Method for improving formation fracture propagation pressure

Abstract

The invention belongs to the technical field of underground energy storage and harmful waste underground deep burying, and discloses a method for improving formation fracture propagation pressure, which comprises the following steps: sequentially or simultaneously injecting a first fluid and a second fluid into a formation fracture or injecting a degradable capsule and a third fluid into the formation fracture; when a first fluid and a second fluid are sequentially injected into the formation fracture, the second fluid is used for displacing the first fluid to the fracture tip of the formation fracture; when the first fluid and the second fluid are injected into the stratum fracture at the same time, the density of the first fluid is smaller than or larger than that of the second fluid. According to the method disclosed by the invention, the crack propagation pressure can be increased under the condition that the size of the formation crack is not changed, so that the energy storage capacity and the harmful waste storage capacity of the formation crack are improved.

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 increasing the expansion pressure of formation fractures. Background Art

[0002] Formation fractures can be used for energy storage. For example, patent application CN114016988A discloses a method and system for storing and releasing energy through formations. The method performs hydraulic fracturing in an energy storage formation that does not contain oil or gas, thereby generating at least one formation fracture. High-pressure fluid is then injected into the resulting formation fracture to cause elastic deformation of the formation fracture for energy storage. The energy is then released by discharging the high-pressure fluid in the fracture back into a preset power generation device.

[0003] Formation fractures can also be used to store hazardous waste. For example, the Oak Ridge National Laboratory in the United States has been injecting radioactive fluid waste into artificial formation fractures in shale formations for decades to achieve the purpose of permanent preservation.

[0004] The volume of high-pressure fluid that a formation fracture can store depends on the size of the fracture and the fracture propagation pressure (fracture extension pressure). Injecting high-pressure fluid into a formation fracture increases the fracture's width and, consequently, its volume, while also increasing the pressure within the fracture. When the pressure within the fracture reaches the fracture propagation pressure, the fracture will expand in length or height.

[0005] Increasing the length of the crack will increase the frictional resistance of fluid migration in the crack, which is not conducive to the circulation efficiency of energy storage. At the same time, when the crack size is larger than the preset crack size, it will cause uncontrollable geological risks (such as connecting faults or crack channeling).

[0006] Currently, methods to improve rock strength can be used to enhance its ability to resist crack propagation. For example, chemicals can be used to penetrate the rock, such as through silicification or carbonization processes, to cause chemical reactions within the rock's mineral components, producing harder, more stable minerals and thus enhancing the rock's strength. Another example is injecting reinforcing materials such as polymers into the rock's natural cracks or pores to fill defects and improve overall strength. However, these methods either require treating the entire rock formation, which is extremely costly, or, while increasing the rock's strength, they also seal existing cracks, necessitating the creation of new cracks to store high-pressure fluids. Furthermore, these methods are particularly unsuitable in rock formations with very low permeability, such as shale, because chemicals and polymers have difficulty penetrating the pores within the shale, making it difficult to improve the shale's overall strength.

[0007] In view of this, how to increase the expansion pressure of formation fractures at a lower construction cost and without destroying the original formation fractures, so that the formation fractures can store more high-pressure fluids or hazardous wastes without expanding, is a technical problem that urgently needs to be solved. Summary of the Invention

[0008] This application aims to solve the technical problem raised in the aforementioned background of how to increase the formation fracture expansion pressure at a low cost without destroying the original formation fractures, and proposes a method for increasing the formation fracture expansion pressure.

[0009] In order to solve the above technical problems, the technical solution adopted in this application is:

[0010] A method for increasing the expansion pressure of a formation fracture, the method comprising: sequentially or simultaneously injecting a first fluid and a second fluid into a formation fracture, or injecting a degradable capsule and a third fluid into the formation fracture; wherein the first fluid comprises at least one liquid polymer and at least one curing agent, and the second fluid is a fluid that does not undergo a curing reaction or a polymerization reaction to form a solid; the degradable capsule comprises at least one reactant, and the third fluid is a fluid that does not undergo a curing reaction or a polymerization reaction to form a solid; the reactants can undergo a curing reaction with each other and / or with the third fluid;

[0011] When a first fluid and a second fluid are sequentially injected into a formation fracture, the second fluid is used to displace the first fluid to the fracture tip of the formation fracture;

[0012] When the first fluid and the second fluid are injected into the formation fracture at the same time, the density of the first fluid is less than or greater than the density of the second fluid.

[0013] Furthermore, when the first fluid and the second fluid are sequentially injected into the formation fracture, after the second fluid is injected to displace the first fluid to the fracture tip of the formation fracture, the method further includes:

[0014] Before the fracture pressure of the formation fracture reaches the fracture expansion pressure, the injection of the second fluid into the formation fracture is stopped, and the solidification reaction of the first fluid is completed to change from liquid to solid.

[0015] Furthermore, the first fluid further comprises nanoparticles for increasing the fracture toughness and / or strength of the solid-state material formed after the solidification reaction of the first fluid.

[0016] Furthermore, before injecting the first fluid into the formation fracture, the first fluid is first heated to increase the temperature of the first fluid.

[0017] Furthermore, during the injection of the first fluid and / or the second fluid into the formation fracture, the formation fracture pressure is greater than the formation fracture closure pressure and less than the original fracture expansion pressure of the formation fracture.

[0018] Furthermore, when the first fluid and the second fluid are sequentially injected into the formation fracture, the ratio M of the viscosity of the first fluid to the viscosity of the second fluid does not exceed 10.

[0019] Furthermore, when the first fluid and the second fluid are sequentially injected into the formation fracture, a thickener is added to the second fluid to increase the viscosity of the second fluid.

