Method and system for geothermal energy exploitation based on multiple non-communicated wellbores

Abstract

The method comprises the steps that high-pressure fluid is injected into different shafts which are not communicated with one another in advance, so that the fracture pressure of formation fractures in the shafts is higher than the fracture closing stress, and then well mouths of the shafts are closed to store energy and absorb geothermal energy; when power generation or heat supply is needed, the wellheads of the wellbores are opened, the high-pressure fluid in one wellbore is reversely discharged for power generation / heat supply, and the reversely discharged fluid subjected to power generation / heat supply is injected into the other wellbore for energy storage and geothermal energy absorption again; and after the reverse discharge of the shaft is finished, the high-pressure fluid in the other shaft can be reversely discharged for power generation / heat supply, and the fluid subjected to power generation / heat supply is injected into the previous shaft, so that circulating energy storage / release and geothermal energy exploitation are realized. The method is implemented on the basis of the multiple non-communicated shafts, and compared with the mode of exploiting geothermal energy through the shafts communicated through cracks in the prior art, the parasitic load can be effectively reduced, and the situation of short heat paths of multiple wells is avoided.

Description

Technical Field

[0001] The present invention belongs to the technical field of geothermal energy exploitation, and in particular relates to a method and system for geothermal energy exploitation based on non-connected multiple wellbores. 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] Currently, hydraulic fracturing is commonly used to construct enhanced geothermal systems (EGS) for deep geothermal extraction. The main disadvantages of EGS are: (1) During the extraction of geothermal energy, the fractures are closed, the gaps are small, and the friction within the fractures is large, resulting in large energy losses of the injected fluid (large parasitic load); (2) Because the injection well and the extraction well are connected by multiple fractures, the injected fluid tends to flow quickly through the fractures with larger gaps, failing to effectively exchange heat with the surrounding rocks, resulting in a "thermal short circuit" (short-circuiting), causing the temperature at the extraction well outlet to drop sharply.

[0004] Therefore, there is an urgent need for a geothermal energy mining method that can overcome the disadvantages of existing enhanced geothermal energy. Summary of the Invention

[0005] In light of this, the present invention provides a method and system for geothermal energy extraction based on multiple, non-connected wellbores. This system utilizes multiple, non-connected wellbores to achieve energy storage and release, as well as geothermal energy extraction. Because the wellbores are disconnected, they effectively avoid the "thermal short circuit" phenomenon seen in geothermal energy extraction methods that utilize wellbores connected by fractures. Furthermore, because the fractures remain open during geothermal energy extraction, frictional resistance within the fractures is minimal, significantly reducing parasitic loads.

[0006] A first aspect of the present invention discloses a method for geothermal energy extraction based on multiple non-connected wellbores, comprising the following steps:

[0007] S1, selecting two or more wellbores as target wellbores, and creating formation fractures in the target wellbores or opening existing formation fractures; wherein the target wellbores are non-connected;

[0008] S2, pre-injecting high-pressure fluid into formation fractures of one or more wellbores in the target wellbore, so that the high-pressure fluid stores energy in the formation fractures of the one or more wellbores; wherein the stored energy includes: fluid compression potential energy obtained due to the pressure increase in the overall space formed by the wellbore and the formation fracture, and / or elastic deformation potential energy obtained by driving the formation rock to undergo elastic deformation, and / or stress potential energy obtained by doing work to overcome the fracture closure pressure, and / or formation thermal energy obtained by heat exchange with the formation rock;

[0009] S3, discharging the injected high-pressure fluid from at least one of the one or more wellbores to release energy; and injecting the discharged high-pressure fluid from outside the wellbores into formation fractures of one or more other wellbores, so that the high-pressure fluid stores energy in the formation fractures of the one or more other wellbores;

[0010] S4, discharging the high-pressure fluid from at least one of the one or more wellbores to release energy; and injecting the discharged high-pressure fluid into the one or more wellbores from outside the wellbores to store energy.

[0011] Among them, the so-called non-connected means that the target wellbores are not connected in terms of the formation structure, that is, they are neither connected through formation cracks nor through pores in any formation (such as gaps and / or microcracks around formation cracks). In low-permeability formations, since the fluid flows extremely slowly in the formation pores, the fluid flow in one wellbore will not affect the fluid flow in another wellbore in a short period of time (such as within a day), and the different wellbores can be considered to be non-connected. That is to say, in the present invention, the selected target wellbores are completely independent and are not connected to each other in terms of the formation structure. It should be understood by those skilled in the art that the injection and reverse discharge of high-pressure fluids can be realized between the selected target wellbores by means of an injection device and a reverse discharge device. For example, the high-pressure fluid in one wellbore is injected into another wellbore by means of a reverse discharge device and an injection device. This does not mean that there is a contradiction or restriction with the definition of "non-connected".

