Method and system for controlling formation fracture propagation direction

Abstract

According to the method and system for controlling the formation fracture propagation direction, first fluid used for fracturing construction is configured in the mode that the fluid pressure gradient at the fracture bottom of the formation fracture is higher than the formation fracture pressure gradient at the position, corresponding to the depth of the fracture bottom, of the formation, and therefore spontaneous downward propagation of the formation fracture can be controlled; therefore, deeper and higher-temperature geothermal resources or other energy can be obtained while the drilling depth is not increased. Meanwhile, configuration of the fluid pressure gradient of the first fluid used for fracturing construction is achieved by adding the weighting agent with the small particle size into the first fluid, so that the density of the first fluid can be effectively improved, and then adjustment and configuration of the fluid pressure gradient of the first fluid are achieved.

Description

Technical Field

[0001] The present invention belongs to the field of geothermal energy mining technology, and particularly relates to a method and system capable of controlling the expansion direction of formation cracks, as well as a method for storing and releasing energy and / or mining geothermal energy by using the method and system of the present invention to control the downward expansion of formation cracks to generate formation cracks. Background Art

[0002] Geothermal energy is a clean, renewable, and stable energy source, crucial for promoting sustainable development and reducing carbon emissions. As a direct harnessing of heat from within the Earth's crust, geothermal energy can provide long-term, reliable electricity, heating, and cooling solutions, making it particularly suitable for district heating systems and remote areas. The development of geothermal energy can help diversify the energy mix, alleviate energy crises, contribute to achieving global climate goals, and provide a green energy guarantee for the future.

[0003] A key factor limiting the utilization of geothermal energy is the high cost of drilling. Generally, the deeper the formation, the higher the temperature. Therefore, to access high-temperature geothermal resources, drilling depth must be increased, and drilling costs rise sharply with increasing depth. Accessing deeper geothermal resources without increasing drilling depth is a pressing challenge.

[0004] Traditional oil and gas wells or geothermal well hydraulic fracturing require drilling to the target formation (such as oil and gas reservoirs or hot dry rock reservoirs), and then hydraulic fracturing construction is carried out in the target formation to create formation fractures. A small amount of proppant is usually added to the fracturing fluid to support the closed formation fractures and improve the conductivity of the fractures (geothermal wells usually do not add proppant or only add a small amount of proppant with a concentration of less than 1.5ppg). Due to the low permeability of traditional oil and gas reservoirs or hot dry rocks, the density of the water-based fracturing mixture is usually 1000kg / m 3 Up to 1200kg / m 3 When no wellhead pressure is applied, the pressure gradient of the water-based fracturing mixture is usually between 0.00981MPa / m and 0.01177MPa / m, while the fracture gradient of the formation rock is usually between 0.015MPa / m and 0.03MPa / m. The effect of the density of the fracturing fluid on the height of the formation fracture is very limited. If a foam-based fluid (such as carbon dioxide foam, nitrogen foam, etc.) is used, the density of the fracturing fluid will be lower. Therefore, in conventional hydraulic fracturing methods, the extension height of the formation fracture is mainly controlled by the ground stress. Since the ground stress usually increases with increasing depth, hydraulic fracturing fractures tend to expand upward and will not spontaneously expand downward. The extension height of the formation fracture can be affected by changing the viscosity of the fracturing fluid and the construction displacement, but the degree of influence is very limited.

[0005] In view of this, there is an urgent need for a geothermal energy mining method that can reduce the cost of geothermal energy development and reduce the drilling depth. Summary of the Invention

[0006] In view of this, the present invention provides a method and system capable of controlling the downward expansion of cracks to produce formation cracks, as well as a method of storing and releasing energy and / or extracting geothermal energy using the method and system capable of controlling the downward expansion of cracks to produce formation cracks. The method can control the spontaneous downward expansion of cracks to produce formation cracks, thereby enabling the acquisition of deeper and higher-temperature geothermal resources and other energy without increasing the drilling depth.

[0007] The first aspect of the present invention discloses a method for controlling the downward expansion of cracks to produce formation cracks, including step S1, based on hydraulic fracturing construction, injecting a first fluid into a wellbore reaching the formation to produce formation cracks; wherein the fluid pressure gradient of the first fluid at the bottom of the formation cracks is configured to be higher than the formation fracture pressure gradient of the formation at the corresponding depth at the bottom of the cracks, so that the formation cracks expand downward.

[0008] The wellbore can be a vertical well, an inclined well, or a horizontal well. The pressure gradient of the first fluid at the bottom of the fracture can be obtained through theoretical models, numerical calculations, empirical formulas, and other methods. The formation breakdown pressure gradient is a key parameter in drilling and fracturing design. The formation breakdown gradient at different depths can be obtained through various methods, such as field measurements (overflow tests, formation integrity tests, small-scale fracturing tests, step-by-step pressurization tests, etc.), empirical formulas, rock mechanics model equations, logging data, numerical modeling, and other methods.

[0009] When the fluid pressure gradient of the first fluid at the bottom of the fracture is greater than the fracture pressure gradient of the formation at the corresponding depth at the bottom of the fracture, the fracture will expand downward. This can control the spontaneous downward expansion of the formation fracture, thereby obtaining deeper and higher-temperature geothermal resources or other energy without increasing drilling depth. For example, the stress potential energy accumulated by the fluid working to overcome the fracture closure pressure and / or the elastic deformation potential energy accumulated by driving the formation rock to undergo elastic deformation and / or the compression potential energy accumulated by the compressed fluid due to the increased pressure in the overall space formed by the target wellbore and the formation fracture.