[0020] Furthermore, when the first fluid and the second fluid are sequentially injected into the formation fracture, the density of the second fluid is equal to the density of the first fluid or the density of the first fluid is not less than 70% of the density of the second fluid.

[0021] Furthermore, when the first fluid and the second fluid are sequentially injected into the formation fracture, the flow rate of the injected second fluid is lower than the threshold flow rate, so that the first fluid and / or the second fluid do not generate turbulence in the wellbore or the formation fracture.

[0022] Furthermore, when the first fluid and the second fluid are sequentially injected into the formation fracture, no new fluid is injected into the formation fracture or fluid is discharged from the formation fracture while waiting for the first fluid to complete the solidification reaction.

[0023] Furthermore, after the solidification reaction of the first fluid is completed, the second fluid is discharged from the formation fracture.

[0024] Furthermore, before injecting the first fluid or the second fluid into the formation fracture, a pre-fluid containing a fluid loss preventer is injected into the formation fracture to reduce fluid loss in the formation fracture to the surrounding formation.

[0025] Furthermore, the first fluid and / or the second fluid injected into the formation fracture contains a fluid loss preventer to reduce fluid loss in the formation fracture to the surrounding formation.

[0026] Furthermore, after simultaneously injecting the first fluid and the second fluid into the formation fracture, the method further includes:

[0027] Before the fracture pressure of the formation fracture reaches the fracture expansion pressure, stopping injecting the first fluid and the second fluid into the formation fracture, and waiting for the first fluid and the second fluid to undergo gravity separation, so that the first fluid accumulates at the fracture top or bottom edge of the formation fracture;

[0028] Wait for the first fluid to complete a solidification reaction and change from a liquid state substance to a solid state substance.

[0029] Furthermore, the fracture toughness of the solid-state material is greater than the fracture toughness of the formation rock where the formation fracture is located, or / and the tensile strength of the solid-state material is greater than the tensile strength of the formation rock where the formation fracture is located, or / and the shear strength of the solid-state material is greater than the shear strength of the formation rock where the formation fracture is located, or / and the compressive strength of the solid-state material is greater than the compressive strength of the formation rock where the formation fracture is located.

[0030] Furthermore, after injecting the degradable capsules and the third fluid into the formation fracture, the method further includes:

[0031] Stop injecting the degradable capsules and continue injecting the third fluid to displace the degradable capsules to the fracture tips of the formation fractures;

[0032] After the degradable capsule is degraded at the fracture tip of the formation fracture, reactants released from the degradable capsule undergo a solidification reaction with each other and / or with the third fluid to form a solid substance.

[0033] Furthermore, when the degradable capsules and the third fluid are injected into the formation fracture, the density of the degradable capsules is less than or greater than the density of the third fluid, so that the degradable capsules gather at the top edge or bottom edge of the formation fracture; after the degradable capsules are degraded at the top edge or bottom edge of the formation fracture, the reactants released by the degradable capsules undergo a solidification reaction with each other and / or with the third fluid to form a solid substance.

[0034] Furthermore, different reactants are contained in the same degradable capsule or in different degradable capsules.

[0035] Furthermore, the reactants are in liquid or solid state in the degradable capsule.

[0036] Furthermore, after injecting the degradable capsules and the third fluid into the formation fracture, the method further includes:

[0037] Before the fracture pressure of the formation fracture reaches the fracture expansion pressure, the injection of the degradable capsule and / or the third fluid into the formation fracture is stopped.

[0038] Furthermore, the fracture toughness of the solid-state material is greater than the fracture toughness of the formation rock where the formation fracture is located, or / and the tensile strength of the solid-state material is greater than the tensile strength of the formation rock where the formation fracture is located, or / and the shear strength of the solid-state material is greater than the shear strength of the formation rock where the formation fracture is located, or / and the compressive strength of the solid-state material is greater than the compressive strength of the formation rock where the formation fracture is located.

[0039] The benefits of this application are:

[0040] According to a method for increasing the expansion pressure of formation fractures disclosed in the present application, a first fluid containing one or more liquid polymers and one or more curing agents is first injected into the formation fracture; then a second fluid is injected into the formation fracture, and the function of the second fluid is to displace the first fluid to the tip of the formation fracture. Before the fracture pressure reaches the fracture expansion pressure, the injection of the second fluid is stopped. After the first fluid solidifies, the second fluid is discharged. After solidification, the first fluid will form a solid with a strength greater than the strength of the formation rock at the fracture tip, making it difficult for the fracture to expand outward from the tip. The method disclosed in the present application can increase the fracture expansion pressure without changing the size of the formation fracture, thereby increasing the energy storage capacity and the ability to store hazardous waste of the formation fracture. The method disclosed in the present application also involves hydraulic fracturing. As a mature technology in the field of oil and gas, hydraulic fracturing has been used on a large scale, so the relevant construction supporting equipment is easy to obtain and the cost is controllable. BRIEF DESCRIPTION OF THE DRAWINGS

[0041] In order to more clearly illustrate the embodiments of the present invention or the technical solutions in the prior art, the following is a brief introduction to the drawings required for the embodiments or the description of the prior art. In all drawings, similar elements or parts are generally identified by similar reference numerals. In the drawings, the various elements or parts are not necessarily drawn according to the actual scale. Obviously, the drawings described below are some embodiments of the present invention. For those of ordinary skill in the art, other drawings can also be obtained based on these drawings without inventive work.

[0042] Figure 1 A process for increasing the formation fracture expansion pressure according to an embodiment of the present application Figure 1 .

