Method for chemically plugging rock around stratum fracture

Abstract

The invention relates to a plugging method for plugging a rock gap around a formation fracture, which is used for plugging by forming a solid substance in the rock gap around the formation fracture by virtue of chemical reaction, so that the problem of plugging the rock gap around the formation fracture without influencing the opening and closing of the formation fracture is solved. Moreover, the application scene of storing the high-pressure fluid by utilizing the formation fracture can be greatly expanded, for example, the high-permeability sandstone can also be used as a carrier of the formation fracture for storing the high-pressure fluid after chemical plugging, and the constraint of geological conditions on underground energy storage and underground deep burying site selection of harmful waste is greatly reduced.

Description

Technical Field

[0001] The present application belongs to the technical field of underground energy storage and deep underground burial of hazardous waste, and specifically relates to a method for chemically sealing rocks around formation cracks. Background Art

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

[0003] The long-term storage of high-pressure fluids in formation fractures requires that the fluids not be lost to the pores of the rock surrounding the formation fractures during storage. Therefore, sealing the rock surrounding the formation fractures and reducing rock permeability are key to preventing fluid loss.

[0004] Currently, reducing rock permeability can be achieved by injecting chemical reagents into the rock formation. For example, chemicals penetrate the rock, causing chemical reactions within the mineral components to form minerals, thereby reducing rock permeability. Another approach is to inject reinforcing materials such as polymers into natural cracks or pores within 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 rock permeability, they also seal existing cracks, requiring the creation of new cracks to store high-pressure fluids.

[0005] Another approach involves injecting a fluid into the formation fractures that reacts with the original formation fluid to form a precipitate, thereby plugging the rock pores. However, this method is limited by its high requirements for the composition of the original formation fluid (for example, it must contain calcium and magnesium ions, and their ion concentrations must reach a certain threshold), making it unsuitable for all formations.

[0006] In view of this, there is an urgent need for a method that can seal the rocks around the formation cracks and reduce the rock permeability, and has no requirements for the original formation fluid and will not cause the cracks themselves to be blocked. Summary of the Invention

[0007] In order to solve the above-mentioned technical problems, the present invention has designed a method for chemically sealing the rocks around formation fractures. It can not only effectively achieve the purpose of reducing the permeability of rocks without requiring the original fluid of the formation, but also greatly expand the applicable scenarios of using formation fractures to store high-pressure fluids, so that it is no longer limited to low-permeability formations as in the existing technology.

[0008] A first aspect of the present invention discloses a method for chemically plugging rocks around formation fractures, comprising the following steps:

[0009] S1, injecting fracturing fluid into the target wellbore to perform hydraulic fracturing operations to create formation fractures and / or open existing formation fractures;

[0010] The fracturing fluid contains a plugging substance that can undergo a solidification or gelling reaction, so as to chemically plug the rock voids and / or microcracks around the formation fractures after the fracturing fluid enters the formation fractures.

[0011] In one embodiment, the plugging material includes at least one main agent and at least one cross-linking agent or curing agent capable of undergoing a solidification or gelation reaction with the main agent, so as to chemically seal the rock voids and / or microcracks around the formation fractures; or, the plugging material is configured to be able to contact the original fluid in the rock voids and / or microcracks around the formation fractures to undergo a solidification or gelation reaction.

[0012] On the basis of the above embodiment, further, after the step of injecting the fracturing fluid, it also includes injecting a 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 does not exceed 10; the density of the fracturing fluid cannot be lower than 70% of the density of the displacement fluid.

[0013] Further, in another embodiment, in step S1, the steps of separately injecting a fracturing fluid and a subsequent fluid into the target wellbore in sequence are included, wherein the subsequent fluid is a subsequent fracturing fluid or a subsequent additional fluid;

[0014] The fracturing fluid and the after-fluid fluid contain different plugging substances, respectively, and can undergo solidification or gelation reaction after contacting each other; or, the plugging substance is set as a substance that can undergo solidification or gelation reaction based on its own temperature increase; the after-fluid fluid is set as a high-temperature fluid, so that the plugging substance in the fracturing fluid undergoes solidification or gelation reaction; or, the plugging substance is set as a substance that can undergo solidification or gelation reaction based on pH change, the fracturing fluid and the after-fluid fluid respectively contain plugging substances with different pH values, and after contacting each other, they undergo solidification or gelation reaction due to pH change; or, the plugging substance is set as a substance that can undergo solidification or gelation reaction based on salinity change, the fracturing fluid and the after-fluid fluid respectively contain plugging substances with different salinities, and after contacting each other, they undergo solidification or gelation reaction due to salinity change.

[0015] On the basis of the aforementioned other embodiments, further, after the step of injecting the fracturing fluid and before the step of injecting the subsequent fluid, an isolation fluid is injected to prevent the two fluids from prematurely contacting and reacting; among the fracturing fluid, the isolation fluid and the subsequent fluid, the ratio of the viscosity of the previously injected fluid to the viscosity of the subsequently injected fluid does not exceed 10; among the fracturing fluid, the isolation fluid and the subsequent fluid, the density of the previously injected fluid is not less than 70% of the density of the subsequently injected fluid.

[0016] On the basis of all the aforementioned embodiments, further, the plugging material is a liquid plugging material and is directly added to the fluid; or, the plugging material in the fluid is at least partially added to the fluid in a manner of being wrapped in a degradable capsule, and the plugging material can be a solid or liquid plugging material.

