid mentioned above and the plugging fluid mentioned below), for the same reasons as those mentioned in the method disclosed in the first aspect above, and will not be repeated here.

[0095] Example 8

[0096] The plugging material is configured to undergo a solidification or gelation reaction based on its own temperature rise, and the fracturing fluid in step S1 is configured to be a high-temperature fluid, so that the plugging material in the sealing fluid undergoes a solidification or gelation reaction.

[0097] That is, by utilizing the fracturing fluid, which is a high-temperature liquid, the plugging material undergoes a solidification or gelation reaction. This allows for a close integration of steps S1 and S2. The fracturing fluid in step S1 no longer simply functions as a fracturing fluid but also participates in the chemical plugging process of step S2. Furthermore, because the fracturing fluid is a high-temperature liquid, the addition of another high-temperature liquid in or after step S2 to further solidify or gel the plugging material significantly saves time and reduces costs.

[0098] Specifically, the fracturing fluid is a high-temperature water fluid, while the room-temperature liquid containing zinc chloride can be used as a plugging fluid. When the two come into contact, the temperature of the plugging fluid rises, thereby generating a solid precipitate of zinc hydroxide.

[0099] Example 9

[0100] Step S2 includes the step of sequentially injecting a first-sealing fluid and a second-sealing fluid into the target wellbore; the first-sealing fluid and the second-sealing fluid contain different plugging substances and can undergo a solidification or gelation reaction after contacting each other;

[0101] In this embodiment, the initial sealing fluid and the subsequent sealing fluid each contain different sealing substances, and they can undergo a curing or gelation reaction upon contact. That is, the initial sealing fluid contains a first sealing substance, while the subsequent sealing fluid contains a second sealing substance. The two sealing substances are different but can undergo a curing or gelation reaction upon contact.

[0102] For example, the plugging material can be one or more metal cations, such as calcium ions, magnesium ions, aluminum ions, iron ions, etc. After the first plugging fluid is injected into the formation fracture, the metal cations can diffuse into the rock pores around the fracture. Then, a second plugging fluid that can chemically react with the metal cations to generate solid precipitates is injected into the formation fracture.

[0103] Example 10

[0104] Step S2 includes the step of sequentially injecting a first-sealing fluid and a second-sealing fluid into the target wellbore; the plugging material is configured to be a substance capable of solidifying or gelling based on its own temperature rise; one of the first-sealing fluid and the second-sealing fluid contains the plugging material, while the other is a high-temperature fluid, so that the plugging material can undergo a solidification or gelling reaction.

[0105] That is, a secondary sealing fluid, independent of the primary sealing fluid, is injected into the formation fracture. The primary sealing fluid contains plugging material, while the secondary sealing fluid is a high-temperature fluid. Upon contact and fusion with the high-temperature fluid, the primary sealing fluid containing plugging material heats up, causing the plugging material to solidify or colloid, thus achieving chemical sealing. For example, high-temperature water can be used as the secondary sealing fluid, while a room-temperature liquid containing zinc chloride can be used as the primary sealing fluid. When they come into contact, the temperature of the fracturing fluid rises, resulting in the formation of zinc hydroxide solid precipitate.

[0106] Example 11

[0107] Step S2 includes the step of sequentially injecting the first sealing fluid and the second sealing fluid into the target wellbore; the plugging material is set as a substance that can undergo a solidification or gelation reaction based on pH changes, and the first sealing fluid and the second sealing fluid contain plugging materials with different pH values, and they undergo a solidification or gelation reaction due to pH changes after they come into contact with each other.

[0108] Specifically, the first sealing fluid contains a first pH value plugging material, while the second sealing fluid contains a second pH value plugging material. The first sealing fluid is first injected into the formation fracture, and the first pH value plugging material diffuses into the pores of the rock around the fracture. Then, the second sealing fluid with the second pH value is injected into the formation fracture. After the first sealing fluid and the second sealing fluid come into contact, the pH value changes, thereby forming a fixed substance and achieving chemical sealing.

[0109] Example 12

[0110] Step S2 includes the sequential injection of a first-stage sealing fluid and a second-stage sealing fluid into the target wellbore. The plugging material is configured to undergo a solidification or gelation reaction based on salinity changes. The first-stage and second-stage sealing fluids contain plugging materials with different salinities, and they undergo a solidification or gelation reaction due to salinity changes after contact with each other.

[0111] Similarly, in Examples 9 to 12, since the first sealing fluid containing plugging material and the subsequent sealing fluid containing or not containing plugging material can be injected into the formation fractures in batches, the premature occurrence or completion of chemical reaction of the liquid plugging material can be better avoided.