[0010] According to the method disclosed in the first aspect of the present invention, the first fluid is constructed as a liquid fluid with a weighting agent added to a basic fracturing fluid, wherein the weighting agent is configured to increase the density of the first fluid so that the fluid pressure gradient of the first fluid at the bottom of the fracture of the formation is higher than the formation fracture pressure gradient of the formation. It is particularly preferred that the density of the first fluid is configured to be higher than 1200 kg / m3; the weighting agent is a granular material, and its particle size is configured to be less than 200 microns. Preferably, in the present invention, only granular materials with a particle size of less than 200 microns can be used as weighting agents to achieve the configuration of the density of the first fluid. Of course, those skilled in the art can also understand that the granular materials with a diameter of less than 200 microns as weighting agents in the present invention are also used together with a small amount of large-particle proppants to achieve the purpose of the present invention. This is also within the scope of protection of the present invention, and the present invention does not exclude this.

[0011] According to the method disclosed in the first aspect of the present invention, the weighting agent includes: at least one ceramsite, and / or at least one resin, and / or at least one quartz sand, and / or at least one barite, and / or at least one hematite, and / or at least one ilmenite, and / or at least one manganese ore, and / or at least one calcium carbonate, and / or at least one magnesia-alumina-iron spinel, and / or at least one metal oxide, and / or at least one silicate, and / or at least one lead ore, and / or at least one fusible alloy.

[0012] While ceramsite or quartz sand is commonly added to fracturing fluids in conventional hydraulic fracturing, the ceramsite or quartz sand used in conventional hydraulic fracturing, due to its relatively large particle size (typically between 0.85 mm and 0.42 mm), is intended to function as a proppant to close the fracture, rather than as a weighting agent to increase the density of the first fluid as described in this application. In other words, conventional hydraulic fracturing does not involve adding a weighting agent to the fracturing fluid to increase fluid density as described in this application.

[0013] Specifically, if the density of the first fluid needs to be increased to 1200 kg / m³ to 1800 kg / m³ or above, based on the ceramsite or quartz sand used in conventional hydraulic fracturing, which typically has a density between 0.85 mm and 0.42 mm, the added concentration of ceramsite or quartz sand needs to exceed 38 ppg to 154 ppg or above. This far exceeds the sand-carrying capacity of the fracturing fluid, because the high concentration of ceramsite or quartz sand can cause crack blockage or difficulty in migration. In other words, existing ceramsite or quartz sand proppants cannot be used alone as the weighting agent described in the present invention. Therefore, the present invention specifically reduces the particle size of ceramsite or quartz sand to below 200 microns and uses it as a weighting agent, thereby increasing the density of the first fluid while avoiding the problem of crack blockage or difficulty in migration caused by excessively high weighting agent concentration. This further achieves the purpose of the invention of configuring the fluid pressure gradient of the first fluid at the bottom of the fracture in the formation to be higher than the formation breakdown pressure gradient at the corresponding depth of the formation at the fracture bottom, so as to cause the formation fracture to expand downward. The prior art does not have a technical solution for increasing the density of the first fluid to achieve downward expansion of the fracture, nor does it have a technical suggestion for increasing the density of the fracturing fluid by reducing the particle size to below 200 microns to serve as a weighting agent.

[0014] According to the method disclosed in the first aspect of the present invention, in step S1, the type and / or quality of the weighting agent added to the first fluid can be adjusted in real time to keep the fluid pressure gradient of the first fluid higher than the formation fracture pressure gradient.

[0015] Specifically, the pressure gradient of the first fluid at the bottom of the crack is calculated in real time, and the data of the formation fracture pressure gradient at the depth corresponding to the bottom of the crack are compared to determine whether the type and / or mass of the weighting agent added to the first fluid needs to be adjusted. When it is determined to be yes, the type and / or mass of the weighting agent added to the first fluid is adjusted based on the change data of the formation fracture pressure gradient (the formation fracture pressure gradient will change with depth) to increase the density and fluid pressure gradient of the first fluid; and / or, whether the formation fracture is expanding downward is monitored in real time. When it is detected that the formation fracture is not expanding downward, the type and / or mass of the weighting agent added to the first fluid is adjusted to increase the density and fluid pressure gradient of the first fluid. Among them, those skilled in the art can understand that the formation fracture pressure gradient does not need to be monitored in real time, because the formation fracture pressure can be obtained in advance after drilling and logging; in some embodiments, the fracture pressure gradient of the formation at different depths can be predicted by using a mechanical model, empirical formula or numerical simulation method such as the Hubbert-Willis theory, combined with the change in deep stress gradient; the formation fracture pressure obtained or predicted at this time is collected and stored for comparison with the real-time calculated pressure gradient of the first fluid at the bottom of the fracture, and then a judgment is made as to whether the type and / or quality of the weighting agent added to the first fluid needs to be adjusted.

[0016] This enables real-time adjustment of the type and / or quality of the weighting agent based on real-time changes in the formation fracture pressure gradient, so that the density of the first fluid can meet working requirements.

[0017] According to the method disclosed in the first aspect of the present invention, it also includes step S2, judging whether the fracture parameters of the formation fracture have reached a threshold value. If not, continue to inject the first fluid into the wellbore; if the threshold value has been reached, stop injecting and reverse the first fluid.

[0018] According to the method disclosed in the first aspect of the present invention, the fracture parameters include at least one of the following: the depth of the formation fracture extending downward, the height of the formation fracture, the length of the formation fracture, the three-dimensional size of the formation fracture and the volume of the formation fracture.

[0019] The second aspect of the present invention also discloses a system capable of controlling the downward expansion of cracks to produce formation cracks, including a hydraulic fracturing device, which is used to inject a first fluid into a wellbore reaching the formation based on hydraulic fracturing construction to produce formation cracks; it also includes a first fluid generating unit, which is used to configure the first fluid and configure the fluid pressure gradient of the first fluid at the bottom of the formation crack to be higher than the formation fracture pressure gradient of the formation at the corresponding depth at the bottom of the crack, so that the formation cracks expand downward; the first fluid generating unit is connected to the hydraulic fracturing device to supply the first fluid into the hydraulic fracturing device for hydraulic fracturing construction.