[0017] The second aspect of the present invention discloses another method for chemically plugging rocks around formation fractures, which comprises the following steps:

[0018] S1, injecting fracturing fluid into the target wellbore to perform hydraulic fracturing operations to create formation fractures and / or open existing formation fractures;

[0019] S2, injecting plugging fluid into the formation fractures;

[0020] The plugging fluid contains plugging substances that can undergo solidification or gelation reactions, so as to chemically plug rock voids and / or microcracks around formation fractures after the plugging fluid enters the formation fractures.

[0021] In one embodiment, the plugging material includes at least one main agent and at least one cross-linking agent or curing agent capable of undergoing a curing or gelling reaction with the main agent, so as to chemically seal rock voids and / or microcracks around formation fractures.

[0022] Based on the above embodiment, further, after the step of injecting the plugging fluid, it also includes injecting a displacement fluid 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 cannot be lower than 70% of the density of the displacement fluid.

[0023] In one embodiment, the plugging material is configured to be a material that can solidify or gel upon increasing its own temperature, and the fracturing fluid in step S1 is configured to be a high-temperature fluid, so that the plugging material in the plugging fluid can solidify or gel.

[0024] In another embodiment, step S2 includes the steps of separately injecting a first plugging fluid and a second plugging fluid into the target wellbore in sequence; the first plugging fluid and the second plugging fluid contain different plugging substances, respectively, and can undergo a solidification or gelation reaction after contacting each other; or, the plugging substance is configured to be a substance that can undergo a solidification or gelation reaction based on its own temperature increase; one of the first plugging fluid and the second plugging fluid contains a plugging substance, and the other is a high-temperature fluid, so that the plugging substance solidifies or or, the plugging material is configured as a material capable of undergoing a solidification or gelation reaction based on a pH change, the first plugging fluid and the second plugging fluid respectively contain plugging materials of different pH values, and after contacting each other, a solidification or gelation reaction occurs due to a pH change; or, the plugging material is configured as a material capable of undergoing a solidification or gelation reaction based on a salinity change, the first plugging fluid and the second plugging fluid respectively contain plugging materials of different salinities, and after contacting each other, a solidification or gelation reaction occurs due to a salinity change.

[0025] On the basis of the aforementioned other embodiments, further, after the step of injecting the prior plugging fluid and before the step of injecting the subsequent plugging fluid, an isolation fluid is injected to prevent the two fluids from contacting and reacting prematurely; among the prior plugging fluid, the isolation fluid and the subsequent plugging fluid, the ratio of the viscosity of the prior injected fluid to the viscosity of the subsequently injected fluid does not exceed 10; among the prior plugging fluid, the isolation fluid and the subsequent plugging fluid, the density of the prior injected fluid is not less than 70% of the density of the subsequently injected fluid; the injection flow rates of the isolation fluid and the subsequent plugging fluid need to be lower than a threshold flow rate, and the threshold flow rate is determined by comparing and calculating the Reynolds numbers in the prior plugging fluid, the subsequent plugging fluid and the isolation fluid to determine whether they meet the critical value of turbulence.

[0026] On the basis of the aforementioned other embodiments, further, after the injection of the prior plugging fluid, whether the formation fracture is closed is judged by monitoring whether the bottom hole pressure is less than the fracture closure pressure. After judging that the formation fracture is closed, it is determined that the prior plugging fluid in the formation fracture has been lost to the formation, and then the injection of the subsequent plugging fluid is started; alternatively, the prior plugging fluid is refluxed until the formation fracture is closed, and then the subsequent plugging fluid is injected.

[0027] Based on all the embodiments disclosed in the aforementioned second aspect, the plugging material is a liquid plugging material and is directly added to the fluid; or, the plugging material in the fluid is at least partially added to the fluid in a manner of being wrapped in a degradable capsule, and the plugging material can be a solid or liquid plugging material.

[0028] Beneficial effects: The use of formation fractures to store high-pressure fluids requires that the rocks around the fractures have extremely low permeability. Therefore, related applications are currently limited to formations with low permeability (such as shale, granite, etc.). The method of chemically sealing the rocks around formation fractures proposed in the present invention can greatly expand the applicable scenarios of using formation fractures to store high-pressure fluids. For example, high-permeability sandstone can also be used as a carrier for storing high-pressure fluids in formation fractures after chemical sealing, greatly reducing the constraints of geological conditions on the selection of underground energy storage and deep underground burial of hazardous waste.

[0029] The method and system for chemically plugging rocks around formation fractures of the present invention will be disclosed in detail below with reference to the embodiments shown in the accompanying drawings and the accompanying reference numerals. BRIEF DESCRIPTION OF THE DRAWINGS

[0030] Figure 1 A flow chart showing the steps of the method for chemically plugging rocks around formation fractures disclosed in the first aspect of the present invention is shown.

[0031] Figure 2 A flow chart showing the steps of the method for chemically plugging rocks around formation fractures disclosed in the second aspect of the present invention is shown. DETAILED DESCRIPTION

[0032] It should be noted that the "liquid fluid" in this article can be but is not limited to liquid, emulsion, slurry and solid particle flow with flow characteristics similar to liquid flow; and the "fluid" in this article can be but is not limited to gas, liquid, emulsion, slurry and solid particle flow with flow characteristics similar to liquid flow.

[0033] The term "formation" as used herein refers to a porous and permeable rock formation (e.g., shale formation, sandstone formation, carbonate formation, hot dry rock formation, etc.) underground that can serve as a storage space for fluids. Typically, these fluids can be water, hydrocarbons, or gases.

[0034] The term "hydraulic fracturing" or "fracture" or "cracking" used herein refers to the generation and expansion of cracks in formation rocks under the action of external forces (such as high-pressure fluid).