[0043] Figure 2 This is an example of increasing the horizontal fracture expansion pressure of the formation according to the embodiment of the present application. Figure 1 .

[0044] Figure 3 A process for increasing the formation fracture expansion pressure according to an embodiment of the present application Figure 2 .

[0045] Figure 4 This is an example of increasing the vertical fracture expansion pressure of the formation according to the embodiment of the present application. Figure 2 .

[0046] Figure 5 A process for increasing the formation fracture expansion pressure according to an embodiment of the present application Figure 3 .

[0047] Figure 6 This is an example of increasing the vertical fracture expansion pressure of the formation according to the embodiment of the present application. Figure 3 . DETAILED DESCRIPTION

[0048] To make the purpose, technical solutions, and advantages of the embodiments of the present application clearer, the technical solutions in the embodiments of the present invention will be clearly and completely described below in conjunction with the accompanying drawings in the embodiments of the present invention. Obviously, the described embodiments are part of the embodiments of the present invention, not all of the embodiments. Based on the embodiments in this application, all other embodiments obtained by ordinary technicians in this field without making creative work are within the scope of protection of this application.

[0049] The "fluid" herein may be, but is not limited to, a gas, a liquid, an emulsion, a slurry, and a flow of solid particles having flow characteristics similar to that of a liquid. For example, the fluid may include a water-based liquid with chemical additives.

[0050] As used herein, a "formation" is a porous and permeable underground rock layer (e.g., shale, sandstone, carbonate, etc.) that acts as a reservoir for fluids. Typically, these fluids are water, hydrocarbons, or gases. Fluid loss control agents can be added to the fluids injected into fractures within the formation to reduce or prevent fluid loss from the fractures into the formation.

[0051] The term "hydraulic fracturing" or "fracture" or "cracking" as used herein refers to the generation and expansion of cracks in formation rocks under the action of external forces (such as high-pressure fluid).

[0052] In this article, "formation fractures" or "fractures" 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.

[0053] The term "fracture closure pressure" used in this article refers to the minimum pressure at which a fracture opens. It is equal to the in-situ stress perpendicular to the fracture plane and is typically the minimum principal stress of the formation. For horizontal fractures, the fracture closure pressure is typically equal to the vertical principal stress of the formation. For vertical fractures, the fracture closure pressure is typically equal to the minimum horizontal principal stress of the formation.

[0054] The term "wellbore" as used herein refers to a hole drilled or inserted into a formation. 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). The wellbore used to connect fractures may be vertical, horizontal, or inclined.

[0055] The “fracture width” in this article refers to the relative displacement distance between the two walls in the direction perpendicular to the fracture surface of the formation.

[0056] The "liquid polymer" in this article refers to a class of polymers that exist in liquid form at room temperature. After adding a "curing agent", they can undergo a curing reaction and turn into a solid form. Common "liquid polymers" include but are not limited to: polyurethane, polyetheramine, liquid natural rubber, liquid polybutadiene, polyimide precursor, polyetheretherketone solution, etc. Common "curing agents" include but are not limited to: ethylenediamine, triethylenetetramine, m-phenylenediamine, diaminodiphenylmethane, polyamide, modified alicyclic amine, maleic anhydride, hexahydrophthalic anhydride, methyltetrahydrophthalic anhydride, phenolic modifier, etc. Common "curing agents" can be divided into amines, acid anhydrides, phenolics, metal salts, imidazoles, polyisocyanates, and polysulfides. The time of the curing reaction is affected by the type of liquid polymer, the type of curing agent, the mixing ratio of the liquid polymer and the curing agent, and the temperature.

[0057] As used herein, "constant" or "unchanged" does not mean that the absolute change in the specified item is zero, but rather that the change in the specified item is very small, and in engineering practice, the item can be considered constant. It should also be understood that the term "equal" as used in this disclosure does not mean that the specified items are exactly the same, but rather is used to specify two items that have negligible differences in engineering practice. For example, the term "equal" in this disclosure may also mean "approximately equal."

[0058] Example 1:

[0059] The present invention provides a method for increasing the formation fracture expansion pressure. Figure 1 FIG. 1 is a flow chart of the method, which includes steps S101 to S103, which are described in detail below.

[0060] S101, injecting a first fluid into a formation fracture; wherein the first fluid comprises at least one liquid polymer and at least one curing agent;

[0061] S102, injecting a second fluid into the formation fracture to displace the first fluid to the fracture tip of the formation fracture; wherein the second fluid is a fluid that does not undergo a solidification reaction or a polymerization reaction to form a solid;

[0062] S103. Before the fracture pressure of the formation fracture reaches the fracture expansion pressure, stop injecting the second fluid into the formation fracture and wait for the first fluid to complete the solidification reaction and change from liquid to solid, thereby increasing the fracture expansion pressure of the formation fracture.

[0063] In one embodiment, Figure 2 As shown, Figure 2 An example diagram of a system 200 for injecting a first fluid 240 and a second fluid 250 into a horizontal formation fracture 230 within a formation 210 through a wellbore 220 is shown.

[0064] In the system 200, step S101 is first performed to inject a first fluid 240 into the wellbore 220, thereby increasing the pressure in the wellbore 220. When the pressure in the wellbore 220 reaches the closure pressure of the formation fracture 230, the formation fracture 230 changes from a closed state to an open state, and the first fluid 240 begins to enter the formation fracture 230. The first fluid includes one or more liquid polymers and one or more curing agents.