[0020] According to the system disclosed in the second aspect of the present invention, the first fluid generating unit is constructed to be able to add a weighting agent to the basic fracturing fluid to form a first fluid, wherein the weighting agent is configured to be able to increase the density of the first fluid so that the fluid pressure gradient of the first fluid at the bottom of the fracture of the formation is higher than the formation fracture pressure gradient of the formation.

[0021] According to the system disclosed in the second aspect of the present invention, it also includes a weighting agent adjustment unit, which is constructed to be able to adjust the type and / or quality of the weighting agent in real time so that the fluid pressure gradient of the first fluid is maintained higher than the formation fracture pressure gradient; the weighting agent adjustment unit is configured as a part of the first fluid generating unit, or the weighting agent adjustment unit is configured as a component independent of the first fluid generating unit, and supplies the weighting agent of the adjusted type and / or quality into the first fluid generating unit.

[0022] According to the system disclosed in the second aspect of the present invention, it also includes a calculation unit, which is configured to calculate the pressure gradient of the first fluid at the bottom of the crack in real time, and compare it with the data of the formation fracture pressure gradient at the corresponding depth of the formation crack, to determine whether the type and / or mass of the weighting agent added to the first fluid needs to be adjusted; when it is determined that the type and / or mass of the weighting agent needs to be adjusted, the weighting agent adjustment unit can receive a control instruction and adjust the type and / or mass of the weighting agent added to the first fluid to increase the density and fluid pressure gradient of the first fluid; and / or, the system also includes a crack expansion monitoring unit, which is configured to monitor in real time whether the formation crack is expanding downward; when it is detected that the formation crack is not expanding downward, the weighting agent adjustment unit can receive a control instruction and adjust the type and / or mass of the weighting agent added to the first fluid to increase the density and fluid pressure gradient of the first fluid.

[0023] According to the system disclosed in the second aspect of the present invention, the density of the first fluid is configured to be higher than 1200 kg / m3; the weighting agent is a granular material, and its particle size is configured to be less than 200 microns.

[0024] According to the system disclosed in the second aspect of the present invention, the weighting agent includes: at least one ceramsite, and / or at least one resin, and / or at least one quartz sand, and / or at least one barite, and / or at least one hematite, and / or at least one calcium carbonate, and / or at least one magnesia-alumina-iron spinel, and / or at least one metal oxide, and / or at least one silicate, and / or at least one lead ore, and / or at least one fusible alloy.

[0025] The third aspect of the present invention further discloses a method for storing and releasing energy through formation fractures, comprising the following steps:

[0026] E1, conducting hydraulic fracturing operations in the target wellbore to create formation fractures and / or open existing formation fractures;

[0027] E2, injecting high-pressure fluid into the formation fractures to increase the width of the formation fractures, thereby generating and storing elastic deformation energy of the formation rock and / or compression potential energy of the high-pressure fluid and / or geothermal energy obtained by increasing the temperature of the high-pressure fluid during heat exchange with the formation;

[0028] E3, discharges high-pressure fluid and releases energy during the discharge process;

[0029] The step E1 is achieved by the method disclosed in the first aspect of the present invention capable of causing cracks to expand downward to generate formation cracks, or by the system disclosed in the second aspect of the present invention capable of causing cracks to expand downward to generate formation cracks.

[0030] In step E3, at least one of the kinetic energy, compression potential energy and thermal energy of the discharged high-pressure fluid is used to generate electricity during the energy release process.

[0031] Beneficial effects: In the method and system disclosed in the present invention that can control the downward expansion of cracks to produce formation cracks, the first fluid used for fracturing construction is configured so that the fluid pressure gradient at the bottom of the crack of the formation is higher than the formation fracture pressure gradient of the formation at the corresponding depth at the bottom of the crack. Based on this, the spontaneous downward expansion of the formation crack can be controlled, so that deeper and higher temperature geothermal resources or other energy can be obtained without increasing the drilling depth.

[0032] In a further preferred embodiment, the configuration of the fluid pressure gradient of the first fluid used for fracturing construction is achieved by adding a weighting agent with a smaller particle size to the first fluid, which can effectively increase the density of the first fluid, thereby adjusting and configuring the fluid pressure gradient of the first fluid.

[0033] The method and system for controlling the downward expansion of fractures to generate formation fractures and the energy storage and release method of the present invention are disclosed in detail below with reference to the embodiments shown in the accompanying drawings and the accompanying reference numerals. BRIEF DESCRIPTION OF THE DRAWINGS

[0034] Figure 1 A flow chart showing the steps of the method for controlling the downward expansion of fractures to generate formation fractures in the present invention is shown.

[0035] Figure 2 A schematic diagram of a system capable of controlling the downward expansion of fractures to generate formation fractures in the present invention is shown.

[0036] Figure 3 A flow chart showing the steps of the method for storing and releasing energy through formation fractures in the present invention is shown. DETAILED DESCRIPTION

[0037] It should be noted that "fluid" herein can include, but is not limited to, gases, liquids, emulsions, slurries, and flows of solid particles with flow characteristics similar to those of liquids. For example, fluids can include water-based liquids with chemical additives; they can also be compressible gases such as carbon dioxide, air, nitrogen, and gas mixtures. Fluids can be in a gaseous, liquid, or supercritical state.

[0038] A "formation" herein is an underground porous and permeable rock formation (eg, a shale formation, a sandstone formation, a carbonate formation, a hot dry rock formation, etc.) that can serve as a storage space for fluids.

[0039] 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).

