To reduce fluid loss or inflow in closed-loop geothermal systems.

Abstract

The method includes circulating a heat transfer working fluid in a closed loop between a geothermal well present in a subsurface region and at least one of a heat exchanger or a turbine, the well being substantially sealed to limit fluid loss of the working fluid to the subsurface region, and while circulating the working fluid, at least one of a viscosity of the working fluid or a pressure differential between the working fluid and the subsurface region is controlled in association with fluid flow between the subsurface region and the geothermal well.

Description

[Technical Field]

[0001] This disclosure relates to a closed-loop geothermal system. [Background technology]

[0002] A closed-loop geothermal system involves a working fluid circulating within a well drilled into an underground region. The working fluid absorbs heat from the underground region, and this heat can be recovered to generate electricity or for other uses. The system is closed-loop in that it is constructed to limit, and ideally prevent, the exchange of fluid with the surrounding geological formations of the underground region. [Prior art documents] [Patent Documents]

[0003] [Patent Document 1] U.S. Patent Application Publication No. 2019 / 0346181 [Patent Document 2] U.S. Patent Application Publication No. 2020 / 0011151 [Overview of the Initiative] [Problems that the invention aims to solve]

[0004] This disclosure relates to a closed-loop geothermal system. [Means for solving the problem]

[0005] Certain embodiments of the subject matter herein can be carried out as methods. The method includes circulating a heat transfer working fluid in a closed loop between a geothermal well located in an underground region and at least one of a heat exchanger or a turbine. The geothermal well is substantially sealed to limit fluid loss of the working fluid to the underground region. While circulating the working fluid, at least one of the viscosity of the working fluid or the pressure difference between the working fluid and the underground region is controlled in relation to the fluid flow between the underground region and the geothermal well.

[0006] Embodiments that can be combined with any of the other embodiments may include the following features: The geothermal well may comprise a surface well extending from the ground surface into a subsurface region and a lateral well extending from the surface well in the subsurface region. The step of circulating the working fluid may include circulating the working fluid in a closed loop between the heat exchanger, the surface well, and the lateral well.

[0007] Embodiments that can be combined with any of the other embodiments may include the following features: At least a portion of the lateral well can be sealed with a sealant embedded in the subsurface region.

[0008] An embodiment that can be combined with any of the other embodiments may include the following feature: The surface well may be substantially vertical.

[0009] Embodiments that can be combined with any of the other embodiments may include the following features: at least a portion of the length of the surface well may be protected by casing, and the majority of the length of the lateral well may be bare.

[0010] Embodiments that can be combined with any of the other embodiments may include the following feature: At least a portion of the length of the lateral well can be protected by casing.

[0011] An embodiment that can be combined with any of the other embodiments may include the following features: The working fluid may be shear-reducing.

[0012] Embodiments that can be combined with any of the other embodiments may include the following features: The step of circulating the working fluid may include circulating the working fluid in the surface well at a higher mean shear rate than in the side well.

[0013] An embodiment that can be combined with any of the other embodiments may include the following feature: The Reynolds number of the fluid flow in the lateral well may exceed 3,000.

[0014] Aspects that can be combined with any of the other aspects may include the following. By emulsifying the gas in the working fluid, the pressure difference between the working fluid and the underground region can be controlled towards the target pressure difference.

[0015] Aspects that can be combined with any of the other aspects may include the following. By adding low-density particles to the working fluid, the pressure difference between the working fluid and the underground region can be controlled towards the target pressure difference.

[0016] Aspects that can be combined with any of the other aspects may include the following. By adding a material having a density higher than that of the working fluid to the working fluid, the pressure difference between the working fluid and the underground region can be controlled towards the target pressure difference.

[0017] Aspects that can be combined with any of the other aspects may include the following. By flowing a second fluid having a density different from that of the working fluid together with the working fluid, the pressure difference between the working fluid and the underground region can be controlled towards the target pressure difference.

[0018] Aspects that can be combined with any of the other aspects may include the following. By controlling the temperature of the working fluid, the pressure difference between the working fluid and the underground region can be controlled towards the target pressure difference.