[0035] "Formation fractures" or "fractures" in this article are open cracks in the rock created by hydraulic fracturing, or existing natural fractures or faults in the formation. The terms "formation fractures" and "fractures" are used interchangeably. "Fractures" can refer to a single fracture, multiple adjacent fractures at the same location, or a fracture swarm.

[0036] As used herein, "wellbore" refers to a hole drilled or inserted into a formation by conduit. Typically, a wellbore is cylindrical, and therefore may have a circular cross-section. However, a wellbore may have any other cross-section. A wellbore may be open-hole, or cased (cased). A wellbore may be vertical, horizontal, or inclined.

[0037] The following will provide a clear and complete description of the technical solutions in the embodiments of the present invention in conjunction with the drawings and the above definitions of terms in the embodiments of the present invention. Obviously, the embodiments described are only part of the embodiments of the present invention, not all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without making creative efforts are within the scope of protection of the present invention.

[0038] It should be noted that, unless there is any conflict, the embodiments and features in the embodiments of this application can be combined with each other.

[0039] Figure 1 The flowchart of the steps of the method for chemically plugging rocks around formation fractures disclosed in the first aspect of the present invention is shown. Figure 1 As shown, the present invention discloses a method for chemically plugging rocks around a formation fracture, comprising the following steps:

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

[0041] That is, in the method disclosed in the first aspect of the present invention, the chemical plugging work is completed simultaneously with the hydraulic fracturing operation. That is, when the hydraulic fracturing operation using the fracturing fluid completes the step of creating formation fractures, the rock voids and / or microcracks surrounding the formation fractures are also chemically plugged synchronously. In other words, in the method disclosed in the first aspect of the present invention, the step of creating formation fractures based on hydraulic fracturing can simultaneously complete the dual tasks of creating or opening formation fractures and chemically plugging the rock voids and / or microcracks surrounding the formation fractures.

[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 in the wellbore.

[0043] In addition, the so-called curing reaction is a reaction that can produce a solid, such as the reaction of epoxy resin and curing agent to produce a solid, and it can also refer to a reaction that can produce a precipitate, such as the mixed reaction of sodium chloride liquid and calcium carbonate liquid to produce a precipitate; the so-called gelation reaction refers to a reaction that produces a colloid.

[0044] Specifically, the plugging material can be constructed so that solidification or gelation reactions occur between its own components, or different liquid plugging materials can contact each other to cause solidification or gelation reactions, or can contact the original fluid in the rock voids and / or microcracks around the formation fractures to cause solidification or gelation reactions, or can change in salinity, pH or temperature after entering the formation to cause solidification or gelation reactions, so as to chemically seal the rock voids and / or microcracks around the formation fractures.

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

[0046] The following describes the process of completing chemical plugging of fractures simultaneously with hydraulic fracturing construction in conjunction with specific embodiments.

[0047] Example 1

[0048] The fracturing fluid serves as a single working fluid, containing plugging substances including at least one main agent and at least one cross-linking agent or curing agent capable of solidifying or gelling with the main agent, thereby chemically sealing the rock voids and / or microcracks surrounding formation fractures. In this embodiment, the single fracturing fluid alone can chemically seal the rock voids and / or microcracks surrounding formation fractures simultaneously with hydraulic fracturing.

[0049] For example, polyacrylamide is the main agent of the plugging material, and chromium salts and zirconium salts are crosslinking agents / curing agents. The plugging material is liquid when injected into the wellbore. After entering the formation, it gels and solidifies to form a gel with a three-dimensional network structure. The gelation / curing reaction usually takes tens of minutes to several hours.

[0050] Example 2

[0051] The fracturing fluid serves as a single working fluid, and the plugging material contained therein is configured to solidify or gel upon contact with the original fluid within the rock voids and / or microcracks surrounding the formation fractures. In this embodiment, the fracturing fluid alone can chemically plug the rock voids and / or microcracks surrounding the formation fractures during hydraulic fracturing.

[0052] The so-called original fluid refers to the original fluid that already exists within the rock voids and / or microcracks surrounding the formation fractures before the fracturing fluid is injected. The chemical properties of the original fluid can be obtained in advance, which is a state of the art and will not be further described here. Based on the chemical properties of the original fluid obtained in advance, the plugging material in the fracturing fluid is selected and arranged so that it can contact the original fluid in the rock voids and / or microcracks surrounding the formation fractures to cause a solidification or gelation reaction.

[0053] Additionally, based on the aforementioned embodiment one and embodiment two, further, after the step of injecting the fracturing fluid, it also includes injecting a displacement fluid into the target wellbore to drive the fracturing fluid in the target wellbore into the formation cracks. That is, in order to prevent the plugging material from clogging the wellbore after gelling / solidifying, before the plugging material completes the gelling / solidifying reaction, it is necessary to inject a displacement fluid into the wellbore to drive all the fluid containing the plugging material in the wellbore into the formation cracks. Stop injecting the displacement fluid into the target wellbore and seal the wellhead, waiting for the plugging material to continue to filter into the formation and complete the gelling / solidifying reaction. Any liquid that does not generate solids or does not 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] In order to achieve a better displacement effect of the displacement fluid on the fluid, avoid the occurrence of viscous fingering, and reduce the mixing of the displacement fluid and the fracturing fluid containing the plugging material in the wellbore, the ratio of the viscosity of the fracturing fluid containing the plugging material to the viscosity of the displacement fluid shall not exceed 10.

[0055] In order to prevent the displacement fluid and the fracturing fluid containing plugging materials from generating Rayleigh-Taylor instability due to the different densities in the wellbore, the density of the fracturing fluid cannot be lower than 70% of the displacement fluid density.