[0065] Next, step S102 is executed to inject a second fluid 250 into the wellbore 220. The second fluid 250 displaces the first fluid 240 to the fracture tips of the formation fractures 230. Any fluid that does not undergo a solidification reaction or polymerization reaction to form a solid can be referred to as the second fluid 250.

[0066] It should be noted that the fracture pressure can be obtained by monitoring the wellhead pressure (fracture pressure = wellhead pressure + hydrostatic pressure - friction resistance). Using the wellbore flow model, the dynamic relationship between the wellhead pressure and the fracture pressure under different injection flow rates and fluid densities can be calculated.

[0067] In other embodiments, the viscosity of the first fluid 240 is relatively high (e.g., above 2000 cP). In order to enable the second fluid 250 to have a better displacement effect on the first fluid 240 in the formation fractures 230 and the wellbore 220, avoid the occurrence of viscous fingering, reduce the residue of the first fluid 240 in areas outside the fracture tip, and avoid mixing of the first fluid and the second fluid in the wellbore 220, the ratio M of the viscosity of the first fluid 240 to the viscosity of the second fluid 250 does not exceed 10.

[0068] In other embodiments, in order to increase the viscosity of the second fluid 250, it is necessary to add a thickener to the second fluid. The thickener includes, but is not limited to, at least one natural polymer and its derivatives, and / or at least one cellulose and its derivatives, and / or at least one synthetic polymer, and / or at least one surfactant thickener, and / or at least one gel-type thickener, and / or at least one clay. Specifically, the thickener can be: natural polymer and its derivatives (such as guar gum, carboxymethyl guar gum, hydroxypropyl guar gum, xanthan gum, artemisia gum, etc.), cellulose and its derivatives (such as hydroxymethyl cellulose, carboxymethyl cellulose, carboxymethyl hydroxyethyl cellulose, hydroxyethyl cellulose, etc.), synthetic polymers (such as polyacrylamide, polyethylene oxide, acrylic acid polymer, polyvinyl alcohol, etc.), surfactant thickener, gel-type thickener (such as phenolic resin, guar gum combined with a cross-linking agent to form a gel) and clay (such as montmorillonite, bentonite, etc.).

[0069] In other embodiments, to prevent Rayleigh-Taylor instability due to density differences between the first fluid and the second fluid in the wellbore 220, and to prevent stratification of the first fluid and the second fluid in the formation fracture 230, the density of the first fluid 240 needs to be the same as or similar to the density of the second fluid 250. For example, in some embodiments, the density of the first fluid 240 cannot be less than 70% of the density of the second fluid 250.

[0070] In other embodiments, to prevent turbulence caused by excessive flow of the first fluid or the second fluid in the wellbore 220 and the formation fracture 230, thereby preventing mixing of the first and second fluids, the flow rate of the second fluid injected needs to be lower than a threshold flow rate, so that turbulence of the first fluid or the second fluid does not occur in the wellbore 220 or the formation fracture 230. 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 first fluid or the second fluid, the wellbore and fracture dimensions, and the surface roughness of the wellbore and fracture. For example, the threshold flow rate can be determined by comparing the calculated Reynolds number to determine whether it meets the critical value for turbulence.

[0071] Finally, step S103 is executed to stop injecting the second fluid 250 before the fracture pressure in the formation fracture 230 reaches the fracture propagation pressure. The process then waits for the first fluid 240 to complete its solidification reaction and become a solid. The fracture propagation pressure in the formation fracture 230 can be calculated based on the dimensions of the formation fracture 230 and the Young's modulus, Poisson's ratio, and initial fracture toughness of the rock in the formation 220. The fracture propagation pressure in the formation fracture 230 can also be determined through field testing by analyzing the relationship between injection flow rate and pressure and the pump-off pressure drop curve. The fracture propagation pressure in the formation fracture 230 can also be calculated using empirical formulas or numerical simulation methods.

[0072] It should be noted that the cessation condition for injection of the second fluid 250 only requires that the fracture pressure does not exceed the fracture propagation pressure, thereby preventing the fracture from expanding. In specific implementations, a safety threshold can be set based on different application scenarios. This safety threshold is the value of the fracture propagation pressure. For example, the safety threshold can be set to a MPA. Injection of the second fluid 250 is stopped until the fracture pressure exceeds a MPA.

[0073] To increase the fracture propagation pressure of the formation fracture 230, the fracture toughness of the solidified substance transformed by the first fluid 240 after solidification must be greater than the fracture toughness of the formation rock within the formation fracture 230, or / and the tensile strength of the solidified substance transformed by the first fluid 240 after solidification must be greater than the tensile strength of the formation rock within the formation fracture 230, or / and the shear strength of the solidified substance transformed by the first fluid 240 after solidification must be greater than the shear strength of the formation rock within the formation fracture 230, or / and the compressive strength of the solidified substance transformed by the first fluid 240 after solidification must be greater than the compressive strength of the formation rock within the formation fracture 230. Because the stress state of the formation fracture 230 varies under different geological conditions, at least one mechanical property of the formation rock, including the fracture toughness, tensile strength, shear strength, and compressive strength, can affect the fracture propagation pressure of the formation fracture 230.

[0074] The curing reaction time of the first fluid 240 is affected by the type of liquid polymer, the type of curing agent, the mixing ratio of the liquid polymer to the curing agent, and the formation temperature of the formation fracture 230. The curing reaction time can be calculated directly or indirectly from information such as experimental data, empirical formulas, and material data sheets provided by suppliers.

[0075] During the solidification reaction of the first fluid 240 , no new fluid is injected into the formation fracture 230 or fluid is discharged from the formation fracture 230 .