[0112] Based on the aforementioned embodiments eight to twelve, after the step of injecting the prior sealing fluid and before the step of injecting the subsequent sealing fluid, a separatory fluid is injected to prevent premature contact and reaction between the two fluids. By injecting the separatory fluid, premature contact and chemical reaction between the prior and subsequent sealing fluids in the wellbore can be prevented. The separatory fluid can be any liquid that does not chemically react with either the prior or subsequent sealing fluid.

[0113] To prevent viscous fingering, the ratio of the viscosity of the first injected fluid to the viscosity of the subsequently injected fluid in the prior sealing fluid, the isolation fluid, and the subsequent sealing fluid shall not exceed 10.

[0114] To prevent Rayleigh-Taylor instability and stratification in formation fractures caused by density differences between the isolation fluid and the pre-plugging fluid in the wellbore, the density of the pre-injected fluid shall not be less than 70% of the density of the post-injected fluid.

[0115] Additionally, the injection flow rates of the isolation fluid and the subsequent sealing fluid must be lower than a threshold flow rate, which is determined by comparing the calculated Reynolds number obtained from the comparison of the initial sealing fluid, the subsequent sealing fluid, and the isolation fluid to see if it meets the critical value for turbulence.

[0116] Based on the aforementioned embodiments eight to twelve, further, after the initial sealing fluid is injected, the closure of the formation fracture is determined by monitoring whether the bottom hole pressure is less than the fracture closure pressure. If the formation fracture is determined to be closed, it is determined that the initial sealing fluid within the formation fracture has been filtered out into the formation, and then the injection of subsequent sealing fluid is initiated; alternatively, the initial sealing fluid is backflowed until the formation fracture is closed, and then subsequent sealing fluid is injected. This is to avoid chemical reactions between the initial and subsequent sealing fluids during their migration within the fracture. Fluids containing plugging material and other fluids need to be injected into the formation fracture separately. That is, the well needs to be shut in to wait for all fluids containing plugging material to be filtered out into the formation before injecting other fluids, or the well needs to be shut in to wait for all other fluids to be filtered out into the formation before injecting fluids containing plugging material.

[0117] Based on all embodiments disclosed in the second aspect above, the plugging material is a liquid plugging material and is added directly to the fluid; or, the plugging material in the fluid is at least partially added to the fluid by being encapsulated in a biodegradable capsule, and the plugging material can be a solid or liquid plugging material. This is because, in some cases, the chemical reaction rate of the different components of the plugging material itself is too fast, posing a risk of wellbore blockage, or the different liquids and fluids are difficult to match in density or viscosity, or the fluid infiltrates the formation pores and hinders the chemical reaction of the different liquids. By injecting the plugging material into formation fractures in biodegradable (also referring to soluble) capsules (referring to containers of any shape that can store liquids or powders), after the capsules degrade, the released plugging material can initiate chemical reactions between itself and / or between itself and the fluid injected into the formation to generate solids or colloids, thereby chemically sealing the rock pores and / or microfractures around the formation fractures.

[0118] Similarly, the biodegradable capsule can be made of materials such as water-soluble polymers, biodegradable polylactic acid films, and soluble carboxymethyl cellulose. The material ratio of the capsule can be selected according to the formation temperature and construction time, and the degradation time of the capsule can be designed. In some embodiments, the capsule will degrade within 30 to 60 minutes after contact with water, thereby allowing the reactants inside the capsule to be released from the capsule within 30 to 60 minutes after entering the formation.

[0119] In the methods disclosed in the first and second aspects of this invention, the plugging material in the biodegradable capsule can be in a liquid or solid state (including powder), and the biodegradable capsule may also contain other substances to adjust the capsule density. Furthermore, in some embodiments, different plugging materials may be contained in the same biodegradable capsule; in other embodiments, different plugging materials may be contained in different biodegradable capsules. For example, a powdered polymer and a powdered curing agent will not undergo a curing reaction when placed in the same capsule, but after the capsule is injected into a formation fracture, the polymer powder and curing agent powder released during degradation can undergo a curing reaction upon contact with water.

[0120] In one specific embodiment, in conjunction with the aforementioned Embodiment Seven, the sealing fluid is configured as a fluid containing biodegradable capsules, wherein the biodegradable capsules contain plugging substances, and the plugging substances released after the capsules degrade undergo chemical reactions with each other and / or with other components of the sealing fluid to generate solids or colloids, thereby chemically sealing the rock voids and / or microfractures around the formation fractures.

[0121] In one specific implementation, in conjunction with Example 8, the sealing fluid is configured as a fluid containing biodegradable capsules, wherein the biodegradable capsules contain plugging material. After the capsules degrade, the plugging material released is converted into a solid or colloid by the high temperature of the fracturing fluid, thereby chemically sealing the rock voids and / or microfractures around the formation fractures.