[0012] In other embodiments where the term "one or more wellbores" includes "one wellbores," the "one or more wellbores" and "the one or more other wellbores" can be understood to refer to two wellbores arranged in opposing groups, each wellbore group including at least one wellbore. Specifically, the present invention achieves continuous energy storage / release and geothermal energy extraction by performing injection and discharge cycles between two wellbores, thereby achieving continuous power generation and / or heating.

[0013] Because the present invention utilizes non-connected wellbores to achieve high-pressure fluid injection and backflow circulation, it effectively avoids the "thermal short-circuiting" technical problem encountered in prior art. Specifically, because the selected wellbores are not connected and circulation between them is achieved using external equipment (such as injection and backflow devices), the injected high-pressure fluid does not rapidly flow through excessively large cracks in one wellbore and enter another wellbore. Instead, it can effectively exchange heat with the surrounding rock in the corresponding wellbores, thus avoiding the disadvantage of thermal short-circuiting.

[0014] Moreover, since the selected wellbores in the present invention are not connected to each other, the geothermal energy obtained based on the high-pressure fluid in a certain wellbore can also be stored in other wellbores through the backflow device and the injection device, so that geothermal energy can be flexibly stored when it is not needed for heating.

[0015] According to the method disclosed in the first aspect of the present invention, step S2 further includes: pre-injecting high-pressure fluid into the formation fractures of the one or more wellbores, wherein the volume of the injected high-pressure fluid is less than the volume of the high-pressure fluid pre-injected into the formation fractures of the one or more wellbores and greater than a pre-set fluid threshold volume. The pre-set fluid threshold volume can be calculated by setting the magnitude of frictional loss (e.g., setting the frictional loss of the energy storage cycle to no more than 5% of the energy storage capacity), and can be a specific value or a range. That is, in this embodiment, a pre-set fluid threshold volume is set for the high-pressure fluid pre-injected into the formation fractures of the one or more wellbores, such that the volume of the high-pressure fluid pre-injected into the formation fractures of the one or more wellbores is greater than the pre-set fluid threshold volume, and the minimum fracture volume generated by the participating formation fractures during the fluid injection and backflow cycles cannot be less than the pre-set fluid threshold volume. In this case, the larger the pre-set fluid threshold volume, the larger the minimum width of the formation fracture during the fluid injection and backflow cycles, thereby reducing the frictional loss of the fluid flowing in the formation fractures. The friction loss of flow in formation fractures is related to the fracture width, and the fracture width is linearly related to the fracture volume (when the fracture height and length remain unchanged).

[0016] That is to say, in the present invention, in step S2, high-pressure fluid is pre-injected into at least one of the one or more wellbores and at least one of the other one or more wellbores, and then a backflow and injection cycle is performed between the wellbores that have been pre-injected with high-pressure fluid. Or, in other words, the wellbores participating in the backflow and injection cycle are all pre-injected with high-pressure fluid. In order to better illustrate the scheme and its effects, an example is given of a crack in each of the two wellbores. 100 cubic meters of high-pressure fluid (such as water) is initially injected into the crack of one wellbores, while 30 cubic meters of water is initially injected into the crack of the other wellbores. During the circulation process, only 70 cubic meters of water are used for circulation, and at least 30 cubic meters of water are retained in the crack of each wellbores. This has the advantage that the cracks in at least one of the one or more wellbores and at least one of the other one or more wellbores can be kept in an open state at any time and have a certain minimum width, thereby reducing the friction resistance of injection and backflow. This also has another advantage. It can allow a portion of the fluid to be preheated in the fracture in advance. The newly injected fluid with a lower temperature and the preheated fluid with a higher temperature will produce convection (high-temperature liquid flows upward, and low-temperature liquid flows downward), so that the newly injected low-temperature fluid can increase its temperature more quickly. That is, energy and heat can be pre-accumulated in all wellbores participating in the backflow and injection cycle at the same time, so that they can respond quickly when energy release is needed, that is, the response time of the energy release work is reduced.

[0017] According to the method disclosed in the first aspect of the present invention, in step S2, high-pressure fluid is pre-injected into the one or more wellbores and the one or more other wellbores in a manner that increases the fracture pressure of the formation fractures above the fracture closure pressure. This solution allows the formation fractures to remain open at all times, with the fracture width being much larger than the closed fracture gap. This reduces frictional resistance within the fractures and resolves the technical issue of high energy loss (high parasitic load) associated with fluid injection in the prior art.

[0018] According to the method disclosed in the first aspect of the present invention, in steps S3 and S4, after the reversed high-pressure fluid is injected into the corresponding wellbore, the corresponding wellbore is plugged for a period of time to store energy. That is, after the reversed high-pressure fluid is injected into the corresponding wellbore, the wellbore is plugged for a period of time. This allows the high-pressure fluid injected based on the reverse flow to have more time to exchange formation heat in the current wellbore, thereby forming effective energy storage.