[0019] Aspects that can be combined with any of the other aspects may include the following. By controlling the pressure at which the working fluid is circulated, the pressure difference between the working fluid and the underground region can be controlled towards the target pressure difference.

[0020] Using a fluid flow restriction having specific flow characteristics in the well, the pressure difference between the working fluid and the underground region can be controlled towards the target pressure difference.

[0021] Aspects that can be combined with any of the other aspects may include the following. The pressure difference between the working fluid and the underground region is the fluid of the working fluid in the well level to the fluid in the well close to the surface levelBy adjusting in relation to the vapor space above, it can be controlled towards the target pressure difference.

[0022] Aspects that can be combined with any of the other aspects may include the following features. By controlling the circulation rate of the working fluid, the pressure difference between the working fluid and the underground region can be controlled towards the target pressure difference.

[0023] Aspects that can be combined with any of the other aspects may include the following features. By selecting a specific diameter of the surface wellbore or lateral wellbore, the pressure difference between the working fluid and the underground region can be controlled towards the target pressure difference.

[0024] Certain aspects of the subject matter herein can be implemented as a method. The method includes the step of selecting a working fluid to exhibit viscosity to control the loss of the working fluid to the underground region. The loss occurs while the working fluid is circulated in a closed loop between a geothermal well existing in the underground region and at least one of a heat exchanger or a turbine. Heat is extracted from the working fluid by the heat exchanger while the working fluid is circulating in the closed loop.

[0025] Aspects that can be combined with any of the other aspects may include the following features. The step of selecting the working fluid may include selecting a shear-thinning fluid as the working fluid.

Brief Description of the Drawings

[0026] [Figure 1] It is a schematic diagram of a closed-loop geothermal system according to the concept herein. [Figure 2] It is a schematic diagram of a part of a lateral wellbore according to the concept herein. [Figure 3] It is a graph of the measured loss of fluid volume over time from a closed-loop system before and after the addition of a shear-thinning additive. [Figure 4] It is a schematic diagram of a closed-loop system with subsurface flow restrictions. [Figure 5]This is a schematic diagram of a closed-loop system with a target fluid level. [Figure 6] This is a flowchart illustrating the conceptual methodology used in this specification. [Modes for carrying out the invention]

[0027] In a closed-loop geothermal system, a working fluid is circulated within a closed loop that includes a subsurface well and a surface or (at least partially) subsurface facility configured to extract heat for use. In exceptional cases, the facility includes a heat exchanger for transferring heat to relevant processes, such as a Rankine cycle (e.g., an organic Rankine cycle) or other thermal cycle that extracts heat and generates electricity, an industrial steam generation process, agricultural or residential use, or other processes. In specific cases, the facility directly uses the heated working fluid, for example, by passing it through an expander (e.g., a turbine) that drives a generator, or by directly using the heat of the working fluid in an industrial, agricultural, or residential process. In such a closed-loop system, contact between the working fluid and the natural fluids of the subsurface region (e.g., groundwater) is substantially eliminated or minimized by piping, well casing, well sealants, and other components or features of the system.

[0028] According to the concepts herein, in certain examples, a closed-loop system comprises one or more inlet wells and one or more outlet wells, the inlet and outlet wells being connected by one or more lateral wells that branch off from the inlet wells, intersect the outlet wells, and / or are otherwise fluidly connected to the outlet wells (e.g., by cracks extending between the wells). In certain examples, the lateral wells are horizontal, acute or obtuse with respect to the vertical, or otherwise non-vertical. The inlet and outlet wells may be connected by a network of multiple lateral wells. In certain examples, one lateral well, or some or all of multiple lateral wells, may not be casing-protected or may be bare, but may be sealed (entirely or substantially) against fluid flow in or out of the system, for example, by a sealant embedded in the subsurface region where the well is drilled. However, because the seal created by the sealant may not be completely impermeable, and / or due to cracks, other fissures, or permeability in the seal created by the sealant, some fluid may leak into or out of the system. Such fluid flow into or out of the system may result in a decrease in the volume of the working fluid and / or dilution. Such fluid exchange may result in a decrease in the efficiency of the geothermal system and / or other undesirable effects. According to some examples of the concepts herein, such fluid flow into or out of a closed-loop system can be eliminated or reduced.