[0076] In other embodiments, nanoparticles that can increase the fracture toughness or strength of the first fluid after solidification are also added to the first fluid, including but not limited to carbon nanotubes, graphene, nanoclay, nanosilica, nanoalumina, nanobarium titanate, nanozinc oxide, nanocalcium carbonate and nanotitanium dioxide.

[0077] After the first fluid 240 is completely solidified at the fracture tip of the formation fracture 230, the second fluid 250 is reversed, thereby obtaining a formation fracture 230 with increased fracture expansion. Subsequently, fluid for energy storage or hazardous waste can be injected into the formation fracture 230.

[0078] In other embodiments, when the formation permeability is relatively high or the solidification reaction time of the first fluid 240 is relatively long, after the first fluid 240 is completely solidified at the crack tip of the formation crack 230, the second fluid 250 has been completely lost to the formation around the formation crack 230, and there is no need to discharge the second fluid 250.

[0079] On-site monitoring of the wellhead pressure (and calculation of the pressure in the formation fractures 230) can be used to determine whether to reverse the flow of the second fluid 250. For example, after the solidification reaction of the first fluid 240 is complete, if the pressure in the formation fractures 230 is greater than the closure stress of the formation fractures 230, then the second fluid 250 is still present in the formation fractures 230 and it is necessary to reverse the flow of the second fluid 250. If the pressure in the formation fractures 230 is less than or equal to the closure stress of the formation fractures 230, it can be inferred that the formation fractures 230 are completely closed and the second fluid 250 has completely filtered into the formation 210, and it is not necessary to reverse the flow of the second fluid 250.

[0080] In other embodiments, before injecting the first fluid 240 into the formation fracture 230, a pre-fluid containing a fluid loss preventer is injected into the formation fracture 230 to physically or chemically seal the rock pores around the formation fracture 230 to reduce the loss of fluid in the formation fracture 230 into the surrounding formation.

[0081] In other embodiments, the first fluid 240 and / or the second fluid 250 injected into the formation fracture 230 contain a fluid loss agent.

[0082] In other embodiments, the evaluation of the effect of the liquid polymer and the curing agent after the curing reaction can be performed by testing the type I fracture toughness and / or type II fracture toughness and / or type III fracture toughness of the solid material formed after the curing reaction, thereby optimizing one or more liquid polymers and one or more curing agents.

[0083] In other embodiments, the evaluation of the effect of the curing reaction of the liquid polymer and the curing agent can directly test the rock mechanical properties of the solid material formed after the curing reaction, such as compressive strength, tensile strength, shear strength, etc., so as to select one or more liquid polymers and one or more curing agents.

[0084] In other embodiments, the evaluation of the effect of the curing reaction of the liquid polymer and the curing agent can use molecular simulation methods to simulate the rock mechanical properties of the solid material formed after the curing reaction, so as to optimize one or more liquid polymers and one or more curing agents.

[0085] In other embodiments, the effect of the curing reaction of the liquid polymer and the curing agent can be evaluated by using a numerical simulation method to simulate the increase in crack expansion pressure after the curing reaction, thereby optimizing one or more liquid polymers and one or more curing agents.

[0086] In other embodiments, the optimal volume of the injected first fluid may be calculated using a numerical simulation method based on the formation fracture expansion pressure requirement and the mechanical properties of the first fluid after solidification reaction.

[0087] Example 2:

[0088] The present invention provides a method for increasing the formation fracture expansion pressure. Figure 3 FIG. 3 is a flow chart of the method, which includes steps S301 to S306, which are described in detail below.

[0089] S301. Inject a first fluid into a formation fracture; wherein the first fluid comprises at least one liquid polymer and at least one curing agent.

[0090] S302. Inject a second fluid into the formation fracture to displace the first fluid to the fracture tip of the formation fracture; wherein the second fluid is a fluid that does not undergo a solidification reaction or a polymerization reaction to generate a solid.

[0091] S303. Before the fracture pressure of the formation fracture reaches the fracture expansion pressure, stop injecting the second fluid into the formation fracture and wait for the first fluid to complete the solidification reaction and change from liquid to solid, thereby increasing the fracture expansion pressure of the formation fracture in the longitudinal direction.

[0092] S304. Simultaneously inject a first fluid and a second fluid into the formation fracture; wherein the density of the first fluid is less than or greater than the density of the second fluid.

[0093] S305. Before the fracture pressure of the formation fracture reaches the fracture expansion pressure, stop injecting the first fluid and the second fluid into the formation fracture, and wait for the first fluid and the second fluid to undergo gravity separation, so that the first fluid gathers at the fracture top or bottom edge of the formation fracture.

[0094] S306: Wait for the first fluid to complete the solidification reaction and change from liquid to solid, thereby increasing the fracture expansion pressure of the formation fracture in the height direction.

[0095] In one embodiment, Figure 4FIG. 4 shows an exemplary diagram of a system 400 including a vertical formation fracture 420 in a formation 410. A high-pressure fluid is injected into a wellbore 430 and enters the formation fracture 420 through perforations 440. When the fracture pressure within the formation fracture 420 rises to the fracture propagation pressure, the fracture propagates toward the fracture tip 450, thereby increasing the fracture length, and / or toward the fracture top 460, thereby increasing the fracture height, and / or toward the fracture bottom 470, thereby increasing the fracture height. The propagation direction of the formation fracture 420 depends on the spatial distribution of formation stress and the mechanical properties of the formation rock.

[0096] Specifically, the purpose of steps S301 to S303 is to increase the expansion pressure of the vertical formation fracture 420 toward the fracture tip 450. The working principle is consistent with steps S101 to S103 described in Example 1, so it is not repeated here.