[0019] According to the method disclosed in the first aspect of the present invention, a fluid loss agent is added to the high-pressure fluid. The addition of the fluid loss agent can effectively prevent the loss of the high-pressure fluid in the formation, thereby ensuring the effective working volume of the high-pressure fluid.

[0020] According to the method disclosed in the first aspect of the present invention, in steps S3 and S4, the method further includes injecting additional high-pressure fluid into the one or more wellbores and the one or more other wellbores, respectively, to compensate for filtration losses of the high-pressure fluid. This effectively replenishes the working volume of the high-pressure fluid, thereby ensuring that the energy intensity of storage / release and geothermal energy extraction meets the requirements for power generation and / or heating.

[0021] According to the method disclosed in the first aspect of the present invention, between step S2 and step S3, a step of monitoring whether there is a demand for power generation or heating is included. When it is monitored that there is a demand for power generation or heating, step S3 is executed, otherwise it is not executed.

[0022] According to the method disclosed in the first aspect of the present invention, a step of monitoring whether there is still a demand for power generation or heating is included between step S3 and step S4. When it is monitored that there is still a demand for power generation or heating, step S4 is executed, otherwise it is not executed.

[0023] A second aspect of the present invention discloses a system for implementing the method for storing / releasing energy and exploiting geothermal energy based on non-connected multiple wellbores disclosed in the first aspect of the present invention, comprising:

[0024] A fracturing device configured to create formation fractures or open existing formation fractures in two or more target wellbores, wherein the target wellbores are configured to be non-connected;

[0025] An injection and flowback device is configured to pre-inject a high-pressure fluid into formation fractures in one or more target wellbores, so that the high-pressure fluid stores energy in the formation fractures of the one or more wellbores; wherein the stored energy includes: fluid compression potential energy obtained due to the pressure increase in the overall space formed by the wellbore and the formation fractures, and / or elastic deformation potential energy obtained by driving the formation rock to undergo elastic deformation, and / or stress potential energy obtained by doing work to overcome the fracture closure pressure, and / or formation thermal energy obtained by heat exchange with the formation rock;

[0026] The injection and discharge device is further configured to discharge the injected high-pressure fluid from at least one of the one or more wellbores to release energy; and to inject the discharged high-pressure fluid into the formation fractures of one or more other wellbores, so that the high-pressure fluid stores energy in the formation fractures of the one or more other wellbores;

[0027] The injection and discharge device is further configured to discharge the high-pressure fluid from at least one of the one or more wellbores to release energy; and to re-inject the discharged high-pressure fluid into the one or more wellbores to store energy;

[0028] The power generation or heating device is configured to receive the energy released by the high-pressure fluid during the reverse discharge process and convert it into electrical energy or thermal energy.

[0029] According to the system disclosed in the second aspect of the present invention, the injection device is also constructed to be able to pre-inject high-pressure fluid into the formation fractures of one or more other wellbores, and the volume of the injected high-pressure fluid is smaller than the volume of the high-pressure fluid pre-injected into the formation fractures of the one or more wellbores and is greater than a pre-fluid threshold volume.

[0030] According to the system disclosed in the second aspect of the present invention, the system further includes:

[0031] a plugging device configured to plug a target wellbore so as to allow high-pressure fluid in formation fractures of the target wellbore to store energy;

[0032] A monitoring device configured to monitor whether there is external demand for power generation or heating;

[0033] A control device is capable of receiving monitoring data from the monitoring device and issuing working instructions to the injection and reverse flow device, the plugging device and the power generation or heating device.

[0034] Beneficial effects: In the method and system of the present invention, cyclical energy storage / release and geothermal energy extraction can be completed between multiple wellbores, thereby ensuring the effective extraction of geothermal energy and greatly reducing energy waste and extraction energy consumption compared to single-well extraction. In addition, the cyclical geothermal energy extraction in the present invention is based on multiple non-connected wellbores. Compared with the existing method of extracting geothermal energy through wellbores connected by fractures, this can effectively avoid the situation of "short-circuiting" of multiple wells. In addition, since the wellbores in the present invention are non-connected, this allows for flexible storage when geothermal energy is not needed.

[0035] In a further preferred embodiment, since the injection of high-pressure fluid can make the fracture pressure of the formation fracture higher than the fracture closure pressure, the formation fracture can always be kept in an open state, and the fracture width is much larger than the closed fracture gap, which can reduce the friction resistance in the fracture and solve the technical problem of large energy loss (large parasitic load) of fluid injection in the prior art.

[0036] The method and system for geothermal energy extraction based on non-connected multiple wellbores of the present invention will be disclosed in detail below with reference to the embodiments shown in the accompanying drawings and the accompanying reference numerals. BRIEF DESCRIPTION OF THE DRAWINGS

[0037] Figure 1A and Figure 1B Schematic diagram of a conventional enhanced geothermal system in the prior art, wherein Figure 1A The enhanced geothermal system formed by vertical well fracturing is shown in Figure 1B An enhanced geothermal system formed by horizontal well fracturing is demonstrated in [1].