[0029] Figure 1 illustrates a closed-loop geothermal system by concept as used herein. In specific examples, a closed-loop geothermal well system may be a system such as that developed by Eavor Technologies Inc. in Calgary, Alberta, which includes, for example, a network of sealed lateral wells that exchange heat with the subsurface region.

[0030] Referring to Figure 1, System 100 comprises a closed-loop system having a well 102 drilled in an underground region 104. In the illustrated example, well 102 comprises adjacent inlet surface wells 120 and outlet surface wells 130, each extending between the ground and the underground region 104 and connected within the underground region 104 by one or more lateral wells 140. In the illustrated example, the lateral wells 140 include multiple pairs of multiple lateral wells intersecting at tip 142, i.e., multiple pairs of multiple lateral wells that, in the closed loop, branch off from the inlet surface well 120, extend a certain distance into the underground region 104, and return from tip 142 towards (and return to and connect with) the outlet surface well 130. In other examples, the inlet and outlet surface wells may be separated by a longer distance, with the lateral wells connecting them below the surface to form a U-shape.

[0031] In the illustrated example, the inlet surface well 120 and the outlet surface well 130 are vertical wells drilled substantially straight (i.e., without the use of inclined drilling methods or equipment). The lateral well 140 is drilled substantially horizontally, such as by using inclined drilling methods and equipment, and includes a curve in the path of the lateral well 140, which begins at a vertical start. In other examples, the inlet surface well and / or the outlet surface well may be non-vertical and / or drilled using inclined drilling. In some examples, some or all of the lateral wells are non-horizontal. In some (but not all) examples, the lateral well 140 is drilled to follow the geological dip of the strata in the subsurface region. In some examples, the lateral well 140 can be 2,000 to 8,000 meters or more in length and have a depth from the surface of any of 1,000 to 8,000 meters.

[0032] In some examples, the majority of the length of the inlet surface well 120 and the outlet surface well 130 is protected by casing, and the lateral well 140 is bare. In some examples, the entire length of the lateral well 140 can be bare, and in other examples, the lateral well can be bare at the junction where the lateral well 140 intersects with the inlet surface well 120 and the outlet surface well 130 (and / or at the tip 142), and can be lined over at least a portion of the distance between those junctions and / or between the tips (for example, it can be lined where the subsurface region is prone to collapse due to faults and / or non-laminate geological material, but otherwise it can be bare). As will be further illustrated with reference to Figure 2, in some examples, part or all of the length of the lateral well 140 can be substantially sealed without the use of casing by forming a substantially fluid-impermeable interface between the lateral well and the subsurface region.

[0033] In the illustrated example, system 100 further includes facility 110 located between an inlet surface well 120 and an outlet surface well 130. The well 102 can be sealed, and a working fluid is added to the closed loop and circulated in the system to absorb heat from the subsurface region 104. In certain examples, facility 110 includes a heat exchanger for extracting heat from the working fluid and transferring the heat to relevant processes such as a Rankine cycle (e.g., an organic Rankine cycle) or other thermal cycle that generates electricity, an industrial steam generation process, agricultural or residential use, or other processes. In certain examples, as an alternative to or addition to the heat exchanger, facility 110 directly uses the heated working fluid, such as passing it through an expander (e.g., a turbine) that drives a generator, or directly using the heat of the working fluid in an industrial, agricultural, or residential process. In some examples, facility 110 is located on or near the ground surface, and in others, facility 110 may be located partially or completely in a subsurface location.

[0034] In some examples, the working fluid may be a fluid with a nonlinear temperature-enthalpy relationship to maximize the temperature difference and heat transfer between the fluid and the subsurface region 104. In some examples, the working fluid may be an aqueous electrolyte as described in Patent Document 1. In some examples, the working fluid may be water-based. In some examples, the working fluid may have a high heat capacity (i.e., greater than 3.0 kJ / kg-K) and / or a high coefficient of thermal expansion (i.e., 10 -4 K -1 It may have a larger ()). In addition to its high heat transfer characteristics, the working fluid may be environmentally harmless, non-toxic, stable at high temperature and pressure, flowable, and provide compressive strength to the subsurface layers.