[0097] In such Figure 4 In the illustrated system, the following steps can be used to increase the expansion pressure of a vertical formation fracture 420 toward the fracture tip 450: First, a first fluid is injected into the wellbore 430, which enters the formation fracture 420 through perforations 440. The first fluid comprises one or more liquid polymers and one or more curing agents. Subsequently, a second fluid is injected into the wellbore 430, which enters the fracture 420 through perforations 440, displacing the first fluid to the fracture tip 450 of the formation fracture 420. Any fluid that does not undergo a solidification reaction or undergoes a polymerization reaction to form a solid can be referred to as the second fluid. The injection of the second fluid is stopped before the fracture pressure in the formation fracture 420 reaches the fracture expansion pressure. Wait until the first fluid completes its solidification reaction at the fracture tip 450, transforming into a solid substance with a strength greater than that of the rock in the formation where the fracture 420 is located. If any unlost second fluid remains in the formation fracture 420, it can be drained back out of the fracture 420.

[0098] The purpose of steps S304 to S306 is to increase the expansion pressure of the formation fracture 420 extending upward along the fracture top edge 460 and / or the expansion pressure of the formation fracture 420 extending downward along the fracture bottom edge 470 .

[0099] To increase the expansion pressure of formation fracture 420 extending upward along fracture top 460, a first fluid and a second fluid are injected into wellbore 430. The first and second fluids enter fracture 420 through perforations 440. The first fluid contains one or more liquid polymers and one or more curing agents. The second fluid does not undergo a curing reaction or polymerization reaction to form a solid, and the density of the first fluid is lower than that of the second fluid. The injection of the first and second fluids is stopped before the fracture pressure in formation fracture 420 reaches the fracture expansion pressure. Gravity segregation of the first and second fluids is allowed. Since the first fluid has a lower density than the second fluid, it will spontaneously migrate upward and accumulate near fracture top 460 of fracture 420. Further, the first fluid solidifies and transforms into a solid substance whose strength exceeds that of the rock in the formation where fracture 420 is located. If any unleached second fluid remains in formation fracture 420, it can be drained back out of the fracture 420. To increase the downward expansion pressure of formation fracture 420 along fracture bottom 470, a first fluid and a second fluid are injected into wellbore 430. The first and second fluids enter formation fracture 420 through perforations 440. The first fluid contains one or more liquid polymers and one or more curing agents. The second fluid does not undergo a curing reaction or polymerization reaction to form a solid, and the density of the first fluid is greater than that of the second fluid. The injection of the first and second fluids is stopped before the fracture pressure in formation fracture 420 reaches the fracture expansion pressure. Gravity segregation of the first and second fluids is allowed. Due to its greater density than the second fluid, the first fluid will spontaneously migrate downward and accumulate near fracture bottom 470 of fracture 420. Further, the first fluid solidifies and transforms into a solid substance whose strength exceeds that of the rock in the formation where fracture 420 is located. If any unlost second fluid remains in formation fracture 420, it can be drained back out of the fracture 420.

[0100] By controlling the injection sequence and fluid density of the first fluid and the second fluid, the position of the first fluid in the crack after it completes the solidification reaction and turns into a solid substance can be controlled, thereby increasing the expansion pressure of the crack in different directions.

[0101] In other embodiments, the first fluid and the second fluid may be miscible or immiscible.

[0102] In other embodiments, in order to reduce the viscosity of the first fluid, the first fluid is heated before being injected into the wellbore 430 to increase the temperature of the first fluid.

[0103] In other embodiments, in order to reduce the amount of heat transferred from the first fluid to the second fluid, the second fluid is heated before being injected into the wellbore 430 to increase the temperature of the second fluid.

[0104] In other embodiments, since the expansion pressure of the formation fracture is determined by the direction where the expansion pressure is the smallest, increasing the expansion pressure of the formation fracture only requires increasing the expansion pressure in a certain direction of the formation fracture using the first fluid.

[0105] In other embodiments, the formation fractures have complex geometric shapes, requiring the first fluid to gather and solidify at multiple fracture tips or fracture top edges or fracture bottom edges.

[0106] In some embodiments, because the curing reaction rate of the reactants (such as polymers and curing agents) is too fast to be pre-configured or mixed into a liquid on the ground, or the viscosity of the liquid polymer is too high and construction is difficult, the reactants can be placed in degradable (also referred to as soluble) capsules (referring to containers of any shape that can store liquids or powders) and injected into the formation cracks. The degradable capsules can be made of materials such as water-soluble polymers, degradable 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 contacting water, thereby allowing the reactants in the capsule to be released from the capsule 30 to 60 minutes after entering the formation.

[0107] Example 3:

[0108] The present invention provides a method for increasing the formation fracture expansion pressure. Figure 5 FIG. 5 is a flow chart of the method, which includes steps S501 to S506, which are described in detail below.

[0109] S501. Injecting a degradable capsule and a third fluid into a formation fracture; wherein the degradable capsule contains at least one reactant, and the third fluid is a fluid that does not undergo a solidification reaction or a polymerization reaction to form a solid;

[0110] S502: Stop injecting the degradable capsules into the formation fractures and continue injecting the third fluid to displace the degradable capsules to the fracture tips of the formation fractures.

[0111] S503. Before the fracture pressure of the formation fracture reaches the fracture expansion pressure, stop injecting the third fluid into the formation fracture, wait for the degradable capsule to degrade at the fracture tip of the formation fracture, and then react the reactants released by the degradable capsule with each other and / or with the third fluid to solidify to form a solid substance, thereby increasing the fracture expansion pressure of the formation fracture in the longitudinal direction.

