System for generating energy from geothermal resources and methods of operation and construction thereof

Abstract

The present disclosure describes a system and method for generating energy from geothermal resources. The system includes an injection well and a production well extending underground into a rock formation, a first transverse section connected to the injection well and a second transverse section connected to the production well, the first transverse section and the second transverse section being connected together using a multi-branch connector, to define a pressure-tested downhole circuit within the formation and form a heat transfer arrangement with the formation. The downhole loop is sleeved with steel and is cemented in place within a rock formation. The downhole circuit is for receiving a working fluid that is capable of undergoing a phase change between a liquid state and a gaseous state within the downhole circuit due to heat transferred from the formation. The system also includes a pump for circulating the working fluid, a turbine system for converting the flow of the working fluid to electrical power, and a cooler.

Description

Technical Field

[0001] The present disclosure generally relates to generating energy from geothermal resources, and more particularly, to systems for generating energy from geothermal resources and methods of operating and constructing the same. Background Art

[0002] Systems for generating energy from geothermal resources (also referred to herein as geothermal power generation systems) are designed such that a working fluid or water is circulated underground for heating and then the thermal energy is brought back to the surface and converted into electricity. The working fluid or water is then cooled and returned to the underground heat source.

[0003] In some known geothermal power generation systems, the working fluid flowing underground is exposed to underground rock formations such that the first working fluid picks up debris, rocks, and other solids as it flows underground. Picking up debris, rocks, and other solids can cause problems for any equipment having moving parts, such as pumps required to assist in circulating the working fluid or turbines for generating electricity from the thermal energy of the working fluid returning to the surface.

[0004] One way to address this problem is to provide a filter in the flow path of the working fluid or before the working fluid enters any mechanical equipment. The filter can help mitigate the problem of the working fluid carrying debris or solids into any mechanical equipment. However, the filter needs to be replaced, thus increasing the maintenance cost. In addition, the filter is an additional component and thus can result in another potential failure point of the system.

[0005] Another way to address the debris problem in the working fluid is to use a binary cycle power plant where two working fluids are used, where the first working fluid is heated underground and then passes through a separate second working fluid in a second loop, where the second working fluid is heated to drive a turbine. While this can prevent the turbine from encountering debris, the pump required for the first working fluid to circulate underground still has to deal with the debris problem. In addition, binary cycle power plants are not efficient because they have a high parasitic load and a significant amount of heat is lost when transferring heat from the first working fluid to the second working fluid.

[0006] In addition, the working fluid circulating underground may also start to erode the rock surface in the flow path of the working fluid. Erosion of the rock surface can lead to instability of the underground path and may also cause environmental damage. Therefore, to prevent erosion, the flow rate of the working fluid must be minimized to protect the integrity of the rock formation. This will result in an increased residence time of the working fluid underground.

[0007] When the working fluid flows underground, it may also leak into the surrounding environment through the gaps in the underground rock formations, causing underground pollution. Therefore, for environmental protection, the working fluid needs to be an environmentally friendly fluid, such as water. Even so, if the first working fluid picks up any non-environmentally friendly substances along its path, such as picking up oil when flowing through a pump, these substances may still leak into the external environment.

[0008] In other known geothermal energy systems, in order to prevent erosion, environmental leakage, and prevent the working fluid from containing debris in the underground loop, a chemical layer, a chemical treatment layer, or a polymer coating layer is provided, where the polymer coating layer is applied to the rock formation and seals it off from the circulating fluid. However, the polymer coating layer has some inherent defects, including the inability to perform a pressure test on the underground polymer layer loop. If a pressure test cannot be performed on the underground loop, it is impossible to ensure whether the polymer coating layer can remain stable at the depth where the working fluid is under high pressure, nor can it ensure whether the polymer coating layer will react with different working fluids, which may lead to leakage, including underground pollution.

[0009] In addition, the polymer coating layer itself is also subject to erosion. Once eroded, it may lead to the erosion of the rock formation. This results in the pollution of the first working fluid. To prevent this, the polymer coating layer may need to be applied in several layers and may also need to be continuously replaced, which leads to high maintenance costs, additional downtime, and loss of production time. Even after the polymer coating layer is applied, it is difficult to verify whether the entire rock formation and the path / loop of the first working fluid are completely coated, let alone ensure the thickness or integrity of the polymer coating layer.

[0010] In other prior arts, such as U.S. Patent Application Publication No. 2018 / 0291880 and International Patent Application Publication No. WO2022029699, a casing is provided. However, the casing is not cemented, which may lead to instability. In addition, the casing is not pressure-tested, which may lead to instability under high-pressure depths or when the flow rate of the working fluid underground is high or variable. These instabilities may lead to poor operating performance, and if the working fluid is not water and leaks, such as in the case of using two working fluids mentioned in the above patent applications, it may lead to potential underground pollution. Underground pollution may occur through the leakage of the working fluid into the gaps in the rock formation. The gaps in the rock formation may be pre-existing unknown fractures or may be fractures induced during the drilling of a geothermal power generation system. If any working fluid leakage occurs, the fluid may be transported through the fractures and enter sensitive resources (such as groundwater).