[0035] In the closed-loop system of Figure 1, the working fluid circulates within the system with no or virtually no loss of working fluid to the environment, and with no or virtually no flow of natural fluids from the environment (e.g., surface water or groundwater) into the system, and is isolated from subsurface or surface fluids (by a sealant, although in certain examples, isolation may be created by piping, casing, and / or other means, as an alternative or additional measure). Periodic adjustment and maintenance of a closed-loop system may require the working fluid to be added to, removed from, or adjusted (e.g., with respect to volume, pressure, and / or composition) while the system remains closed if it otherwise is not.

[0036] Figure 2 is a schematic diagram of a portion of a lateral well 140 according to the concept herein. Referring to Figure 2, the lateral well 140 is formed through a subsurface region 104, as previously described with reference to Figure 1. In the illustrated example, the lateral well 140 is sealed with a sealant 204 embedded in the subsurface region. Such sealing can be carried out in various ways. For example, in some cases, a drilling fluid can be used during the drilling operation, which solidifies into a solid upon contact with the rock, creating a substantially impermeable seal. In some cases, as an addition or alternative to depositing sealant material, the drilling fluid may damage the rock surrounding the well, reducing the permeability of the rock. Several such methods are described in Patent Document 2. In some cases, a fluid slag with sealant may be added to the drilling fluid during drilling. In some cases, the lateral well 140 is sealed by treating the well after drilling, as an alternative or addition to sealing during the drilling operation. In some cases, all or part of the lateral well 140 is casing protected. In some instances where a portion (but not all) of the lateral well 140 is casing-protected, some or all of the uncasing-protected portion of the lateral well 140 is sealed with a sealant 204 embedded in the subsurface region, as previously described.

[0037] After drilling the lateral well 140, a working fluid 202 is introduced, flowing through the lateral well 140 and circulating throughout the system, as previously described with reference to Figure 1. Because the seal created by the sealant 204 may not be completely impermeable, and / or due to cracks 210, other fissures, or other holes in the embedded deposit of the sealant 204, some working fluid 202 may leak from the lateral well 140 into the subsurface region 104 ("leakage"), and / or some fluid from the formation may leak from the subsurface region 104 into the lateral well 140. In a closed-loop system, such flows into or out of the subsurface region may be undesirable because they may result in a decrease in volume and / or dilution of the working fluid 202 (for example).

[0038] In some examples of this disclosure, outflow from the system can be mitigated by increasing the viscosity of the working fluid, because the increase in viscosity has the effect of reducing the fluid flow through cracks or fissures (such as crack 210), and / or through the sealant 204 and / or subsurface region 104, to a degree that the fluid can seep through. Such an increase in viscosity can be achieved by selecting a suitable working fluid that exhibits the desired viscosity, and / or by adding material to the working fluid to increase the viscosity. For example, in some examples, for a well 102 in subsurface region 104, the suitable viscosity of the working fluid is about 10 centipoise (cP), assuming a mass flow rate of 60 kg / s and 12 lateral wells, each with a diameter of 8.5 inches. Suitable additives for increasing viscosity may, in some examples, be starch, partially hydrolyzed polyacrylamide (PHPA) polymer, or hydroxyethylcellulose (HEC).

[0039] In some examples of this disclosure, the viscosity of a working fluid can be increased by adding additives to the working fluid that exhibit shear-devisiating behavior. Shear devisiating is a non-Newtonian behavior of a fluid in which viscosity increases under smaller shear strains and decreases under larger shear strains. Examples of suitable shear-devisiating additives in some examples of this disclosure include 1m 3The additive concentration is approximately 0.6 kg per working fluid, which is xanthan rubber. The shear strain force acting on the working fluid can vary within different locations or sections of a closed-loop system, depending on factors such as the shape of the well (size and shape, etc.). For example, in the case of a closed-loop system such as the one shown in Figure 1, where the inlet surface well 120 and outlet surface well 130 are substantially vertical and the side well 140 is substantially horizontal, the shear-deviscating fluid in well 102 will exhibit a lower average viscosity in the inlet surface well 120 and outlet surface well 130 rather than in the side well 140, due to a higher flow viscosity in the substantially vertical well (assuming the surface well has the same diameter and the same fluid temperature as the side well). Because higher viscosity of the working fluid has the disadvantage of increasing hydraulic pressure in the power generation system (and consequently resulting in wasted energy), such shear-thinning behavior is particularly advantageous in systems such as those shown in Figure 1, which utilize substantially vertical wells that can be (at least partially) casing-protected and substantially horizontal wells that can be bare. Relatively high viscosity in uncasing-protected areas (such as the lateral well 140 in the example shown in Figure 1) minimizes working fluid loss from the uncasing-protected well to the subsurface region, while lower viscosity in at least partially casing-protected areas (such as the substantially vertical surface wells 120 and 130 in Figure 1) where fluid loss is less of a concern minimizes such hydraulic loss in those areas.