[0038] Figure 2 A flow chart showing the steps of the method for geothermal energy extraction based on non-connected multiple wellbores in the present invention is shown.

[0039] Figure 3 It is a schematic diagram of the system for geothermal energy extraction based on non-connected multiple wellbores in the present invention. DETAILED DESCRIPTION

[0040] 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.

[0041] The term "formation" as used herein refers to a porous and permeable rock formation (e.g., shale formation, sandstone formation, carbonate formation, hot dry rock formation, etc.) underground that can serve as a storage space for fluids. Typically, these fluids can be water, hydrocarbons, or gases.

[0042] 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).

[0043] "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.

[0044] 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.

[0045] 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."

[0046] 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 in the absence of conflict.

[0047] Figure 1A and Figure 1B This is a schematic diagram of a conventional enhanced geothermal system in the prior art. Figure 1A and Figure 1B As shown, a conventional enhanced geothermal system is implemented as follows: at least one injection wellbore a and at least one drainage wellbore (or production wellbore) b are hydraulically connected through formation fractures c and / or rock pores in the enhanced geothermal system. Fluid is injected into injection wellbore a, where it exchanges heat with the formation rock in the fractures, generating formation heat energy. When heating or power generation is needed, the fluid, which has accumulated formation heat energy, is discharged through drainage wellbore b and subsequently used for heating or power generation. Arrows in the figure represent the injection and drainage directions of the fluid. As previously described in the background technology, the conventional enhanced geothermal system has the following technical problems: 1) During the process of extracting geothermal energy, the cracks are in a closed state, the crack gaps are small, and the frictional resistance within the cracks is large, resulting in a large energy loss of the injected fluid; 2) Since the injection wellbore and the return wellbore are connected by multiple cracks, the injected fluid tends to flow quickly through the cracks with larger crack gaps and fails to effectively exchange heat with the surrounding rocks, thereby causing a "thermal short circuit" and causing the outlet temperature of the return wellbore to drop sharply.

[0048] To solve the above technical problems, the present application proposes a method and system for geothermal energy extraction based on non-connected multiple wellbores. Please refer to the following embodiments for details.

[0049] Example 1

[0050] Figure 2A flow chart showing the steps of a method for geothermal energy extraction based on non-connected multiple wellbores is shown. Figure 2 As shown, the method of the present invention comprises the following steps:

[0051] S1, selecting two or more wellbores as target wellbores, and creating formation fractures in the target wellbores or opening existing formation fractures; wherein the target wellbores are non-connected;

[0052] S2, pre-injecting high-pressure fluid into formation fractures of one or more wellbores in the target wellbore, so that the high-pressure fluid stores energy in the formation fractures of the one or more wellbores; wherein the stored energy includes: fluid compression potential energy obtained due to the pressure increase in the overall space formed by the wellbore and the formation fracture, and / or elastic deformation potential energy obtained by driving the formation rock to undergo elastic deformation, and / or stress potential energy obtained by doing work to overcome the fracture closure pressure, and / or formation thermal energy obtained by heat exchange with the formation rock;

[0053] S3, reversely discharging the injected high-pressure fluid from at least one of the one or more wellbores to release energy; and injecting the reversed high-pressure fluid into formation fractures of one or more other wellbores, so that the high-pressure fluid stores energy in the formation fractures of the one or more other wellbores;

[0054] S4, discharging the high-pressure fluid from at least one of the one or more wellbores to release energy; and injecting the discharged high-pressure fluid back into the one or more wellbores to store energy.

[0055] The target wellbore can be a vertical well, an inclined well, or a horizontal well. The existing formation fractures created or opened in the target wellbore can be one or multiple. For example, two target horizontal wells are staged for fracturing, but the two target horizontal wells are not connected by the formation fractures.

[0056] The so-called "one or more wellbores" can be one or two or more wellbores, and the "another wellbores" can similarly be one or two or more wellbores. In other words, the "one or more wellbores" and "another one or more wellbores" as defined in the present invention can be understood as two wellbores arranged in opposing groups, each group including at least one wellbores, with both wellbores sharing at least two wellbores involved in energy storage and release. In other words, the present invention achieves continuous energy storage / release and geothermal energy extraction, thereby enabling continuous power generation and / or heating, by performing injection and reverse discharge cycles between the two wellbores.

[0057] Because the present invention utilizes non-connected wellbores to achieve high-pressure fluid injection and backflow circulation, it effectively avoids the "thermal short-circuiting" technical problem commonly encountered in existing technologies. Specifically, because the selected wellbores are not connected and circulation between them is achieved through external equipment (such as injection and backflow devices), the injected high-pressure fluid cannot flow directly from one wellbore to another through the formation. As a result, the injected high-pressure fluid can effectively exchange heat with the surrounding rock, eliminating the thermal short-circuiting problem often seen in conventional enhanced geothermal systems.