[0112] S504. Injecting degradable capsules and a third fluid into the formation fracture; wherein the density of the degradable capsules is less than or greater than the density of the third fluid.

[0113] S505. Before the fracture pressure of the formation fracture reaches the fracture expansion pressure, stop injecting the degradable capsules and the third fluid into the formation fracture, and wait for the degradable capsules to gather at the top or bottom edge of the formation fracture due to the density difference between the degradable capsules and the third fluid.

[0114] S506: After the degradable capsule degrades at the top or bottom edge of the formation fracture, the released reactants react with each other and / or with the third fluid to form a solid substance, thereby increasing the fracture expansion pressure of the formation fracture in the vertical direction.

[0115] In one embodiment, Figure 6 FIG. 6 illustrates an exemplary system 600 including a vertical formation fracture 620 in a formation 610. High-pressure fluid is injected into a wellbore 630 and enters the formation fracture 620 through perforations 640. When the fracture pressure within the formation fracture 620 rises to the fracture propagation pressure, the fracture propagates toward the fracture tip 650, thereby increasing the fracture length, and / or toward the fracture top 660, thereby increasing the fracture height, and / or toward the fracture bottom 670, thereby increasing the fracture height. The propagation direction of the formation fracture 620 depends on the spatial distribution of formation stress and the mechanical properties of the formation rock.

[0116] In such Figure 6 In the system shown, the expansion pressure of the formation fracture 620 toward the fracture tip 650 can be increased specifically by the following steps: first, inject the degradable capsule 680 and the third fluid into the wellbore 630, and the degradable capsule 680 and the third fluid enter the formation fracture 420. The degradable capsule contains at least one reactant, and the third fluid is a fluid that does not undergo a solidification reaction or a polymerization reaction to form a solid. Then, the injection of the degradable capsule 680 into the formation fracture is stopped and the injection of the third fluid is continued to displace the degradable capsule to the fracture tip 650 of the formation fracture. Before the fracture pressure of the formation fracture 420 reaches the fracture expansion pressure, the injection of the third fluid is stopped. After waiting for the degradable capsule 680 to degrade at the fracture tip 650 of the formation fracture 620, the reactants released by the degradable capsule 680 undergo a solidification reaction with each other and / or the reactants and the third fluid to form a solid state substance, thereby increasing the fracture expansion pressure of the formation fracture 620 in the length direction. In the example Figure 6In the illustrated system, the vertical expansion pressure of a formation fracture 620 can be increased by the following steps: Degradable capsules 680 and a third fluid are injected into the formation fracture 620; wherein the density of the degradable capsules is less than or greater than the density of the third fluid. Before the fracture pressure of the formation fracture 620 reaches the fracture expansion pressure, the injection of the degradable capsules 680 and the third fluid into the formation fracture 620 is stopped, and the density difference between the degradable capsules 680 and the third fluid causes the degradable capsules 680 to accumulate at the top edge 660 or bottom edge 670 of the formation fracture 620. After the degradable capsules 680 degrade at the top edge 660 or bottom edge 670 of the formation fracture 620, the released reactants react with each other and / or with the third fluid to form a solid substance, thereby increasing the vertical expansion pressure of the formation fracture 620.

[0117] In some embodiments, a degradable capsule and a third fluid are injected into a formation fracture. The degradable capsule contains at least one reactant, and the third fluid is a fluid that does not undergo a solidification reaction or polymerization reaction to form a solid. The injection of the degradable capsule is stopped and the third fluid is continued, displacing the degradable capsule to the fracture tip of the formation fracture. After the degradable capsule degrades at the fracture tip, the reactants released from the degradable capsule undergo a solidification reaction with each other and / or with the third fluid, forming a solid substance.

[0118] In some embodiments, the degradable capsules and a third fluid are injected into a formation fracture, wherein the density of the degradable capsules is less than or greater than the density of the third fluid, so that the degradable capsules accumulate at the top or bottom edge of the formation fracture. After the degradable capsules degrade at the top or bottom edge of the formation fracture, reactants released from the degradable capsules undergo a solidification reaction with each other and / or with the third fluid to form a solid substance.

[0119] In some embodiments, different reactants can be contained in the same degradable capsule; in some embodiments, different reactants can be 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] The reactants in the degradable capsule can be in liquid or solid form (including powder). The degradable capsule can also contain other substances for adjusting the density of the capsule.

[0121] The above embodiments are only used to illustrate the technical solutions of the present application, rather than to limit them. Although the present invention has been described in detail with reference to the above embodiments, those skilled in the art should understand that they can still modify the technical solutions described in the above embodiments, or make equivalent replacements for some or all of the technical features therein. These modifications or replacements do not deviate the essence of the corresponding technical solutions from the scope of the technical solutions of the embodiments of the present invention, and they should all be included in the scope of the claims and description of the present invention.

Claims

1. A method for increasing the expansion pressure of a formation fracture, characterized in that: The method comprises: A first fluid and a second fluid are sequentially or simultaneously injected into a formation fracture, or a degradable capsule and a third fluid are injected into the formation fracture; wherein the first fluid comprises at least one liquid polymer and at least one curing agent, and the second fluid is a fluid that does not undergo a curing reaction or a polymerization reaction to form a solid; the degradable capsule comprises at least one reactant, and the third fluid is a fluid that does not undergo a curing reaction or a polymerization reaction to form a solid; the reactants can undergo a curing reaction with each other and / or with the third fluid; When a first fluid and a second fluid are sequentially injected into a formation fracture, the second fluid is used to displace the first fluid to the fracture tip of the formation fracture; When the first fluid and the second fluid are injected into the formation fracture at the same time, the density of the first fluid is less than or greater than the density of the second fluid.