[0122] In one specific embodiment, in conjunction with Embodiment 10, the initial sealing fluid is configured as a fluid containing biodegradable capsules, wherein the biodegradable capsules contain a plugging material. After the capsules degrade, the plugging material released is converted into a solid or colloid due to the high temperature of the subsequent sealing fluid, thereby chemically sealing the rock voids and / or microfractures around the formation fractures.

[0123] In one specific embodiment, in conjunction with Embodiments 9, 11, and 12, a biodegradable capsule is present in the pre-sealing fluid and / or the post-sealing fluid, and the biodegradable capsule contains at least one plugging material; after the capsule degrades, the plugging material released reacts chemically with the components in the sealing fluid to generate a solid or colloid, thereby chemically sealing the rock voids and / or microfractures around the formation fractures.

[0124] In addition, it should be particularly emphasized that in this invention, by using displacement fluid or isolation fluid or injecting liquid fluid containing plugging material in batches, the solidification reaction only occurs in the pores around the cracks and does not seal the formation cracks.

[0125] For ease of description, spatial relative terms such as "above," "on top of," "on the upper surface of," "above," etc., are used herein to describe the spatial positional relationship of a device or feature as shown in the figures to other devices or features. It should be understood that spatial relative terms are intended to encompass different orientations in use or operation beyond the orientation of the device as described in the figures. For example, if the device in the figures were inverted, a device described as "above" or "on top of" other devices or structures would subsequently be positioned as "below" or "under" other devices or structures. Thus, the exemplary term "above" can include both "above" and "below." The device may also be positioned in other different ways (rotated 90 degrees or in other orientations), and the spatial relative descriptions used herein will be interpreted accordingly.

[0126] It should be noted that the terminology used herein is for the purpose of describing particular embodiments only and is not intended to limit the exemplary embodiments according to this application. As used herein, the singular form is intended to include the plural form as well, unless the context clearly indicates otherwise. Furthermore, it should be understood that when the terms "comprising" and / or "including" are used in this specification, they indicate the presence of features, steps, operations, devices, components, and / or combinations thereof.

[0127] It should be noted that the terms "first," "second," etc., in the specification, claims, and accompanying drawings of this application are used to distinguish similar objects and are not necessarily used to describe a specific order or sequence. It should be understood that such data can be interchanged where appropriate so that the embodiments of this application described herein can be implemented, for example, in orders other than those illustrated or described herein. Furthermore, the terms "comprising" and "having," and any variations thereof, are intended to cover non-exclusive inclusion; for example, a process, method, system, product, or apparatus that comprises a series of steps or units is not necessarily limited to those steps or units explicitly listed, but may include other steps or units not explicitly listed or inherent to such processes, methods, products, or apparatus.

[0128] The above are merely preferred embodiments of the present invention and are not intended to limit the present invention. Various modifications and variations can be made to the present invention by those skilled in the art. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the scope of protection of the present invention.

[0129] Finally, it should be noted that the above embodiments are only used to illustrate the technical solutions of the present invention and are not intended to limit it. Although the present invention has been described in detail with reference to preferred embodiments, those skilled in the art should understand that modifications or equivalent substitutions can be made to the technical solutions of the present invention without departing from the spirit and scope of the technical solutions of the present invention, and all such modifications or substitutions should be covered within the scope of the claims of the present invention.

Claims

1. A method for chemically sealing rock surrounding formation fractures, characterized in that, Includes the following steps: S1, inject fracturing fluid into the target wellbore to carry out hydraulic fracturing operations, creating formation fractures and / or opening existing formation fractures; The fracturing fluid contains a plugging material that can undergo solidification or gelation to chemically seal the rock voids and / or microfractures around the formation fractures after the fracturing fluid enters the formation fractures. Step S1 includes the steps of sequentially injecting fracturing fluid and subsequent fluid into the target wellbore, wherein the subsequent fluid is either the subsequent fracturing fluid or a subsequent additional fluid. The fracturing fluid and the subsequent fluid each contain different plugging materials, and they can undergo solidification or gelation reactions after coming into contact with each other. Alternatively, the plugging material may be configured as a substance capable of solidifying or gelling upon its own temperature rise; and the subsequent fluid may be configured as a high-temperature fluid to cause the plugging material in the fracturing fluid to solidify or gel. Alternatively, the plugging material may be configured as a substance capable of undergoing a curing or gelation reaction based on pH changes, wherein the fracturing fluid and the plugging material in the subsequent fluid each contain different pH values, and undergo a curing or gelation reaction due to pH changes after they come into contact with each other. Alternatively, the plugging material may be configured to undergo a solidification or gelation reaction based on salinity changes, wherein the fracturing fluid and the plugging material in the subsequent fluid each contain different salinities, and solidify or gel due to salinity changes upon contact with each other.