[0056] It should be noted that the injection of displacement fluid is only applicable to the case where the plugging is formed based on a single fluid (such as the fracturing fluid mentioned above and the plugging fluid to be mentioned below). This is because, when using a single fluid, although the injected fluid is in liquid state, it has begun to solidify or gelate and usually takes more than tens of minutes to become solid. At this time, the injection of displacement fluid can help inject the plugging fluid into the crack; it is not applicable to the case where different fluids used for plugging are injected in sequence for plugging, because no solidification or gelation reaction will occur in the wellbore when different fluids used for plugging are injected in sequence.

[0057] Example 3

[0058] In step S1, the steps of injecting fracturing fluid and subsequent fluid into the target wellbore separately in sequence are included, wherein the subsequent fluid is subsequent fracturing fluid or subsequent additional fluid; that is, the subsequent fluid can be either fracturing fluid for fracturing or additional fluid for not fracturing.

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

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

[0061] Example 4

[0062] In step S1, the steps of injecting fracturing fluid and subsequent fluid into the target wellbore separately in sequence, wherein the subsequent fluid is subsequent fracturing fluid or subsequent additional fluid; the plugging material is set to be a material that can undergo a solidification or gelation reaction based on its own temperature increase; the subsequent fluid is set to be a high-temperature fluid, so that the plugging material in the fracturing fluid undergoes a solidification or gelation reaction.

[0063] That is, a separate fluid, independent of the fracturing fluid, is injected into the formation fractures; the fracturing fluid contains a plugging substance, and the separate fluid is a high-temperature fluid. The fracturing fluid containing the plugging substance can fuse with the high-temperature fluid and heat up, allowing the plugging substance to form a solid or colloid upon heating, thereby achieving chemical plugging. For example, high-temperature water can be used as the separate fluid, while a room-temperature liquid containing zinc chloride can be used as the fracturing fluid. When the two come into contact, the temperature of the fracturing fluid increases, forming a solid precipitate of zinc hydroxide.

[0064] Example 5

[0065] In step S1, the steps of injecting fracturing fluid and subsequent fluid into the target wellbore separately in sequence, wherein the subsequent fluid is subsequent fracturing fluid or subsequent additional fluid; the plugging material is set to be a material that can undergo a solidification or gelation reaction based on pH changes, and the fracturing fluid and the subsequent fluid respectively contain plugging materials with different pH values, and after contact with each other, they undergo a solidification or gelation reaction due to pH changes.

[0066] Specifically, the fracturing fluid contains a first pH plugging material with a first pH value, and the trailing fluid contains a second pH plugging material with a second pH value. Hydraulic fracturing construction is first carried out with the help of the fracturing fluid. At this time, the first pH plugging material with the first pH value diffuses into the rock pores around the cracks, and then the trailing fluid with the second pH value is injected into the formation cracks. After the fracturing fluid and the trailing fluid come into contact, the pH value changes, thereby generating a fixation to achieve chemical sealing.

[0067] Example 6

[0068] In step S1, the steps of separately injecting fracturing fluid and subsequent fluid into the target wellbore in sequence, wherein the subsequent fluid is subsequent fracturing fluid or subsequent additional fluid; the plugging material is configured to be a material that can undergo a solidification or gelation reaction based on a change in salinity, the fracturing fluid and the subsequent fluid respectively contain plugging materials of different salinities, and solidify or gelate due to a change in salinity after contact with each other (for example, the fracturing fluid contains barium nitrate, and the subsequent fluid contains sulfate, which can generate barium sulfate after contact with each other).

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

[0070] Alternatively, based on the aforementioned embodiments three to six, after the step of injecting the fracturing fluid and before the step of injecting the trailing fluid, a spacer fluid is injected to prevent the two fluids from prematurely contacting and reacting. The injection of the spacer fluid prevents the fracturing fluid and the trailing fluid from prematurely contacting and chemically reacting in the wellbore. The spacer fluid can be any liquid that does not chemically react with the fracturing fluid or the trailing fluid.

[0071] In order to prevent the occurrence of viscous fingering, the ratio of the viscosity of the first injected fluid to the viscosity of 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 the spacer fluid and the fracturing fluid from generating Rayleigh-Taylor instability and stratification in the formation fractures due to the different densities in the wellbore, the density of the first injected fluid among the fracturing fluid, the spacer fluid and the subsequent fluid is not less than 70% of the density of the subsequent injected fluid.

[0073] Furthermore, in this embodiment, to prevent the fracturing fluid, the back-fluid, and the spacer fluid from causing turbulence in the wellbore or formation fractures due to excessive flow during injection, thereby preventing the different fluids from mixing, the flow rates of the injected spacer and back-fluid fluids 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 fluid dynamics properties of the fracturing fluid, the back-fluid, and the spacer fluid, the wellbore and fracture dimensions, and the surface roughness of the wellbore and fractures. For example, the threshold flow rate can be determined by comparing the calculated Reynolds number to see if it meets the critical value for turbulence.

[0074] Additionally, based on the aforementioned embodiments one to six, the plugging material is a liquid plugging material and is directly added to the fluid; or, the plugging material in the fluid is at least partially added to the fluid in a manner of being wrapped in a degradable capsule, and the plugging material can be a solid or liquid plugging material.

[0075] In some cases, the chemical reaction rates of the different components of the plugging material itself are too fast, posing the risk of wellbore blockage, or it is difficult to match the density or viscosity of the different fluids and the spacer fluid, or the spacer fluid may invade the formation pores and hinder the chemical reaction of the different fluids. Therefore, a method is used to encapsulate the plugging material into degradable (also referred to as soluble) capsules (referring to any container that can store liquids or powders) and inject them into the formation fractures. After the capsules degrade, the released plugging material and / or the plugging material and the fluid injected into the formation can stimulate chemical reactions to form solids or colloids, thereby chemically sealing the rock voids and / or microcracks around the formation fractures.