[0040] "Formation fractures" or "fractures" herein are open cracks in rock created by hydraulic fracturing, or natural fractures or faults opened by hydraulic fracturing. 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.

[0041] 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.

[0042] Furthermore, in this article, the wellbore may be a vertical well, an inclined well, or a horizontal well; and the wellbore may be an abandoned oil and gas well; the abandoned oil and gas well may be one in which the original perforations are plugged and then converted into an energy storage well or a geothermal well.

[0043] 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."

[0044] 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.

[0045] The term "fracture pressure" or "intra-fracture pressure" used in this article refers to the average pressure within formation fractures. Fracture pressure can be determined by monitoring wellhead pressure (i.e., fracture pressure = wellhead pressure + hydrostatic pressure - frictional resistance). Using a wellbore flow model, the dynamic relationship between wellhead pressure and fracture pressure can be calculated under varying injection rates and fluid density / temperature conditions.

[0046] The “fracture expansion pressure” in this article refers to the pressure at which formation fractures begin to expand along the length or height direction, which is greater than the “fracture closure pressure”.

[0047] In this article, "fluid pressure gradient" refers to the ratio of the fluid pressure at a certain depth to the vertical distance from that depth to the surface, while "formation fracture pressure gradient" refers to the ratio of the minimum fluid pressure required to fracture a formation rock at a certain depth to the vertical distance from that depth to the surface. The phrase "the fluid pressure gradient of the first fluid at the bottom of a formation fracture is configured to be higher than the formation fracture pressure gradient of the formation at the corresponding depth at the fracture bottom" is equivalent to "the fluid pressure of the first fluid at the bottom of the formation fracture is configured to be higher than the formation fracture pressure of the formation at the corresponding depth at the fracture bottom."

[0048] The following will clearly and completely describe the technical solutions in the embodiments of the present invention in conjunction with the drawings in the embodiments of the present invention. Obviously, the described embodiments 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 work are within the scope of protection of the present invention. It should be noted that the embodiments in this application and the features in the embodiments can be combined with each other unless there is a conflict.

[0049] During conventional hydraulic fracturing, the height of formation fractures is primarily controlled by in-situ stress. Because in-situ stress generally increases with depth, hydraulically induced fractures tend to propagate upward and do not spontaneously propagate downward. While the height of formation fractures can be influenced by varying the viscosity of the fracturing fluid and the flow rate, the effect is very limited.

[0050] Therefore, in order to solve the problem in the prior art that formation cracks cannot spontaneously expand downward during hydraulic fracturing construction, the present invention provides a method and system that can expand cracks downward to generate formation cracks.

[0051] Example 1

[0052] Figure 1 The flowchart of the method for making the cracks extend downward to generate the formation cracks in the present invention is shown. Figure 1 As shown, the method of the present invention comprises the following steps:

[0053] S1, based on hydraulic fracturing construction, injecting a first fluid into a wellbore reaching the formation to generate formation fractures; wherein the fluid pressure gradient of the first fluid at the bottom of the formation fracture is configured to be higher than the formation fracture pressure gradient of the formation at the corresponding depth at the bottom of the fracture, so that the formation fracture expands downward.

[0054] Among them, generating formation fractures can be for opening existing formation fractures or for creating new formation fractures. The wellbore can be above the target formation or target depth. When the target formation or target depth is thicker, the target wellbore can also enter the upper part of the target formation or target depth. The pressure gradient of the first fluid at the bottom of the fracture can be obtained by theoretical models, numerical calculations, empirical formulas and the like. The formation fracture pressure gradient is a key parameter in drilling and fracturing design. The formation fracture gradient at different depths can be obtained by a variety of methods, such as through field measurements (overflow tests, formation integrity tests, small-scale fracturing tests, step-by-step pressurization tests, etc.), empirical formulas, rock mechanics model equations, logging data, numerical modeling and the like.

[0055] In a particularly preferred embodiment, the first fluid is constructed as a fluid having a weighting agent added to a basic fracturing fluid, wherein the weighting agent is configured to increase the density of the first fluid so that the fluid pressure gradient of the first fluid at the bottom of the fracture of the formation is higher than the formation fracture gradient of the formation.

[0056] The pressure gradient of the first fluid at the bottom of the fracture can be obtained through theoretical models, numerical calculations, empirical formulas, etc. If the frictional resistance of the first fluid in the pipe and the fracture is ignored, the pressure gradient of the first fluid at the bottom of the fracture can be calculated by the following formula:

[0057]

[0058] Where: P1 is the wellhead pressure; H is the vertical distance from the bottom of the fracture to the surface; ρ is the average density of the first fluid in the wellbore and fracture, which is affected by the mass and density of the added weighting agent; g is the gravitational acceleration constant.

[0059] When the pressure gradient of the first fluid at the bottom of the fracture is greater than the formation fracture gradient at the corresponding depth at the bottom of the fracture, the fracture will expand downward.

[0060] In a particularly preferred embodiment, the density of the first fluid is configured to be 1200 kg / m3-1800 kg / m3; the weighting agent is a granular material, and its particle size is configured to be less than 200 microns.

[0061] While ceramsite or quartz sand is commonly added to fracturing fluids in conventional hydraulic fracturing, the ceramsite or quartz sand used in conventional hydraulic fracturing, due to its relatively large particle size (typically between 0.85 mm and 0.42 mm), is intended to function as a proppant to close the fracture, rather than as a weighting agent to increase the density of the first fluid as described in this application. In other words, conventional hydraulic fracturing does not involve adding a weighting agent to the fracturing fluid to increase fluid density as described in this application.