[0058] Moreover, since the selected wellbores in the present invention are not connected to each other, the geothermal energy obtained based on the high-pressure fluid in a certain wellbore can also be stored in other wellbores through the backflow device and the injection device, so that geothermal energy can be flexibly stored when it is not needed for heating.

[0059] In a preferred embodiment of the present invention, step S2 further includes: pre-injecting high-pressure fluid into the formation fractures of the one or more other wellbores, wherein the volume of the injected high-pressure fluid is smaller than the volume of the high-pressure fluid pre-injected into the formation fractures of the one or more wellbores and is larger than a pre-fluid threshold volume. That is, in the present invention, in step S2, high-pressure fluid is pre-injected into at least one wellbores among the one or more wellbores and at least one wellbores among the one or more other wellbores, and then a backflow and injection cycle is performed between the wellbores that have been pre-injected with high-pressure fluid. Or, in other words, the wellbores participating in the backflow and injection cycle are all pre-injected with high-pressure fluid. This can pre-accumulate energy in all the wellbores participating in the backflow and injection cycle, so that they can respond quickly when energy release is required, that is, reduce the response time of the energy release work.

[0060] In a further preferred embodiment of the present invention, in step S2, high-pressure fluid is pre-injected into the one or more wellbores and the one or more other wellbores in a manner that enables the fracture pressure of the formation fractures to be higher than the fracture closure pressure. That is, during the intermittent injection and backflow cycles in the wellbores and during energy storage, the fracture pressure of the formation fractures within the wellbores is higher than the fracture closure pressure and lower than the formation fracture expansion pressure. Based on this solution, the formation fractures can be kept open at all times, with the fracture width being much larger than the closed fracture gap. This reduces friction within the fractures and solves the technical problem of high energy loss (high parasitic load) associated with injecting fluids in the prior art.

[0061] In another embodiment, in steps S3 and S4, after the reversed high-pressure fluid is injected into the corresponding wellbore, the corresponding wellbore is plugged for a period of time, T, to store energy. Specifically, after the reversed high-pressure fluid is injected into the corresponding wellbore, the wellbore is plugged for a period of time. This allows the injected high-pressure fluid to have more time to exchange heat with the formation in the current wellbore, thereby more effectively extracting geothermal energy. The time T can be calculated using empirical formulas or physical models based on information such as the formation temperature, the temperature / density / specific heat of the injected fluid, the volume of the formation fractures, and the required temperature for power generation / heating.

[0062] In another embodiment, a fluid loss control agent is added to the high-pressure fluid. This addition effectively prevents filtration of the high-pressure fluid within the formation, thereby ensuring the effective working volume of the high-pressure fluid. Alternatively, steps S3 and S4 may further include injecting additional high-pressure fluid into the one or more wellbores and the other or more wellbores to compensate for filtration losses of the high-pressure fluid. This effectively replenishes the working volume of the high-pressure fluid, thereby ensuring that the energy storage / release and energy intensity of geothermal extraction meet the requirements for power generation and / or heating.

[0063] In another embodiment, between step S2 and step S3, there is a step of monitoring whether there is a demand for power generation or heating. If it is detected that there is a demand for power generation or heating, step S3 is executed; otherwise, it is not executed. In a further embodiment, between step S3 and step S4, there is a step of monitoring whether there is still a demand for power generation or heating. If it is detected that there is still a demand for power generation or heating, step S4 is executed; otherwise, it is not executed.

[0064] The following summarizes the working process implemented by the method of the present invention using two wellbores as an example: first, high-pressure fluid is pre-injected into a wellbore D, and at the same time, high-pressure fluid is pre-injected into another wellbore F. The injection pressure of the high-pressure fluid can match the crack pressure of the formation cracks connected to the wellbore, which is the high-pressure crack closing pressure and is less than the crack expansion pressure, so that the formation cracks are in an open but not expanded state; the volume of the high-pressure fluid injected into the other wellbore F is less than the volume of the high-pressure fluid injected into the aforementioned wellbore D.

[0065] After the injection of high-pressure fluid is completed, the plugging devices of the two wellbores are closed to allow the high-pressure fluid to store energy and obtain geothermal energy in the two wellbores.

[0066] When the monitoring device reports a demand for power generation or heating, the control device controls the opening of the plugging device, and the high-temperature, high-pressure fluid discharged from the aforementioned wellbore D is used for power generation / heating, and then injected into another wellbore F to re-store energy (at least to re-exchange heat with the formation rock). At this time, the time for discharging the high-pressure fluid from the aforementioned wellbore D depends on the power generation / heating demand and the total volume of the high-pressure fluid in the formation fractures in the wellbore.