[0076] Degradable capsules can be made of materials such as water-soluble polymers, degradable polylactic acid films, and soluble carboxymethyl cellulose. The material ratio and degradation time of the capsules can be tailored based on the formation temperature and construction time. In some embodiments, the capsules degrade within 30 to 60 minutes upon contact with water, allowing the reactants within the capsules to be released from the capsules 30 to 60 minutes after entering the formation.

[0077] In a specific implementation, in combination with Example 1, the fracturing fluid is configured as a fluid containing degradable capsules, wherein the degradable capsules contain plugging substances, and the plugging substances released after the capsules degrade chemically react with each other and / or with other components of the fracturing fluid to generate solids or colloids, which chemically seal the rock voids and / or microcracks around the formation fractures.

[0078] In a specific implementation, in combination with Example 2, the fracturing fluid is configured as a fluid containing degradable capsules, wherein the degradable capsules contain plugging substances. The plugging substances released after the capsules are degraded react chemically with the original fluid in the rock cracks around the formation to generate solids or colloids, chemically sealing the rock voids and / or microcracks around the formation cracks.

[0079] In a specific embodiment, in combination with Examples 3, 5, and 6, degradable capsules are present in the fracturing fluid and / or in the post-fluid fluid, and the degradable capsules contain at least one plugging substance; the plugging substance released after the capsules are degraded reacts chemically with components in the fracturing fluid to generate solids or colloids, which chemically seal the rock voids and / or microcracks around the formation fractures.

[0080] In a specific embodiment, in combination with Example 4, the fracturing fluid is configured as a fluid containing degradable capsules, wherein the degradable capsules contain plugging substances, and the plugging substances released after the capsules are degraded are transformed into solids or colloids due to the high temperature of the subsequent fluid, thereby chemically sealing the rock voids and / or microcracks around the formation fractures.

[0081] In addition, based on the above-mentioned embodiments three to six, after the injection of the fracturing fluid, the closure of the formation fracture is judged 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 fracturing fluid in the formation fracture has been lost to the formation, and then the injection of the subsequent fluid is started; or, the fracturing fluid is refluxed and reversed until the formation fracture is closed, and then the subsequent fluid is injected. This is to avoid chemical reactions between the previous fracturing fluid and the subsequent fluid during migration in the fracture. The fluid containing the plugging substance and other fluids need to be injected into the formation fracture separately, that is, the well needs to be shut down to wait for the fluid containing the plugging substance to be completely lost to the formation before injecting other fluids, or the well needs to be shut down to wait for the other fluids to be completely lost to the formation before injecting the fluid containing the plugging substance.

[0082] The second aspect of the present invention discloses another method for chemically plugging rocks around formation fractures, which comprises the following steps:

[0083] S1, injecting fracturing fluid into the target wellbore to perform hydraulic fracturing operations to create formation fractures and / or open existing formation fractures;

[0084] S2, injecting plugging fluid into the formation fractures;

[0085] The plugging fluid contains plugging substances that can undergo solidification or gelation reactions, so as to chemically plug rock voids and / or microcracks around formation fractures after the plugging fluid enters the formation fractures.

[0086] The explanations of the “target wellbore”, “curing reaction” and “plugging material” mentioned in the method disclosed in the first aspect of the present invention are also applicable to the method disclosed in the second aspect of the present invention and will not be repeated here.

[0087] By providing a plugging fluid for chemical plugging after injecting the fracturing fluid for fracturing construction, the following advantages are achieved: due to the loss of the fracturing fluid during the fracturing process, the original fluid (including formation mineral cations) in the rock pores surrounding the formation fractures has been displaced to a distant location. That is, the rock pores surrounding the formation fractures are now filled with the fracturing fluid. When the plugging fluid containing the plugging material enters the formation fractures, the plugging material will no longer react or complete a chemical reaction with the original fluid (including formation mineral cations) in the rock pores. In other words, chemical reactions between the plugging material and the original fluid or substances in the rock pores are avoided.

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

[0089] Example 7

[0090] The plugging fluid serves as a single plugging working fluid, and the plugging substances it contains include at least one main agent and at least one cross-linking agent or curing agent that can undergo a solidification or gelation reaction with the main agent, so as to chemically plug the rock voids and / or microcracks around the formation cracks. In this embodiment, the rock voids and / or microcracks around the formation cracks can be chemically plugged only based on a single plugging fluid fluid itself after hydraulic fracturing construction. Similarly, for example, polyacrylamide is the main agent of the plugging substance, and chromium salts, zirconium salts, etc. are cross-linking agents / curing agents.

[0091] On the basis of this embodiment, further, after the step of injecting the plugging fluid, it also includes injecting a displacement fluid into the target wellbore to drive the plugging fluid in the target wellbore into the formation fractures; that is, in order to prevent the plugging material from clogging the wellbore after gelling / solidifying, before the plugging material completes the gelling / solidifying reaction, it is necessary to inject a displacement fluid into the wellbore to drive all the fluid containing the plugging material in the wellbore into the formation fractures. Stop injecting the displacement fluid into the target wellbore and seal the wellhead, waiting for the plugging material to continue to filter into the formation and complete the gelling / solidifying reaction. Any liquid that does not generate solids or does not 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] In order to achieve a better displacement effect of the displacement fluid on the plugging fluid, avoid the occurrence of viscous fingering, and reduce the mixing of the displacement fluid and the fracturing fluid containing plugging materials in the wellbore, the ratio of the viscosity of the plugging fluid to the viscosity of the displacement fluid shall not exceed 10.