2. The method according to claim 1, characterized in that, The plugging material is a liquid plugging material, which is added directly to the fluid; Alternatively, the plugging material in the fluid may be added to the fluid in at least part by being encapsulated in a biodegradable capsule, and the plugging material may be a solid or liquid plugging material.

3. The method according to claim 1, characterized in that, Following the step of injecting fracturing fluid, the procedure also includes injecting displacement fluid into the target wellbore to drive the fracturing fluid in the target wellbore into the formation fractures. The ratio of the viscosity of the fracturing fluid to the viscosity of the displacement fluid shall not exceed 10; The density of the fracturing fluid must not be less than 70% of the density of the displacement fluid.

4. The method according to claim 1, characterized in that, After the injection of fracturing fluid and before the injection of the subsequent fluid, a release fluid is injected to prevent the two fluids from reacting prematurely. In fracturing fluid, isolation fluid, and subsequent fluid, the ratio of the viscosity of the first injected fluid to the viscosity of the subsequently injected fluid does not exceed 10. In the fracturing fluid, the isolation fluid, and the subsequent fluid, the density of the fluid injected first shall not be less than 70% of the density of the fluid injected later.

5. A method for chemically sealing rock surrounding formation fractures, characterized in that, Includes the following steps: S1, inject fracturing fluid into the target wellbore to carry out hydraulic fracturing operations, creating formation fractures and / or opening existing formation fractures; S2, inject sealing fluid into the formation fracture; The sealing fluid contains a plugging substance capable of solidification or gelation to chemically seal the rock voids and / or microfractures surrounding the formation fractures after the sealing fluid enters the formation fractures. Wherein, the plugging material is configured to undergo a solidification or gelation reaction based on its own temperature rise, and the fracturing fluid in step S1 is configured to be a high-temperature fluid, so that the plugging material in the sealing fluid undergoes a solidification or gelation reaction; or, Step S2 includes sequentially injecting a first-stage sealing fluid and a second-stage sealing fluid into the target wellbore; wherein the first-stage and second-stage sealing fluids each contain different plugging substances and are capable of solidification or gelation upon contact; or, the plugging substances are configured to solidify or gel based on their own temperature rise; one of the first-stage and second-stage sealing fluids contains a plugging substance, while the other is a high-temperature fluid, so that the plugging substance undergoes solidification or gelation. Alternatively, the sealing material is configured to undergo a curing or gelling reaction based on pH changes, wherein the initial sealing fluid and the subsequent sealing fluid each contain sealing materials with different pH values, and a curing or gelling reaction occurs due to pH changes upon contact; or, the sealing material is configured to undergo a curing or gelling reaction based on salinity changes, wherein the initial sealing fluid and the subsequent sealing fluid each contain sealing materials with different salinities, and a curing or gelling reaction occurs due to salinity changes upon contact.

6. The method according to claim 5, characterized in that, The plugging material is a liquid plugging material, which is added directly to the fluid; Alternatively, the plugging material in the fluid may be added at least in part in a manner encapsulated in a biodegradable capsule, and the plugging material may be a solid or liquid plugging material.

7. The method according to claim 5, characterized in that, After the step of injecting the plugging fluid, the method further includes injecting a displacement fluid into the target wellbore to drive the plugging fluid in the target wellbore into the formation fractures. The ratio of the viscosity of the plugging fluid to the viscosity of the displacement fluid shall not exceed 10; The density of the plugging fluid must not be less than 70% of the density of the displacement fluid.

8. The method according to claim 5, characterized in that, After the step of injecting the first sealing fluid and before the step of injecting the subsequent sealing fluid, an isolation fluid is injected to prevent the two fluids from contacting each other prematurely and reacting. In the prior sealing fluid, the isolation fluid, and the subsequent sealing fluid, the ratio of the viscosity of the prior injected fluid to the viscosity of the subsequent injected fluid does not exceed 10. In the prior sealing fluid, the isolation fluid, and the subsequent sealing fluid, the density of the prior injected fluid is not less than 70% of the density of the subsequent injected fluid; The injection flow rates of the isolation fluid and the subsequent sealing fluid must be lower than the threshold flow rate, which is determined by comparing the calculated Reynolds number obtained by the prior sealing fluid, the subsequent sealing fluid, and the isolation fluid to see if they meet the critical value for turbulence.

9. The method according to claim 5, characterized in that, After the initial sealing fluid is injected, the formation fracture is judged to be closed by monitoring whether the bottom hole pressure is less than the fracture closure pressure. After the formation fracture is judged to be closed, it is determined that the initial sealing fluid in the formation fracture has been filtered into the formation, and then the work of injecting the subsequent sealing fluid is started. Alternatively, after the fluid is first used to seal the formation fractures and then the fluid is injected to seal them again, the fluid is reversed and drained back into the formation.

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