[0062] Specifically, if the density of the first fluid needs to be increased to 1200kg / m3 to 1800kg / m3 or more, based on the ceramsite or quartz sand used in existing conventional hydraulic fracturing, which is usually between 0.85 mm and 0.42 mm, the added concentration of ceramsite or quartz sand needs to exceed 38ppg to 154ppg or more, which far exceeds the sand carrying capacity of the fracturing fluid. In other words, existing ceramsite or quartz sand can be used as, but cannot be used alone as, the weighting agent described in the present invention. Therefore, the present invention specifically reduces the particle size of ceramsite or quartz sand to less than 200 microns and uses it as a weighting agent, thereby increasing the density of the first fluid, while avoiding the problem of crack blockage or migration difficulty caused by too high a concentration of the weighting agent, and then achieving the purpose of the invention of configuring the fluid pressure gradient of the first fluid at the crack bottom of the formation crack to be higher than the formation fracture pressure gradient at the corresponding depth of the formation at the crack bottom, so that the formation crack expands downward. The prior art does not have a technical solution for increasing the density of the first fluid to achieve downward expansion of the fracture, nor does it have a technical suggestion for increasing the density of the fracturing fluid by reducing the particle size to below 200 microns to serve as a weighting agent.

[0063] In a specific embodiment, the weighting agent can be one of the following: at least one ceramsite, and / or at least one resin, and / or at least one quartz sand, and / or at least one barite, and / or at least one hematite, and / or at least one ilmenite, and / or at least one manganese ore, and / or at least one calcium carbonate, and / or at least one magnesia-aluminum-iron spinel, and / or at least one metal oxide, and / or at least one silicate, and / or at least one lead ore, and / or at least one fusible alloy.

[0064] In some embodiments, in order to better transport the weighting agent in the wellbore and fracture and prevent the weighting agent from settling, it is necessary to add a thickener to the first fluid to increase the viscosity of the first 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 polymer, polyvinyl alcohol, etc.), surfactant thickener, gel-type thickener (such as phenolic resin, guar gum combined with a crosslinking agent to form a gel) and clay (such as montmorillonite, bentonite, etc.).

[0065] In the present invention, weighting agents can be added and adjusted as needed during the construction process to increase the density of the first fluid after it enters the wellbore. Weighting agents can be added to the first fluid continuously, intermittently, or during periods when fracture propagation is desired. Weighting agents can also be added to the container storing the first fluid to increase its density at the surface.

[0066] In a particularly preferred embodiment, in step S1, the type and / or mass of the weighting agent added to the first fluid can be adjusted in real time so that the fluid pressure gradient of the first fluid remains higher than the formation fracture pressure gradient. Specifically, the pressure gradient of the first fluid at the bottom of the fracture is calculated in real time (for example, by monitoring the wellhead pressure, injection flow rate, and the density and mass of the added weighting agent, and calculating using a physical model), and the data of the corresponding formation fracture pressure gradient at the bottom of the fracture are compared to determine whether the type and / or mass of the weighting agent added to the first fluid needs to be adjusted. If the judgment is yes, the type and / or mass of the weighting agent added to the first fluid is adjusted based on the change data of the formation fracture pressure gradient to increase the density and fluid pressure gradient of the first fluid.

[0067] In an alternative embodiment, whether the formation cracks are expanding downward is monitored in real time. When it is detected that the formation cracks are not expanding downward, the type and / or quality of the weighting agent added to the first fluid is adjusted to increase the density and fluid pressure gradient of the first fluid. Specifically, if it is detected that the cracks are not expanding downward according to the design requirements (due to calculation errors in the formation fracture pressure gradient, formation heterogeneity or data uncertainty, etc.), it is necessary to adjust the type and quality of the weighting agent added to the first fluid to increase the density and pressure gradient of the first fluid. By using monitoring methods such as pressure monitoring, temperature monitoring, optical fiber monitoring, microseismic monitoring, inclinometer monitoring, electromagnetic monitoring, and combining physical models and / or analysis algorithms, the expansion of the cracks can be judged.

[0068] In another embodiment, the method further includes step S2 of determining whether a fracture parameter of the formation fracture reaches a threshold value. If not, injection of the first fluid into the wellbore is continued; if the threshold value is reached, injection is stopped and the first fluid is reversed. Specifically, the fracture parameter includes at least one of the following: a downward extension depth of the formation fracture, a height of the formation fracture, a length of the formation fracture, a three-dimensional dimension of the formation fracture, and a volume of the formation fracture.

[0069] In one specific implementation, in step S2, it is determined whether the depth of the formation fracture's downward extension reaches a threshold depth. The threshold depth is greater than the target wellbore (maximum) depth, for example, 50 to 1000 meters greater than the target wellbore (maximum) depth. The depth of the formation fracture's downward extension can be calculated using a hydraulic fracturing model / software. For example, by inputting data such as pressure, displacement, and operation time into the hydraulic fracturing model / software, the depth of the formation fracture's downward extension at the corresponding time can be calculated.

[0070] In another embodiment, the threshold depth may be determined by requirements for formation temperature or energy storage density of formation fractures. For example, if a higher formation temperature or a higher energy storage density of formation fractures is required, the threshold depth may be increased.

[0071] After the depth of the formation fracture extending downward reaches a threshold depth, the injection of the first fluid is stopped. If it is determined that the depth of the formation fracture extending downward does not reach the threshold depth, the injection of the first fluid is continued.

[0072] The correlation between construction time and the depth of formation fracture extension can be calculated during the design phase. On-site monitoring of whether the construction time meets the design requirements can determine whether the depth of formation fracture extension has reached the threshold depth. Similarly, the correlation between the first fluid injection rate and the depth of formation fracture extension can be calculated during the design phase. On-site monitoring of whether the first fluid injection rate meets the design requirements can determine whether the depth of formation fracture extension has reached the threshold depth. Similarly, the correlation between the first fluid injection rate and the depth of formation fracture extension can be calculated during the design phase. On-site monitoring of whether the first fluid injection rate meets the design requirements can determine whether the depth of formation fracture extension has reached the threshold depth. Similarly, the determination of whether the depth of formation fracture extension has reached the threshold depth can also be calculated by monitoring other construction parameters.