[0093] In order to prevent the displacement fluid and the plugging fluid containing plugging material from generating Rayleigh-Taylor instability due to the different densities in the wellbore, the density of the plugging fluid cannot be lower than 70% of the displacement fluid density.

[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 the plugging is formed based on a single fluid (such as the fracturing fluid mentioned above, and the plugging fluid to be mentioned below). The specific reasons are the same 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 set to be a material that can solidify or gel based on its own temperature increase, and the fracturing fluid in step S1 is set to be a high-temperature fluid to enable the plugging material in the plugging fluid to solidify or gel.

[0097] That is, the high-temperature fracturing fluid is used to cause the plugging material to solidify or gel. This allows for a close integration of steps S1 and S2. The fracturing fluid in step S1 no longer simply serves as a fracturing fluid, but also participates in the chemical plugging process in step S2. Furthermore, because the fracturing fluid is a high-temperature fluid, additional high-temperature fluid can be added during or after step S2 to cause the plugging material to solidify or gel. This significantly saves time and reduces costs.

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

[0099] Embodiment 9

[0100] In step S2, the steps of sequentially injecting a first plugging fluid and a second plugging fluid into the target wellbore are included; the first plugging fluid and the second plugging fluid contain different plugging substances, and can undergo a solidification or gelation reaction upon contact with each other;

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

[0102] For example, the plugging material can be metal cations, such as one or more of 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, and then a second plugging fluid that can chemically react with the metal cations to form solid precipitates is injected into the formation fracture.

[0103] Example 10

[0104] In step S2, a step of sequentially injecting a first plugging fluid and a second plugging fluid into the target wellbore is included; the plugging material is configured to be a material capable of solidifying or gelling upon increasing its own temperature; one of the first plugging fluid and the second plugging fluid contains the plugging material, while the other is a high-temperature fluid, so that the plugging material solidifies or gels;

[0105] That is, a subsequent plugging fluid, independent of the prior plugging fluid, is injected into the formation fractures; the prior plugging fluid contains a plugging substance, while the subsequent plugging fluid is a high-temperature fluid. The prior plugging fluid containing the plugging substance and the high-temperature fluid fuse and heat up, allowing the plugging substance to form a solid or colloid upon heating, thereby achieving chemical plugging. For example, high-temperature water can be used as the subsequent plugging fluid, while a room-temperature liquid containing zinc chloride can be used as the prior plugging fluid. When the two come into contact, the temperature of the fracturing fluid increases, resulting in the formation of a solid precipitate of zinc hydroxide.

[0106] Example 11

[0107] In step S2, the steps of sequentially injecting a first plugging fluid and a second plugging fluid into the target wellbore are included; the plugging material is configured to be a material capable of undergoing a solidification or gelation reaction based on pH changes, the first plugging fluid and the second plugging fluid respectively contain plugging materials of different pH values, and upon contact with each other, solidification or gelation reaction occurs due to pH changes;

[0108] Specifically, the prior plugging fluid contains a first pH plugging substance with a first pH value, while the subsequent plugging fluid contains a second pH plugging substance with a second pH value. The prior plugging fluid is first injected into the formation fracture, and the first pH plugging substance diffuses into the rock pores around the fracture. Then, the subsequent plugging fluid with a second pH value is injected into the formation fracture. After the prior plugging fluid and the subsequent plugging fluid come into contact, the pH value changes, thereby generating a fixation to achieve chemical plugging.

[0109] Example 12

[0110] In step S2, the steps of sequentially injecting a first plugging fluid and a second plugging fluid into the target wellbore are included; the plugging material is configured to be a material that can undergo a solidification or gelation reaction based on a change in salinity, and the first plugging fluid and the second plugging fluid respectively contain plugging materials of different salinities, and solidify or gelate due to a change in salinity after contacting each other.

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

[0112] Based on the aforementioned embodiments 8 to 12, after the step of injecting the first plugging fluid and before the step of injecting the second plugging fluid, a spacer fluid is injected to prevent the two fluids from prematurely contacting and reacting. The injection of the spacer fluid prevents the first plugging fluid and the second plugging fluid from prematurely contacting and chemically reacting in the wellbore. The spacer fluid can be any liquid that does not chemically react with the first plugging fluid and the second plugging fluid.

[0113] In order to prevent the occurrence of viscous fingering, among the first plugging fluid, the spacer fluid and the subsequent plugging fluid, the ratio of the viscosity of the first injected fluid to the viscosity of the subsequent injected fluid does not exceed 10.

[0114] In order to prevent the Rayleigh-Taylor instability phenomenon and stratification in the formation fractures due to the different densities of the isolation fluid and the prior plugging fluid in the wellbore, the density of the prior injected fluid among the prior plugging fluid, the isolation fluid and the subsequent plugging fluid shall not be less than 70% of the density of the subsequent injected fluid.

[0115] Additionally, the injection flow rates of the spacer fluid and the subsequent plugging fluid must be lower than a threshold flow rate, which is determined by comparing the calculated Reynolds numbers of the preceding plugging fluid, the subsequent plugging fluid, and the spacer fluid to determine whether they meet a critical value for turbulence.