[0067] When the reverse flow from wellbore D is complete and monitoring indicates that power generation / heating is still required, the high-pressure fluid is reversed and reverse flow from the other wellbore F begins to continue generating power / heating. After power generation / heating, the high-pressure fluid is reinjected into wellbore D to re-exchange heat with the formation. This intermittent injection and reverse flow cycle between wellbore D and wellbore F achieves continuous power generation / heating.

[0068] In some embodiments, during the intermittent injection and backflow cycles of one wellbore D and another wellbore F, the fracture pressure of the formation fracture is higher than the high-pressure fracture closure pressure and is lower than the fracture expansion pressure, so that the formation fracture is in an open but unexpanded state, and a portion of high-pressure fluid is always retained in the formation fracture participating in the geothermal extraction cycle. This can be achieved based on the aforementioned scheme of pre-injecting high-pressure fluid into one wellbore D and another wellbore F. For example, 1,000 cubic meters of high-pressure fluid are pre-injected into wellbore D and 300 cubic meters of high-pressure fluid are pre-injected into wellbore D, and only 700 cubic meters of high-pressure fluid participate in the intermittent injection and backflow cycles of wellbore D and wellbore F. After the backflow is completed, both wellbore D and wellbore F retain 300 cubic meters of high-pressure fluid in the formation fracture.

[0069] Example 2

[0070] The present invention also discloses a system for implementing the method for geothermal energy extraction based on non-connected multiple wellbores disclosed in the first aspect of the present invention. Figure 3 This is a schematic diagram of a geothermal energy extraction system based on non-connected multiple wellbores in the present invention, combined with Figure 3 As shown, the system includes:

[0071] A fracturing device is configured to create formation fractures 1 or open existing formation fractures 1 in two or more target wellbores; wherein the target wellbores are configured to be non-connected;

[0072] An injection and flowback device 2 is configured to pre-inject a high-pressure fluid into the formation fractures 1 of one or more wellbores in a target wellbore, so that the high-pressure fluid stores energy in the formation fractures 1 of the one or more wellbores; wherein the stored energy includes: fluid compression potential energy obtained due to the pressure increase in the overall space formed by the wellbore and the formation fracture 1, and / or elastic deformation potential energy obtained by driving the formation rock to undergo elastic deformation, and / or stress potential energy obtained by doing work to overcome the fracture closure pressure, and / or formation thermal energy obtained by heat exchange with the formation rock;

[0073] The injection and discharge device 2 is further configured to discharge the injected high-pressure fluid from at least one of the one or more wellbores to release energy; and to inject the discharged high-pressure fluid into the formation fracture 1 of one or more other wellbores, so that the high-pressure fluid stores energy in the formation fracture 1 of the one or more other wellbores;

[0074] The injection and discharge device 2 is further configured to discharge the high-pressure fluid from at least one of the one or more wellbores to release energy; and to re-inject the discharged high-pressure fluid into the one or more wellbores to store energy.

[0075] The power generation or heating device 3 is configured to receive the energy released by the high-pressure fluid during the reverse discharge process and convert it into electrical energy or thermal energy.

[0076] The pre-set power generation or heating device 3 can convert at least one of the following: high-pressure fluid kinetic energy converted from elastic potential energy stored in the formation rock, fluid compression potential energy released by the high-pressure fluid, and geothermal energy carried by the high-pressure fluid into electrical energy or for heating. The power generation or heating device 3 can be one or more of a hydro turbine, a steam turbine, a supercritical carbon dioxide turbine, an expander, a heat exchanger, an organic Rankine cycle, a Kalina cycle, a flash cycle, a binary cycle system, a supercritical carbon dioxide cycle, or a Brayton cycle power generation device.

[0077] In this embodiment, the injection device is also constructed to be able to pre-inject high-pressure fluid into the formation fracture 1 of one or more other wellbores, and the volume of the injected high-pressure fluid is smaller than the volume of the high-pressure fluid pre-injected into the formation fracture 1 of the one or more wellbores and is greater than a pre-fluid threshold volume.

[0078] The following describes the system of the present invention by assuming that two wellbores participate in the circulation work: In the system of the present invention, the injection and backflow device 2 is connected to a wellbore D and another wellbore F respectively through the first injection pipe 7 and the second injection pipe 8. When it is necessary to inject high-pressure fluid, the high-pressure fluid is injected into the corresponding wellbore through the first injection pipe 7 and the second injection pipe 8, or the high-pressure fluid obtained by backflow is injected; and the first backflow pipe 9 and the second backflow pipe 10 are connected to the wellbore D and the other wellbore F respectively. When it is necessary to backflow the high-pressure fluid, the first backflow pipe 9 and the second backflow pipe 10 are connected. The second discharge pipe 10 discharges the high-pressure fluid in the corresponding wellbore back out of the wellbore; in addition, the power generation or heating device 3 in the system is connected to the injection and discharge device 2 through another input pipe 11 and an output pipe 12. In this way, when the injection and discharge device 2 discharges the high-pressure fluid of the corresponding wellbore back out of the wellbore, the discharged high-pressure fluid can be input into the power generation or heating device 3 through the input pipe 11, and after the power generation or heating device 3 does work, the fluid after power generation or heating is output to the injection and discharge device 2 through the output pipe 12, thereby realizing reciprocating circulation.