[0073] When the depth of the formation fractures reaches a threshold depth, injection of the first fluid is stopped and the first fluid is reversed. Due to the high density and poor fluidity of the first fluid, the weighting agent will settle after a long time, making the first fluid unsuitable for energy storage or geothermal energy extraction. It should be noted that after the first fluid is reversed, some of the first fluid will still remain in the wellbore and formation fractures.

[0074] Example 2

[0075] The present invention also discloses a system capable of controlling the downward expansion of cracks to generate stratum cracks ( Figure 2 ), including a hydraulic fracturing device 3, which is used to inject a first fluid into a wellbore 1 reaching the formation based on hydraulic fracturing construction to generate formation fractures 2; and also includes a first fluid generating unit 4, which is used to configure the first fluid and configure the fluid pressure gradient of the first fluid at the bottom of the formation fracture 2 to be higher than the formation fracture pressure gradient of the formation at the corresponding depth at the bottom of the fracture, so that the formation fracture 2 expands downward; the first fluid generating unit 4 is connected to the hydraulic fracturing device 3 to supply the first fluid into the hydraulic fracturing device 3 for hydraulic fracturing construction.

[0076] The hydraulic fracturing device 3 can be any existing device in the prior art, as long as it can achieve the purpose of hydraulic fracturing construction, and will not be described in detail here. The first fluid generation unit 4 can be attached to the hydraulic fracturing device 3, that is, as a part of the hydraulic fracturing device 3, or it can exist independently of the hydraulic fracturing device 3 as a separate device. The density of the first fluid can be adjusted in the first fluid generation unit 4 to adjust and configure the fluid pressure gradient at the bottom of the formation fracture 2, thereby achieving the purpose of the fluid pressure gradient of the first fluid at the bottom of the formation fracture 2 being higher than the formation fracture pressure gradient at the corresponding depth at the fracture bottom. In actual construction, the first fluid unit can supply the first fluid to the hydraulic fracturing device 3, or the hydraulic fracturing device 3 can directly draw the first fluid from the first fluid unit to perform hydraulic fracturing construction. This can be achieved through existing pipeline structures, and will not be described in detail here. In addition, a wellhead plugging device 5 is also provided on the wellbore to plug the wellbore wellhead during subsequent energy storage.

[0077] In this embodiment, the first fluid generating unit 4 is configured to add a weighting agent to the base fracturing fluid to form a first fluid, wherein the weighting agent is configured to increase the density of the first fluid so that the fluid pressure gradient of the first fluid at the bottom of the formation fracture 2 is higher than the formation fracture pressure gradient of the formation. That is, the density of the first fluid can be adjusted by means of the first fluid generating unit 4. Specifically, the first density can be adjusted by adding weighting agents of different types and / or qualities to the base fracturing fluid used for hydraulic fracturing construction. The particle size of the weighting agent can be pre-configured to meet the working requirements. With regard to the selection of the base fracturing fluid, existing fracturing fluids can be used as long as their density can be adjusted based on the weighting agent.

[0078] As disclosed in the first embodiment, the density of the first fluid is configured to be greater than 1200 kg / m3; the weighting agent is a granular material having a particle size of less than 200 microns. The weighting agent includes: at least one ceramsite, and / or at least one resin, and / or at least one quartz sand, and / or at least one barite, and / or at least one hematite, and / or at least one ilmenite, and / or at least one manganese ore, and / or at least one calcium carbonate, and / or at least one magnesia-alumina-iron spinel, and / or at least one metal oxide, and / or at least one silicate, and / or at least one lead ore, and / or at least one fusible alloy.

[0079] In addition, the system also includes a weighting agent adjustment unit 6, which is constructed to be able to adjust the type and / or quality of the weighting agent in real time so that the fluid pressure gradient of the first fluid is maintained higher than the formation fracture pressure gradient; the weighting agent adjustment unit 6 is configured as a part of the first fluid generating unit 4, or, the weighting agent adjustment unit 6 is configured as a component independent of the first fluid generating unit 4, and supplies the weighting agent of the adjusted type and / or quality into the first fluid generating unit 4.

[0080] Specifically, the weighting agent adjustment unit 6 is configured to deliver weighting agents of different types and / or qualities to the first fluid generation unit 4 according to control instructions or manual operation, thereby achieving the purpose of adjusting the density of the basic fracturing fluid.

[0081] In this embodiment, a calculation unit 7 is further included, which is configured to calculate in real time the pressure gradient of the first fluid at the bottom of the fracture, and compare it with the data of the formation fracture pressure gradient at the corresponding depth of the formation fracture 2, to determine whether the type and / or mass of the weighting agent added to the first fluid needs to be adjusted; when it is determined that the type and / or mass of the weighting agent needs to be adjusted, the weighting agent adjustment unit 6 can receive a control instruction and adjust the type and / or mass of the weighting agent added to the first fluid to increase the density and fluid pressure gradient of the first fluid; and / or, the system also includes a fracture expansion monitoring unit 7, which is configured to monitor in real time whether the formation fracture 2 expands downward; when it is monitored that the formation fracture 2 does not expand downward, the weighting agent adjustment unit 6 can receive a control instruction and adjust the type and / or mass of the weighting agent added to the first fluid to increase the density and fluid pressure gradient of the first fluid.