[0116] On the basis of the above-mentioned embodiments 8 to 12, further, after the injection of the first plugging fluid, the closure of the formation fracture is judged 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 plugging fluid in the formation fracture has been lost to the formation, and then the injection of the subsequent plugging fluid is started; or, the first plugging fluid is refluxed until the formation fracture is closed, and then the subsequent plugging fluid is injected. This is to avoid chemical reactions between the first plugging fluid and the subsequent plugging fluid during migration in the fracture. The fluid containing the plugging material and other fluids need to be injected into the formation fracture separately, that is, it is necessary to shut down the well to wait for the fluid containing the plugging material to be completely lost to the formation before injecting other fluids, or shut down the well to wait for the other fluids to be completely lost to the formation before injecting the fluid containing the plugging material.

[0117] Based on all the embodiments disclosed in the aforementioned second aspect, the plugging material is a liquid plugging material and is added directly to the fluid; or, at least a portion of the plugging material in the fluid is added to the fluid by being encapsulated in a degradable 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, which may risk blocking the wellbore, or the density or viscosity of the different fluids and the isolation fluid is difficult to match, or the isolation fluid may invade the formation pores and hinder the chemical reaction of the different fluids. By encapsulating the plugging material into a degradable (also referred to as soluble) capsule (referring to a container of any shape that can store liquid or powder) and injecting it into the formation fracture, after the capsule degrades, the released plugging material and / or the plugging material and the fluid injected into the formation can stimulate a chemical reaction to form a solid or colloid, thereby chemically plugging the rock voids and / or microcracks around the formation fracture.

[0118] Similarly, degradable capsules can be made of materials such as water-soluble polymers, degradable polylactic acid films, and soluble carboxymethyl cellulose. The material ratio and degradation time of the capsules can be tailored based on the formation temperature and construction time. In some embodiments, the capsules degrade within 30 to 60 minutes upon contact with water, allowing the reactants within the capsules to be released from the capsules 30 to 60 minutes after entering the formation.

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

[0120] In a specific embodiment, in combination with the aforementioned embodiment seven, the plugging fluid is configured as a fluid containing degradable capsules, wherein the degradable capsules contain plugging substances, and the plugging substances released after the capsules are degraded react chemically with each other and / or with other components of the plugging fluid to generate solids or colloids, thereby chemically plugging the rock voids and / or microcracks around the formation fractures.

[0121] In a specific implementation, in combination with Example 8, the plugging fluid is configured as a fluid containing degradable capsules, wherein the degradable capsules contain plugging substances. The plugging substances released after the capsules are degraded are transformed into solids or colloids due to the high temperature of the fracturing fluid, thereby chemically plugging the rock voids and / or microcracks around the formation fractures.

[0122] In a specific embodiment, in combination with Example 10, the prior plugging fluid is configured as a fluid containing degradable capsules, wherein the degradable capsules contain plugging substances, and the plugging substances released after the capsules are degraded are transformed into solids or colloids due to the high temperature of the subsequent plugging fluid, thereby chemically plugging the rock voids and / or microcracks around the formation fractures.

[0123] In a specific embodiment, in combination with Examples 9, 11 and 12, there are degradable capsules in the first plugging fluid and / or the second plugging fluid, and the degradable capsules contain at least one plugging substance; the plugging substance released after the capsules are degraded reacts chemically with the components in the plugging fluid to generate solids or colloids, which chemically plug the rock voids and / or microcracks around the formation fractures.

[0124] In addition, it should be emphasized that in the present invention, due to the use of displacement fluid or spacer fluid or batch injection of fluid containing plugging material, the solidification reaction only occurs in the pores around the cracks and does not block the formation cracks.

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

[0126] It should be noted that the terms used herein are only for describing specific embodiments and are not intended to limit the exemplary embodiments according to the present application. As used herein, unless the context clearly indicates otherwise, the singular form is also intended to include the plural form. In addition, it should be understood that when the terms "comprise" and / or "include" 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 and claims of the present application and the above-mentioned drawings are used to distinguish similar objects and are not necessarily used to describe a specific order or sequence. It should be understood that the data used in this way can be interchangeable where appropriate, so that the embodiments of the present application described herein can, for example, be implemented in an order other than those illustrated or described herein. In addition, the terms "including" and "having" and any variations thereof are intended to cover non-exclusive inclusions, for example, a process, method, system, product or device comprising a series of steps or units is not necessarily limited to those steps or units clearly listed, but may include other steps or units that are not clearly listed or inherent to these processes, methods, products or devices.

[0128] The above are merely preferred embodiments of the present invention and are not intended to limit the present invention. Those skilled in the art will readily appreciate that various modifications and variations of the present invention are possible. Any modifications, equivalent substitutions, or improvements made within the spirit and principles of the present invention shall 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 limiting. Although the present invention has been described in detail with reference to the preferred embodiments, those skilled in the art should understand that the technical solutions of the present invention may be modified or replaced by equivalents without departing from the purpose and scope of the technical solutions of the present invention, which should all be included in the scope of the claims of the present invention.

Claims

1. A method for chemically sealing rocks around formation fractures, characterized in that: The following steps are involved: S1, injecting fracturing fluid into the target wellbore to perform hydraulic fracturing operations to create formation fractures and / or open existing formation fractures; The fracturing fluid contains a plugging substance that can undergo a solidification or gelling reaction, so as to chemically plug the rock voids and / or microcracks around the formation fractures after the fracturing fluid enters the formation fractures.

2. The method according to claim 1, characterized in that The plugging material comprises at least one main agent and at least one cross-linking agent or curing agent capable of undergoing a curing or gelling reaction with the main agent, so as to chemically seal rock voids and / or microcracks around formation fractures; Alternatively, the plugging material is configured to be able to contact the original fluid in the rock voids and / or microcracks around the formation fractures to cause solidification or gelation reaction.