[0040] Furthermore, laminar and turbulent flow of the working fluid can be considered. At Reynolds numbers above 3000, the thermal performance of the loop can be minimized by viscosity, while below 3000, viscosity can have a detrimental effect on system performance. Preferably, in some examples, the shear-deviscating additive to the working fluid 202 in Figure 2 allows the working fluid 202 to exhibit sufficient viscosity in surface wells to minimize losses to the subsurface region while maintaining Reynolds numbers above 3000 in side wells.

[0041] Figure 3 is a graph of the measured loss of fluid volume over time from a closed-loop system before and after the addition of a shear-devising additive that increases viscosity. The measurements shown in Figure 3 are from a closed-loop geothermal system with substantially vertical inlet and outlet surface wells connected by a lateral well in the subsurface region, where the lateral well is bare but substantially sealed to the fluid flow in and out of the system by a sealing layer embedded in the subsurface region. As can be seen from the first group 302 of the measurements, despite the sealing in the subsurface region, there is a change (i.e., loss) in the volume of working fluid from the system between 0.5 cubic meters and 0.6 cubic meters per day. This loss may be at least partly attributable to incomplete sealing and / or permeability of the sealing agent in the sealing layer in the lateral well. The average viscosity of the working fluid for the first group 302 was approximately 1 cP. At time 304, a shear viscosity-reducing additive (xanthan rubber) was added to the working fluid, increasing its average viscosity to approximately 2 cP. The second group of measurements, 306, shows a loss of between 0.4 and 0.5 cubic meters per day from the system, which is smaller than the loss from the first group, 302. Later, at time 308, additional xanthan rubber was added to the working fluid to increase its average viscosity to approximately 10 cP. The third group of measurements, 310, shows a loss of less than 0.4 cubic meters per day, which is smaller than the loss from the second group, 306. Thus, the addition of shear viscosity-reducing materials was effective in reducing the loss of working fluid from the system.

[0042] In some examples, as an alternative to or in addition to controlling the viscosity of the working fluid as previously described, fluid flow in and out of a closed-loop system, such as those described with reference to Figures 1 and 2, can be mitigated by controlling the pressure difference between the working fluid and the subsurface region. A target pressure difference can be established such that the fluid flow in and out of the system is sufficiently reduced or mitigated as desired. In some examples, for instance, the target pressure difference between the working fluid and the subsurface region is less than 100 kilopascals (kPa), with the working fluid pressure slightly higher than the subsurface region pressure (stacked pressure). In some examples, the target pressure difference between the working fluid and the subsurface region is zero kPa. In other examples, other pressure differences may be targeted.

[0043] In some cases, the pressure difference between the working fluid and the subsurface region can be controlled by controlling the density of the working fluid, thereby increasing or decreasing the hydrostatic head of the fluid in the well. Specifically, in situations where achieving a target pressure difference requires decreasing the working fluid pressure, decreasing the density of the working fluid can reduce the weight of the fluid column in one or both of the surface inlet and surface outlet wells in the system shown in Figure 1, thereby decreasing the working fluid pressure in the side wells. Similarly, in situations where achieving a target pressure difference requires increasing the working fluid pressure, increasing the density of the working fluid can increase the weight of the fluid column, thereby increasing the working fluid pressure in the side wells.