[0082] Specifically, the formation fracture pressure gradient monitoring unit 7 can include a monitoring module and a control module, wherein the monitoring module is used to monitor the formation fracture pressure gradient of the formation cracks 2 of the formation in real time, and transmit the monitoring data to the control module. The control module judges the change of the formation fracture pressure gradient based on the received monitoring data. When it is judged that the fracture pressure gradient has a sudden change, that is, it exceeds the change threshold, the control module can transmit a control instruction to the weighting agent adjustment unit 6 to control the weighting agent adjustment unit 6 to deliver weighting agents of different types and / or masses to the first fluid generating unit 4, thereby achieving adjustment of the density of the first fluid.

[0083] By means of the system of the present invention, the downward expansion of the formation fracture 2 can be effectively controlled, thereby making it possible to obtain deeper and higher temperature geothermal resources and other energy without increasing the drilling depth.

[0084] Example 3

[0085] The present invention also discloses a method for storing and releasing energy by means of the method described in the first embodiment and the system described in the second embodiment ( Figure 3 ), which specifically includes the following steps:

[0086] E1, performing hydraulic fracturing operation in the target wellbore 1 to create formation fractures 2 and / or open existing formation fractures 2;

[0087] E2, injecting high-pressure fluid into the formation fracture 2 to increase the width of the formation fracture 2, thereby generating and storing elastic deformation energy of the formation rock and / or compression potential energy of the high-pressure fluid and / or geothermal energy obtained by heat exchange between the high-pressure fluid and the formation;

[0088] E3, discharges high-pressure fluid and releases energy during the discharge process;

[0089] The step E1 is implemented by the method disclosed in the first embodiment of the present invention capable of causing the crack to expand downward to generate the formation crack 2 or by the system disclosed in the second embodiment of the present invention capable of causing the crack to expand downward to generate the formation crack 2.

[0090] Specifically, step E1 can be implemented using all of the technical features described in the method for causing a fracture to propagate downward to generate a formation fracture 2, as disclosed in Example 1, and has corresponding technical effects. In step E1, when it is determined that a fracture parameter (e.g., propagation depth) of the formation fracture 2 has reached a threshold, injection of the first fluid is stopped and reversed (see step S2 in Example 1), followed by step E2.

[0091] In step E2, a high-pressure fluid (relative to the first fluid, it can be called "second fluid") is injected into the target wellbore 1, so that the high-pressure fluid enters the formation fracture 2, thereby driving the formation rock to undergo elastic deformation and accumulate elastic potential energy, or / and causing the high-pressure fluid to generate fluid compression potential energy under the reaction force of the formation rock; at the same time, the second fluid exchanges heat with the formation rock to obtain formation thermal energy; the wellbore 1 is sealed to maintain the elastic deformation of the formation rock and thus store energy.

[0092] It should be noted that the density of the high-pressure fluid as the second fluid is usually lower than the density of the first fluid because the density of the first fluid is greatly increased due to the addition of the weighting agent.

[0093] In step E2, to prevent the loss of high-pressure fluid in the formation fracture 2 and reduce energy storage efficiency, it is necessary to seal the rock pores / microcracks around the formation fracture 2 and reduce the permeability of the fracture wall or surrounding rock. For example, a fluid containing a fluid loss control agent is injected into the formation fracture 2.

[0094] Between step E2 and step E3, there is also a step of determining whether there is a demand for power generation or heating. If not, the wellbore 1 continues to be blocked. If it is determined that there is, the second fluid is reversed, that is, step E3 is performed.

[0095] In step E3, specifically, if power generation is required, during the backflow process, at least one of the following: kinetic energy of the second fluid converted from elastic potential energy accumulated in the formation rock, fluid compression potential energy released by the second fluid, and geothermal energy carried by the second fluid is converted into electrical energy using pre-set power generation equipment. The pre-set power generation equipment may include, but is not limited to, a hydro turbine, a steam turbine, a supercritical carbon dioxide turbine, a piston expander, a turboexpander, a heat exchanger, and an organic Rankine cycle (ORC) power generation device.

[0096] If the demand is for heating, the reversed second fluid is used for the heating system.

[0097] In particular embodiments, power generation and heating demands may exist simultaneously.

[0098] In the energy storage and release method described in Example 3, multiple single-well systems can work in concert to meet continuous power generation or heating needs. For example, the injection and discharge phases of the second fluid are alternated between different single-well systems, ensuring that at any given moment, at least one of the multiple single-well systems is discharging the second fluid for power generation or heating.

[0099] Since the method disclosed in Example 1 and the system disclosed in Example 2 are adopted in the energy storage and release method of the present invention, deeper and higher temperature geothermal resources or other energy can be obtained without increasing the drilling depth, thereby reducing the drilling depth and lowering the drilling cost.

[0100] It should be noted that the method disclosed in the first embodiment and the system disclosed in the second embodiment of the present invention can also be applied to traditional enhanced geothermal systems, thereby reducing the drilling depth and lowering the drilling cost.

[0101] 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.

[0102] 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.

[0103] 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.

[0104] The foregoing description is merely a preferred embodiment of the present invention and is 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 are intended to be within the scope of protection of the present invention.

[0105] 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 controlling the propagation direction of a formation fracture, comprising step S1, based on hydraulic fracturing construction, injecting a first fluid into a wellbore leading to the formation to generate a formation fracture; It is characterized by: The fluid pressure gradient of the first fluid at the bottom of the formation fracture is configured to be higher than the formation fracture pressure gradient at the corresponding depth of the formation at the bottom of the fracture, so that the formation fracture expands downward.

2. The method according to claim 1, characterized in that The first fluid is constructed as a fluid having a weighting agent added to a basic fracturing fluid, wherein the weighting agent is configured to increase the density of the first fluid so that the fluid pressure gradient of the first fluid at the bottom of the formation fracture is higher than the formation fracture pressure gradient of the formation.

3. The method according to claim 2, characterized in that In step S1 , the type and / or mass of the weighting agent added to the first fluid can be adjusted in real time so that the fluid pressure gradient of the first fluid is kept higher than the formation fracture pressure gradient.