2. The method according to claim 1, characterized in that When sequentially injecting a first fluid and a second fluid into a formation fracture, after injecting the second fluid to displace the first fluid to the fracture tip of the formation fracture, the method further includes: Before the fracture pressure of the formation fracture reaches the fracture expansion pressure, the injection of the second fluid into the formation fracture is stopped, and the solidification reaction of the first fluid is completed to change from liquid to solid.

3. The method according to claim 1, characterized in that The first fluid further comprises nanoparticles for increasing the fracture toughness and / or strength of the solid state material formed after the solidification reaction of the first fluid.

4. The method according to claim 1, wherein Before injecting the first fluid into the formation fracture, the first fluid is first heated to increase the temperature of the first fluid.

5. The method according to claim 1, wherein During the injection of the first fluid and / or the second fluid into the formation fracture, the formation fracture pressure is greater than the formation fracture closure pressure and less than the original fracture expansion pressure of the formation fracture.

6. The method according to claim 1, characterized in that When the first fluid and the second fluid are sequentially injected into the formation fracture, the ratio M of the viscosity of the first fluid to the viscosity of the second fluid does not exceed 10.

7. The method according to claim 1, characterized in that When the first fluid and the second fluid are sequentially injected into the formation fracture, a thickener is added to the second fluid to increase the viscosity of the second fluid.

8. The method according to claim 1, characterized in that When the first fluid and the second fluid are sequentially injected into the formation fracture, the density of the second fluid is equal to that of the first fluid or the density of the first fluid is not less than 70% of the density of the second fluid.

9. The method according to claim 1, characterized in that When the first fluid and the second fluid are sequentially injected into the formation fracture, the flow rate of the injected second fluid is lower than the threshold flow rate, so that the first fluid and / or the second fluid do not generate turbulent flow in the wellbore or the formation fracture.

10. The method according to claim 1, characterized in that When the first fluid and the second fluid are sequentially injected into the formation fracture, no new fluid is injected into the formation fracture or fluid is discharged from the formation fracture during the period of waiting for the first fluid to complete the solidification reaction.

11. The method according to claim 1, wherein After the solidification reaction of the first fluid is completed, the second fluid is discharged from the formation fracture.

12. The method according to claim 1, characterized in that Before injecting the first fluid, the second fluid or the third fluid into the formation fracture, a pre-fluid containing a fluid loss preventer is injected into the formation fracture to reduce the fluid loss in the formation fracture to the surrounding formation.

13. The method according to claim 1, wherein The first fluid and / or the second fluid or the third fluid injected into the formation fracture contains a fluid loss preventer, so as to reduce the fluid loss in the formation fracture to the surrounding formation.

14. The method according to claim 1, wherein After simultaneously injecting the first fluid and the second fluid into the formation fracture, the method further includes: Before the fracture pressure of the formation fracture reaches the fracture expansion pressure, stopping injecting the first fluid and the second fluid into the formation fracture, and waiting for the first fluid and the second fluid to undergo gravity separation, so that the first fluid accumulates at the fracture top or bottom edge of the formation fracture; Wait for the first fluid to complete a solidification reaction and change from a liquid state substance to a solid state substance.

15. The method according to claim 2 or 14, characterized in that The fracture toughness of the solid-state material is greater than the fracture toughness of the formation rock where the formation fracture is located, or / and the tensile strength of the solid-state material is greater than the tensile strength of the formation rock where the formation fracture is located, or / and the shear strength of the solid-state material is greater than the shear strength of the formation rock where the formation fracture is located, or / and the compressive strength of the solid-state material is greater than the compressive strength of the formation rock where the formation fracture is located.

16. The method according to claim 1, wherein After injecting the degradable capsules and the third fluid into the formation fracture, the method further includes: Stop injecting the degradable capsules and continue injecting the third fluid to displace the degradable capsules to the fracture tips of the formation fractures; After the degradable capsule is degraded at the fracture tip of the formation fracture, reactants released from the degradable capsule undergo a solidification reaction with each other and / or with the third fluid to form a solid substance.

17. The method according to claim 1, wherein When the degradable capsules and the third fluid are injected into the formation fracture, the density of the degradable capsules is less than or greater than the density of the third fluid, so that the degradable capsules are gathered at the top edge or bottom edge of the formation fracture; After the degradable capsule is degraded at the top edge or bottom edge of the formation fracture, reactants released from the degradable capsule undergo a solidification reaction with each other and / or with the third fluid to form a solid substance.

18. The method according to claim 16 or 17, characterized in that Different reactants are contained in the same degradable capsule or respectively contained in different degradable capsules.

19. The method according to claim 16 or 17, characterized in that The reactants are in liquid or solid state in the degradable capsule.

20. The method according to claim 16 or 17, characterized in that After injecting the degradable capsules and the third fluid into the formation fracture, the method further includes: Before the fracture pressure of the formation fracture reaches the fracture expansion pressure, the injection of the degradable capsule and / or the third fluid into the formation fracture is stopped.

21. The method according to claim 16 or 17, characterized in that The fracture toughness of the solid-state material is greater than the fracture toughness of the formation rock where the formation fracture is located, or / and the tensile strength of the solid-state material is greater than the tensile strength of the formation rock where the formation fracture is located, or / and the shear strength of the solid-state material is greater than the shear strength of the formation rock where the formation fracture is located, or / and the compressive strength of the solid-state material is greater than the compressive strength of the formation rock where the formation fracture is located.

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