[0044] For example, in one case, the density of a working fluid can be increased or decreased (respectively) by decreasing or increasing the temperature of the working fluid. For example, if the working fluid is water, the target density is 980 kg / m³. 3 The standard inlet temperature is 20 degrees Celsius, and the water temperature can be heated to 66 degrees Celsius to achieve the target density.

[0045] The density of the working fluid can be reduced in some cases by emulsifying gases in the working fluid that have a lower density than the working fluid itself. For example, 1,000 kg / m³3 98.8% of the weight of the working fluid based on water with a density of 100 kg / m 3 is combined with 1.2% of the weight of the emulsified gas having a density of 900 kg / m 3 to produce a mixed density. In some examples, additives can be added to the working fluid such that air or other gases can be incorporated into the fluid, thereby forming a mixture that contains bubbles or a gas otherwise. Alternatively or additionally, low-density particles such as microcells and / or other hollow or lightweight glass spheres can be added to the working fluid.

[0046] In some examples, the density of the working fluid can be increased by adding barite or other high-density materials to the working fluid. In one example, for instance, 88.3% of the weight of the working fluid based on water with a density of 1,000 kg / m 3 is combined with 11.7% of the weight of a barite solution having a density of 4,480 kg / m 3 to produce a mixed density of 1,100 kg / m 3 .

[0047] In some examples, the density of the working fluid can be controlled by flowing a second fluid through the system. In some examples, for instance, a second fluid with a different density can be mixed with the rest of the working fluid and thus change the overall density of the mixture. Such a fluid can be added at the surface, added with the rest of the working fluid, or injected into the already circulating working fluid. In other examples, instead of or in addition to such a mixture, a slug of fluid with a density different from the rest of the working fluid can be added to the system. For example, a lightweight and low-density slug can be injected above the working fluid advancing downward through a surface inlet shaft and / or above the working fluid advancing upward through a surface outlet shaft, thereby reducing the hydrostatic head of each shaft. Such a slug may be injected via an injection site proximate to the surface or via a feed pipe or other suitable conveyance at other appropriate locations.

[0048] In some cases, the pressure difference between the working fluid and the subsurface region can be controlled by controlling the pressure at which the working fluid is circulated. Pressure can be controlled, for example, by controlling the pressure at which the working fluid is injected into the inlet well. For example, if the target bottom pressure is 40,000 kPa, the surface pressure in a reference example is 200 kPa, and the bottom pressure in the reference example is 39,000 kPa, then the surface pressure can be increased to 1,200 kPa to increase the bottom pressure to the target of 40,000 kPa. Such increases can be achieved in various ways, including by pumping or by utilizing thermal siphon pressure.

[0049] In some cases, the pressure difference between the working fluid and the subsurface region can be controlled by controlling the rate at which the working fluid is circulated. The circulation rate can be controlled, for example, by using flow control valves at the surface so that the hydraulic pressure loss in the vertical section of the well is reduced to a level sufficient to maintain the target bottom pressure. For example, if the target bottom pressure is 55,000 kPa and the reference case bottom pressure is 55,500 kPa, the flow can be increased so that the target bottom pressure is achieved by increasing the hydraulic pressure drop in the vertical section by 500 kPa.

[0050] In some examples, in addition to or as an alternative to other methods described herein, the pressure difference between the working fluid and the subsurface region can be controlled by adding a subsurface flow limit to the wells of a closed-loop geothermal system. Figure 4 is a schematic diagram of a closed-loop geothermal system by concept herein with such a subsurface flow limit. System 400 in Figure 4 comprises a closed-loop geothermal system comprising an inlet surface well 120 through which the working fluid 202 passes and circulates, an outlet surface well 130, and a side well 140, as described with reference to Figures 1 and 2. System 400 further comprises a flow limit 402 positioned within the inlet surface well 120. The flow limit 402 may comprise a reduced-diameter orifice, an adjustable control valve, or other fixed or adjustable limit that can reduce the pressure as the working fluid circulates from the surface well 120 to the side well 140, thereby controlling the pressure difference between the working fluid 202 and the subsurface region 104. The size, shape, and other characteristics of the flow limiter 402 can be selected to produce a specific degree of fluid limiting or pressure drop to yield a desired pressure difference. A narrower limiter in the inlet well may result in a greater pressure drop of the working fluid in the lateral well downstream of the limiter compared to a wider limiter. For example, a bottom-of-well pressure drop of 781 kPa can be achieved with a circular orifice plate with a 14-inch orifice diameter, a mass flow rate of 5 kg / s, a flow coefficient of 1.0, and a flow rate of 1,000 kg / m³. 3 This can be achieved with a working fluid density of [value missing].