4. The method according to claim 3, characterized in that Calculating in real time the pressure gradient of the first fluid at the bottom of the fracture and comparing it with the data of the formation fracture pressure gradient corresponding to the bottom of the fracture to determine whether the type and / or mass of the weighting agent added to the first fluid needs to be adjusted. If so, adjusting the type and / or mass of the weighting agent added to the first fluid based on the change data of the formation fracture pressure gradient to increase the density and fluid pressure gradient of the first fluid; And / or, monitor in real time whether the formation fractures are expanding downward. When it is detected that the formation fractures are not expanding downward, adjust the type and / or quality of the weighting agent added to the first fluid to increase the density and fluid pressure gradient of the first fluid.

5. The method according to claim 2, characterized in that The density of the first fluid is configured to be higher than 1200 kg / m3; the weighting agent is a granular material, and its particle size is configured to be less than 200 microns.

6. The method according to claim 2, characterized in that The weighting agent comprises: at least one ceramsite, and / or at least one resin, and / or at least one quartz sand, and / or at least one barite, and / or at least one hematite, and / or at least one ilmenite, and / or at least one manganese ore, and / or at least one calcium carbonate, and / or at least one magnesia-alumina-iron spinel, and / or at least one metal oxide, and / or at least one silicate, and / or at least one lead ore, and / or at least one fusible alloy.

7. The method according to claim 1, characterized in that A thickener is further added to the first fluid to increase the viscosity of the first fluid; The thickener comprises: 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-type thickener, and / or at least one gel-type thickener, and / or at least one clay.

8. The method according to any one of claims 1 to 7, characterized in that The method further includes step S2, determining whether the fracture parameter of the formation fracture reaches a threshold value; if not, continuing to inject the first fluid into the wellbore; and if the threshold value is reached, stopping the injection and back-discharging the first fluid.

9. The method according to claim 8, characterized in that The fracture parameters include at least one of the following: a depth of downward extension of the formation fracture, a height of the formation fracture, a length of the formation fracture, a three-dimensional size of the formation fracture, and a volume of the formation fracture.

10. A system for controlling the propagation direction of formation fractures, comprising a hydraulic fracturing device for injecting a first fluid into a wellbore leading to the formation during hydraulic fracturing to generate formation fractures; It is characterized by: The system further includes a first fluid generating unit configured to configure a first fluid so that a fluid pressure gradient of the first fluid at a fracture bottom of a formation fracture is configured to be higher than a formation fracture pressure gradient at a corresponding depth of the formation at the fracture bottom, so as to cause the formation fracture to expand downward; The first fluid generating unit is connected to the hydraulic fracturing device to supply the first fluid to the hydraulic fracturing device for hydraulic fracturing construction.

11. The system according to claim 10, wherein: The first fluid generating unit is constructed to be able to add a weighting agent to the basic fracturing fluid to form a first fluid, wherein the weighting agent is configured to be able to increase the density of the first fluid so that the fluid pressure gradient of the first fluid at the bottom of the fracture of the formation is higher than the formation fracture pressure gradient of the formation.

12. The system according to claim 11, wherein: The system further comprises a weighting agent adjustment unit configured to adjust the type and / or quality of the weighting agent in real time so that the fluid pressure gradient of the first fluid is kept higher than the formation fracture pressure gradient; The weighting agent adjustment unit is configured as a part of the first fluid generating unit, or is configured as a component independent of the first fluid generating unit, and supplies the weighting agent of adjusted type and / or quality into the first fluid generating unit.

13. The system according to claim 12, wherein: The system further includes a calculation unit configured to calculate in real time the pressure gradient of the first fluid at the bottom of the fracture, and compare it with data of the formation fracture pressure gradient at a corresponding depth of the formation fracture, to determine whether the type and / or mass of the weighting agent added to the first fluid needs to be adjusted; When it is determined that the type and / or mass of the weighting agent needs to be adjusted, the weighting agent adjustment unit can receive a control instruction and adjust the type and / or mass of the weighting agent added to the first fluid to increase the density and fluid pressure gradient of the first fluid; And / or, the system further comprises a fracture expansion monitoring unit configured to monitor in real time whether the formation fractures are expanding downward; When it is monitored that the formation fractures do not extend downward, the weighting agent adjustment unit can receive a control instruction and adjust the type and / or quality of the weighting agent added to the first fluid to increase the density and fluid pressure gradient of the first fluid.

14. The system according to claim 13, wherein: The density of the first fluid is configured to be higher than 1200 kg / m3; the weighting agent is a granular material, and its particle size is configured to be less than 200 microns.

15. The system according to claim 11, wherein: The weighting agent comprises: at least one ceramsite, and / or at least one resin, and / or at least one quartz sand, and / or at least one barite, and / or at least one hematite, and / or at least one ilmenite, and / or at least one manganese ore, and / or at least one calcium carbonate, and / or at least one magnesia-alumina-iron spinel, and / or at least one metal oxide, and / or at least one silicate, and / or at least one lead ore, and / or at least one fusible alloy.

16. A method for storing and releasing energy through formation fractures, characterized in that: The following steps are involved: E1, conducting hydraulic fracturing operations in the target wellbore to create formation fractures and / or open existing formation fractures; E2, injecting high-pressure fluid into the formation fractures to increase the width of the formation fractures, thereby generating and storing the elastic deformation energy of the formation rock and / or the compression potential energy of the high-pressure fluid and / or the geothermal energy obtained by increasing the temperature of the high-pressure fluid and the formation through heat exchange; E3, discharges high-pressure fluid and releases energy during the discharge process; The step E1 is implemented by the method according to any one of claims 1 to 9 or by the system according to any one of claims 10 to 15.

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