[0079] In this embodiment, the system further includes:

[0080] A plugging device 4 is configured to plug the target wellbore so that the high-pressure fluid in the formation fracture 1 of the target wellbore can store energy;

[0081] A monitoring device 5 is configured to monitor whether there is external demand for power generation or heating;

[0082] The control device 6 is capable of receiving the monitoring data from the monitoring device 5 and issuing working instructions to the reverse discharge device, the blocking device 4 and the power generation or heating device 3 .

[0083] In the system of the present invention, the control device 6 can be a controller with a CPU processor, which can receive and process the monitoring signals from the monitoring device 5. After processing the signals, it can also issue working instructions to the injection and reverse flow device 2, the plugging device 4, and the power generation or heating device 3. After receiving the corresponding working instructions, the corresponding devices start or stop working. The signal processing and working instruction transmission of the controller can be implemented using existing technologies and will not be described in detail here.

[0084] In addition, in the method for storing and releasing energy based on non-connected multiple wellbores described in the first embodiment, during the process of hydraulic fracturing to create formation fractures in step S1, a method is adopted to enable the fractures to extend downward to generate formation fractures. The method includes the following steps:

[0085] E1, based on hydraulic fracturing construction, injecting a first fluid into a wellbore reaching the energy storage 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 energy storage formation at the corresponding depth at the bottom of the fracture, so that the formation fracture expands downward.

[0086] Wherein, the wellbore can be a vertical well, an inclined well or a horizontal well. The formation fractures can be generated by opening the original formation fractures or 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.

[0087] 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.

[0088] 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 energy storage formation.

[0089] 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:

[0090]

[0091] 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.

[0092] When the pressure gradient of the first fluid at the bottom of the fracture is greater than the fracture gradient of the formation at the corresponding depth at the bottom of the fracture, the fracture will expand downward.

[0093] 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.

[0094] 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.

[0095] Specifically, if the density of the first fluid needs to be increased to above 1200 kg / m³ to 1800 kg / m³, based on the ceramsite or quartz sand used in conventional hydraulic fracturing, which typically has a particle size between 0.85 mm and 0.42 mm, the added concentration of ceramsite or quartz sand needs to exceed 38 ppg to 154 ppg, which far exceeds the sand-carrying capacity of the fracturing fluid. In other words, existing ceramsite or quartz sand 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 to increase the density of the first fluid, thereby achieving the inventive goal of configuring the fluid pressure gradient of the first fluid at the bottom of the formation fracture to be higher than the formation fracture pressure gradient of the energy storage layer at the corresponding depth at the fracture bottom, thereby causing the formation fracture to expand downward. The prior art does not contain any technical solutions for increasing the density of the first fluid to achieve downward fracture expansion, nor does it provide any technical inspiration for increasing fluid density by reducing the particle size to below 200 microns to act as a weighting agent.

[0096] 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.

[0097] 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.

[0098] In a particularly preferred embodiment, in step E1, the type and / or mass of the weighting agent added to the first fluid can be adjusted in real time to maintain the fluid pressure gradient of the first fluid above the formation breakdown pressure gradient. Specifically, the formation breakdown pressure gradient at the bottom of the formation fracture of the energy storage formation is monitored in real time, and based on the real-time monitored formation breakdown pressure gradient data, it is determined whether the type and / or mass of the weighting agent added to the first fluid needs to be adjusted. If the determination 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 breakdown pressure gradient to increase the density and fluid pressure gradient of the first fluid.

[0099] In an alternative embodiment, the formation fractures are monitored in real time to determine whether they are expanding downward. If the formation fractures are 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. Specifically, if the fractures are not expanding downward as designed (due to errors in the calculation of the formation fracture pressure gradient, formation heterogeneity, or data uncertainty), the type and mass of the weighting agent added to the first fluid may be adjusted to increase the density and pressure gradient of the first fluid.

[0100] In another embodiment, the method further includes step E2 of determining whether a fracture parameter of the formation fracture has reached a threshold value. If not, injection of the first fluid into the wellbore is continued; if the threshold value has been 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.

[0101] In one specific implementation, in step E2, 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.

[0102] 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.

[0103] 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.

[0104] 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.

[0105] 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.

[0106] By means of this hydraulic fracturing method, cracks can be controlled to spontaneously expand downward to produce formation cracks, thereby enabling the acquisition of deeper and higher-temperature geothermal resources and other energy without increasing the depth of the wellbore. 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 between a device or feature and 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 figure. For example, if the device in the figure is inverted, the device described as "above" or "on top of" other devices or structures will be subsequently positioned as "below" 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 herein will be interpreted accordingly.

[0107] 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.