[0051] In some examples, with the addition or replacement of the flow limit 402, the diameters of the inlet surface well 120, the outlet surface well 130, and / or the lateral well 140 can be selected to control the differential pressure between the working fluid and the subsurface region. For example, a vertical well with a diameter of 216 mm, a length of 4.5 km, and a water circulation velocity of 80 kg / s at 60°C provides a bottom pressure of 43,400 kPa. If the target bottom pressure is 42,000 kPa, the diameter of the vertical well can be reduced to 176 mm to achieve the target bottom pressure.

[0052] In some examples, with the addition or substitution of other methods described herein, the differential pressure between the working fluid and the underground region is the fluid of the working fluid in the well. level The fluid inside the well, close to the surface. level It can be controlled by adjusting in relation to the steam space above. Figure 5 shows such an adjusted fluid. level This is a schematic diagram of a closed-loop geothermal system according to the concept herein, accompanied by the following. System 500 in Figure 5 comprises a closed-loop geothermal system including an inlet surface well 120 through which a working fluid 202 passes and circulates, an outlet surface well 130, and a side well 140, as described with reference to Figures 1 and 2. level Pressure 502 is regulated (decreased) by the presence of steam 504, which forms a steam space 506. In one example, the bottom-of-pit pressure (without steam space) in the reference case is 65,000 kPa, the target bottom-of-pit pressure is 62,000 kPa, the working fluid density is 1,000 kg / m³, and the steam density is 10 kg / m³. In this example, a steam space of 305 m would achieve the target bottom-of-pit pressure.

[0053] Figure 6 is a flowchart of the process of the conceptual method described herein. The method begins in step 602, in which the well is formed by drilling a suitable well in the subsurface region. In the example shown in Figure 1, well 102 is formed by drilling an inlet surface well 120 and an outlet surface well 130, and connecting these surface wells by drilling one or more lateral wells 140 using conventional inclined drilling techniques. In some examples, the surface wells are casing protected, while the lateral wells are left bare. The process proceeds to step 604, in which the lateral wells are sealed to reduce or substantially eliminate fluid flow in or out of the wells. In some examples, sealing can be performed by embedding a sealant (such as sealant 204 as described with reference to Figure 2) in the subsurface region.

[0054] The process proceeds to step 606, in which a working fluid (such as working fluid 202 as described in Figure 2) is selected and circulated within the system. Because the sealant may not be completely impermeable, and / or due to cracks, other fissures, or holes in the sealant, some fluid may leak into or out of the system. The process proceeds to step 608, in which, while the working fluid is circulating, at least one of the viscosity of the working fluid or the pressure difference between the working fluid and the subsurface region is controlled using one or more of the techniques or methods described above, thereby reducing the fluid flow between the subsurface region and the well. In step 610, thermal energy is extracted from the system (e.g., using a heat exchanger) and used for power generation or other applications.

[0055] This disclosure contains many specific implementation details, but these should not be interpreted as limitations on the subject matter or limitations on what can be claimed, but rather as descriptions of features that may be specific to a particular implementation. Certain features described in this disclosure in separate implementation contexts may also be implemented in combination or in a single implementation. Conversely, various features described in a single implementation context may also be implemented separately or in any appropriate partial combination in multiple implementations. Furthermore, even if a previously described feature is described as acting on a particular combination and may initially be claimed as such, one or more features from the claimed combination may, in some cases, be cut from the combination, and the claimed combination may be directed towards a partial combination or a variation of a partial combination.