3. The method according to claim 1, characterized in that In step S1, the steps of sequentially injecting a fracturing fluid and a subsequent fluid into a target wellbore are included, wherein the subsequent fluid is a subsequent fracturing fluid or a subsequent additional fluid; The fracturing fluid and the back-fluid contain different plugging substances, and can undergo solidification or gelation reaction after contacting each other; Alternatively, the plugging material is configured to be a material that can undergo a solidification or gelation reaction based on its own temperature increase; the back fluid is configured to be a high-temperature fluid, so that the plugging material in the fracturing fluid undergoes a solidification or gelation reaction; Alternatively, the plugging material is configured to be a material capable of solidifying or gelling based on pH changes, the fracturing fluid and the back-fluid fluid respectively contain plugging materials with different pH values, and solidify or gellify due to pH changes after contact with each other; Alternatively, the plugging material is configured to be a material that can solidify or gel based on salinity changes, and the fracturing fluid and the back-fluid contain plugging materials of different salinities, which solidify or gel due to salinity changes after contacting each other.

4. The method according to any one of claims 1 to 3, characterized in that The plugging material is a liquid plugging material and is directly added to the fluid; Alternatively, the plugging material in the fluid is at least partially added to the fluid in a manner of being wrapped in a degradable capsule, and the plugging material can be a solid or liquid plugging material.

5. The method according to claim 2, characterized in that After the step of injecting the fracturing fluid, the method further includes injecting a 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 cannot be less than 70% of the displacement fluid density.

6. The method according to claim 3, characterized in that After the step of injecting the fracturing fluid and before the step of injecting the subsequent fluid, injecting a spacer fluid capable of preventing the two fluids from contacting and reacting prematurely; In the fracturing fluid, spacer fluid and follow-on fluid, the ratio of the viscosity of the first injected fluid to the viscosity of the subsequent injected fluid does not exceed 10; Among the fracturing fluid, the spacer fluid and the subsequent fluid, the density of the previously injected fluid is not less than 70% of the density of the subsequently injected fluid.

7. A method for chemically sealing rocks around formation fractures, characterized in that: The following steps are involved: S1, injecting fracturing fluid into the target wellbore to perform hydraulic fracturing operations to create formation fractures and / or open existing formation fractures; S2, injecting plugging fluid into the formation fractures; The plugging fluid contains plugging substances that can undergo solidification or gelation reactions, so as to chemically plug rock voids and / or microcracks around formation fractures after the plugging fluid enters the formation fractures.

8. The method according to claim 7, characterized in that The plugging material includes at least one main agent and at least one cross-linking agent or curing agent capable of undergoing a curing or gelling reaction with the main agent, so as to chemically seal rock voids and / or microcracks around formation fractures.

9. The method according to claim 7, characterized in that The plugging material is set to be a material that can solidify or gel based on its own temperature increase. The fracturing fluid in step S1 is set to be a high-temperature fluid to enable the plugging material in the plugging fluid to solidify or gel.

10. The method according to claim 7, characterized in that In step S2, the steps of sequentially injecting the first plugging fluid and the second plugging fluid into the target wellbore are included; The first plugging fluid and the second plugging fluid contain different plugging substances, and can undergo solidification or gelation reaction after contacting each other; Alternatively, the plugging material is configured to be a material capable of solidifying or gelling upon increasing its own temperature; one of the first plugging fluid and the second plugging fluid contains the plugging material, while the other is a high-temperature fluid, so that the plugging material solidifies or gels; Alternatively, the plugging material is configured to be a material capable of undergoing a solidification or gelation reaction based on pH changes, wherein the first plugging fluid and the second plugging fluid contain plugging materials with different pH values, and solidification or gelation reaction occurs due to pH changes after contact with each other; Alternatively, the plugging material is configured to be a material that can undergo a solidification or gelation reaction based on salinity changes, and the first plugging fluid and the second plugging fluid contain plugging materials with different salinities, and solidification or gelation reactions occur due to salinity changes after contact with each other.

11. The method according to any one of claims 7 to 10, characterized in that The plugging material is a liquid plugging material and is directly added to the fluid; Alternatively, the plugging material in the fluid is at least partially added to the fluid in a manner of being wrapped in a degradable capsule, and the plugging material can be a solid or liquid plugging material.

12. The method according to claim 8, 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 fracture; 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 cannot be lower than 70% of the displacement fluid density.

13. The method according to claim 10, characterized in that After the step of injecting the first plugging fluid and before the step of injecting the second plugging fluid, injecting a spacer fluid capable of preventing the two fluids from contacting and reacting prematurely; Among the first plugging fluid, the spacer fluid and the subsequent plugging fluid, the ratio of the viscosity of the first injected fluid to the viscosity of the subsequent injected fluid does not exceed 10; Among the first plugging fluid, the spacer fluid and the subsequent plugging fluid, the density of the first injected fluid is not less than 70% of the density of the subsequent injected fluid; The injection flow rates of the spacer fluid and the subsequent plugging fluid must be lower than a threshold flow rate, which is determined by comparing the Reynolds numbers calculated in the preceding plugging fluid, the subsequent plugging fluid, and the spacer fluid to see if they meet the critical value of turbulence.

14. The method according to claim 10, characterized in that After the first plugging fluid is injected, the bottom hole pressure is monitored to determine whether the formation fracture is closed or not. After the formation fracture is closed, it is determined that the first plugging fluid in the formation fracture has been lost to the formation, and then the injection of the subsequent plugging fluid is started. Alternatively, the first plugging fluid is refluxed until the formation fractures are closed, and then the subsequent plugging fluid is injected.

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