[0108] 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.

[0109] 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.

[0110] 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 geothermal energy extraction based on non-connected multiple wellbores, characterized in that: The following steps are involved: S1, selecting two or more wellbores as target wellbores, and creating formation fractures in the target wellbores or opening existing formation fractures; wherein the target wellbores are non-connected; S2, pre-injecting high-pressure fluid into formation fractures of one or more wellbores in the target wellbore, so that the high-pressure fluid stores energy in the formation fractures of the one or more wellbores; wherein the stored energy includes: fluid compression potential energy obtained due to the pressure increase in the overall space formed by the wellbore and the formation fracture, and / or elastic deformation potential energy obtained by driving the formation rock to undergo elastic deformation, and / or stress potential energy obtained by doing work to overcome the fracture closure pressure, and / or formation thermal energy obtained by heat exchange with the formation rock; S3, reversely discharging the injected high-pressure fluid from at least one of the one or more wellbores to release energy; and injecting the reversed high-pressure fluid into formation fractures of one or more other wellbores, so that the high-pressure fluid stores energy in the formation fractures of the one or more other wellbores; S4, discharging the high-pressure fluid from at least one of the one or more wellbores to release energy; and injecting the discharged high-pressure fluid back into the one or more wellbores to store energy.

2. The method according to claim 1, characterized in that In the step S2, it also includes: pre-injecting high-pressure fluid into the formation fractures of the one or more wellbores, and the volume of the injected high-pressure fluid is smaller than the volume of the high-pressure fluid pre-injected into the formation fractures of the one or more wellbores and greater than the pre-fluid threshold volume.

3. The method according to claim 1, characterized in that In step S2, high-pressure fluid is pre-injected into the one or more wellbores and the one or more other wellbores in a manner such that the fracture pressure of the formation fracture is higher than the fracture closure pressure.

4. The method according to claim 1, wherein In step S3 and step S4, after the reverse high-pressure fluid is injected into the corresponding wellbore, the wellhead of the corresponding wellbore is plugged for a time T to store energy.

5. The method according to claim 1, wherein A fluid loss control agent is added to the high-pressure fluid.

6. The method according to claim 1, characterized in that In step S3 and step S4, the method further includes injecting additional high-pressure fluid into the one or more wellbores and the one or more other wellbores respectively to compensate for the filtration loss of the high-pressure fluid.

7. The method according to claim 1, characterized in that Between step S2 and step S3, there is also a step of monitoring whether there is a demand for power generation or heating. When it is monitored that there is a demand for power generation or heating, step S3 is executed, otherwise it is not executed.

8. The method according to claim 7, characterized in that Between step S3 and step S4 is a step of monitoring whether there is still a demand for power generation or heating. When it is monitored that there is still a demand for power generation or heating, step S4 is executed, otherwise it is not executed.

9. A system for implementing the method for geothermal energy extraction based on non-connected multiple wellbores according to any one of claims 1 to 8, characterized in that: include: A fracturing device configured to create formation fractures or open existing formation fractures in two or more target wellbores, wherein the target wellbores are configured to be non-connected; An injection and flowback device is configured to pre-inject a high-pressure fluid into formation fractures in one or more target wellbores, so that the high-pressure fluid stores energy in the formation fractures of the one or more wellbores; wherein the stored energy includes: fluid compression potential energy obtained due to the pressure increase in the overall space formed by the wellbore and the formation fractures, and / or elastic deformation potential energy obtained by driving the formation rock to undergo elastic deformation, and / or stress potential energy obtained by doing work to overcome the fracture closure pressure, and / or formation thermal energy obtained by heat exchange with the formation rock; The injection and discharge device is further configured to discharge the injected high-pressure fluid from at least one of the one or more wellbores to release energy; and to inject the discharged high-pressure fluid into the formation fractures of one or more other wellbores, so that the high-pressure fluid stores energy in the formation fractures of the one or more other wellbores; The injection and discharge device is further configured to discharge the high-pressure fluid from at least one of the one or more wellbores to release energy; and to re-inject the discharged high-pressure fluid into the one or more wellbores to store energy; The power generation or heating device is configured to receive the energy released by the high-pressure fluid during the reverse discharge process and convert it into electrical energy or thermal energy.

10. The system according to claim 9, characterized in that The injection device is further configured to pre-inject high-pressure fluid into the formation fractures of the one or more other wellbores, wherein the volume of the injected high-pressure fluid is smaller than the volume of the high-pressure fluid pre-injected into the formation fractures of the one or more wellbores and is larger than a pre-fluid threshold volume; The system further comprises: a plugging device configured to plug a target wellbore so as to allow high-pressure fluid in formation fractures of the target wellbore to store energy; A monitoring device configured to monitor whether there is external demand for power generation or heating; A control device is capable of receiving monitoring data from the monitoring device and issuing working instructions to the injection and reverse flow device, the plugging device and the power generation or heating device.

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