[0056] The specific implementation of the subject matter has been described. Nevertheless, it is understood that various variations, substitutions, and modifications are possible. Although the actions are described in a specific order in the drawings or claims, this should not be understood as requiring that such actions be performed in the specific order shown, or in a sequential order, or that all shown actions be performed (some actions may be considered optional) in order to achieve the desired result. Accordingly, the implementation of the examples described above does not define or limit this disclosure. [Explanation of Symbols]

[0057] 100 Systems 102 Well 104 Underground area 110 facilities 120 Inlet surface well 130 Outlet surface well 140 Side well 142 Tip 202 Working fluid 204 Sealant 210 Cracks 302 First group of measurements 304 hours 306 Second group of measurements 308 hours 310 Third group of measurements 400 System 402 Flow Restriction 500 Systems 502 Fluid level

Claims

1. A step of circulating a heat transfer working fluid in a closed loop between a geothermal well located in an underground region and at least one of a heat exchanger or a turbine, wherein the geothermal well has one or more wells and is substantially sealed to limit fluid loss of the working fluid to the underground region, and at least one of the one or more wells has a bare-bore length portion of the well; A step of selecting a target pressure difference between the pressure of the working fluid and the stratified pressure of the subsurface region, in accordance with the fluid flow between the bare-bore portion of the well and the subsurface region while the working fluid is circulating, wherein the target pressure difference is selected such that the fluid flow between the bare-bore portion of the well and the subsurface region decreases. The steps include controlling the pressure difference between the pressure of the circulating working fluid and the cumulative pressure of the underground region toward the target pressure difference while the working fluid is circulating, Methods that include...

2. The method according to claim 1, wherein one or more wells include a surface well extending from the ground surface to the underground region, and the bare-bore portion of the well is a lateral well extending from the surface well in the underground region, and the step of circulating the working fluid includes circulating the working fluid in a closed loop between the heat exchanger, the surface well and the lateral well.

3. The method according to claim 2, wherein at least a portion of the lateral well is sealed with a sealant embedded in the underground region.

4. The method according to claim 2, wherein the surface well is substantially vertical.

5. The method according to claim 2, wherein at least a portion of the length of the surface well is protected by a casing, and the majority of the length of the lateral well is an open well.

6. The method according to claim 2, wherein at least a portion of the length of the lateral well is protected by a casing.

7. The method according to claim 1, wherein the working fluid is shear-reducing.

8. The method according to claim 2, wherein the step of circulating the working fluid includes circulating the working fluid in the surface well at a higher mean shear rate than in the side well.

9. The method according to claim 2, wherein the Reynolds number of the fluid flow in the lateral well exceeds 3,000.

10. The method according to claim 1, wherein controlling toward the target pressure difference includes at least emulsifying the gas in the working fluid.

11. The method according to claim 1, wherein controlling toward the target pressure difference includes adding at least low-density particles to the working fluid.

12. The method according to claim 1, wherein controlling toward the target pressure difference includes adding a material having a density higher than that of the working fluid to the working fluid.

13. The method according to claim 1, wherein controlling toward the target pressure difference includes, at least, flowing a second fluid having a density different from that of the working fluid together with the working fluid.

14. The method according to claim 1, wherein controlling toward the target pressure difference includes at least controlling the temperature of the working fluid.

15. The method according to claim 1, wherein controlling toward the target pressure difference includes at least controlling the pressure at which the working fluid is circulated.

16. The method according to claim 2, wherein controlling toward the target pressure difference includes at least using a fluid flow limiter that reduces the pressure as the working fluid flows in the geothermal well from the surface well to the side well.

17. The method according to claim 1, wherein controlling toward the target pressure difference includes adjusting the fluid level of the working fluid in the geothermal well by introducing steam into a steam space above the fluid level in the geothermal well, which is close to the ground surface.

18. The method according to claim 1, wherein controlling toward the target pressure difference includes controlling the circulation speed of the working fluid.

19. The method according to claim 2, wherein controlling toward the target pressure difference includes selecting a specific diameter of the surface well or the side well.

20. The method according to claim 1, wherein the target pressure difference is less than 100 kilopascals.

21. The method according to claim 1, wherein the target pressure difference is 0 kilopascals.

22. The method according to claim 1, wherein the step of controlling the pressure difference toward the target pressure difference comprises the step of circulating the working fluid at a pressure higher than the stage pressure.

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