[0011] In other prior arts, such as in U.S. Patent Application Publication No. 2011 / 0048005, a continuous string of tubing is cemented throughout the entire length within two connected wellbores, specifically starting from the injection wellhead of one wellbore, extending underground and passing through an underground near-horizontal pipeline, and then returning along the production well until the production wellhead. This allows for the transportation of a working fluid underground, which undergoes a phase change due to heat from the surrounding underground rocks and is then transported back to the surface for use in a power plant. There is only a single underground horizontal pipeline connection between the injection wellhead and the production wellhead. In this type of system, the distance between the injection wellhead and the production wellhead, as well as the single underground horizontal pipeline, tend to be quite long in order to achieve effective heat transfer between the rock formation and the production fluid. The large distance between the injection wellhead and the production wellhead tends to result in a large footprint both above and below the ground. This increases the overall cost of the system because additional lengths of pipeline are required between the injection wellhead and the production wellhead above the ground, additional volumes of working fluid are required for the additional lengths of pipeline above the ground, and heat loss may occur due to the additional time of the production fluid above the ground, which may increase the parasitic load. Additionally, the construction technique provided in U.S. Patent Application Publication No. 2011 / 0048005 does not allow for a pressurized connection between two segments.

[0012] Accordingly, it would be advantageous to find a solution in which a geothermal power generation system can have an underground loop that includes a barrier that can be pressure tested and that minimizes the risk of erosion, entrapment of debris, and leakage into the surrounding rock formation and environment. Additionally, it would be advantageous to find a solution in which maintenance is minimized, costs are saved, and downtime is minimized, and in which there are fewer points of failure within the system. SUMMARY OF THE INVENTION

[0013] According to various aspects of the present invention, a system for generating energy from geothermal resources is provided. The system includes an injection well extending underground into a rock formation, the injection well having an upper end and a lower end. The system further includes a production well extending underground into the rock formation and adjacent to the injection well, the production well having an upper end and a lower end. Additionally, the system includes a first lateral section connected to a location of the injection well and extending away therefrom, and a second lateral section connected to a location of the production well and extending away therefrom, wherein the first lateral section and the second lateral section are connected together using a multi-branch connector, and the length of each of the first lateral section and the second lateral section is greater than the distance between the upper end of the injection well and the upper end of the production well. Each of the injection well, the production well, the first lateral section, and the second lateral section is sleeved with steel and cemented in place within the rock formation. The injection well, the first lateral section, the multi-branch connector, the second lateral section, and the production well cooperate with each other to define a pressure-tested downhole circuit within the rock formation and form a heat transfer arrangement with the rock formation, the pressure-tested downhole circuit being configured to receive a working fluid that can undergo a phase change between liquid and gas due to heat transferred from the rock formation within the pressure-tested downhole circuit. The system further includes a pump fluidly connected to the injection well, the pump being configured to circulate the working fluid through the pressure-tested downhole circuit. Additionally, the system includes a turbine system fluidly connected to the production well, the turbine system being operable to convert mechanical energy generated by the flow of the working fluid into electrical power. The system further includes a cooler fluidly connected between the pump and the turbine system for cooling the working fluid.

[0014] The system may further include an injection well surface casing surrounding the inlet of the injection well, wherein the injection well surface casing is partially located above the surface and is configured to prevent the working fluid from escaping into the rock formation.

[0015] The system may further include a production well surface casing surrounding the outlet of the production well, wherein the production well surface casing is partially located above the surface and is configured to prevent the working fluid from escaping into the rock formation.

[0016] The injection well includes an inlet and the production well includes an outlet, the inlet and the outlet being positioned close to each other on the surface, and the distance between the inlet and the outlet being from 7 m to 50 m.

[0017] The system may have a surface area of 22500 m 2 above ground.

[0018] The working fluid may be a homogeneous working fluid.

[0019] Alternatively, the working fluid may be a heterogeneous working fluid.

[0020] The depth of the injection well may be from 1000 m to 4000 m.

[0021] The length of the first horizontal section can be from 2000 m to 4000 m.

[0022] The length of the second horizontal section can be from 2000 m to 4000 m.

[0023] The depth of the production well can be from 1000 m to 4000 m.

[0024] The first horizontal section can be longer than the second horizontal section, and among them, the depth of the first horizontal section is greater than the depth of the second horizontal section.

[0025] The first horizontal section can be located at the same depth as the second horizontal section. The first horizontal section extends away from the lower end of the injection well at a first angle, and the second horizontal section extends away from the lower end of the production well at a second angle.

[0026] During operation, the downhole loop that has undergone pressure testing can be configured to receive fluid pressurized to 7 MPa to 31 MPa.

[0027] The downhole loop that has undergone pressure testing can withstand a pressure of at least 7 MPa.

[0028] The pump can be a positive displacement pump with a variable speed drive controller.

[0029] In addition, the positive displacement pump can be selected from the group consisting of a piston pump, a gear pump, and a rotary vane pump.

[0030] The turbine system can include a turboexpander.

[0031] The turbine system can generate output power of 0.5 MW to 2 MW.

[0032] The cooler can use ambient air as a coolant.

[0033] The system can further include a storage tank, which is connected between the cooler and the pump and is configured to accommodate excess working fluid.

[0034] The working fluid can be selected from the group consisting of refrigerants, hydrocarbon-based fluids, ammonia, carbon dioxide, and water.

[0035] In addition, if the working fluid is a hydrocarbon-based working fluid, the hydrocarbon-based working fluid is selected from the group consisting of propane, ethane, pentane, butane, and hydrocarbon mixtures.

[0036] Alternatively, the working fluid is propane.

[0037] The system can further include a recuperator, which has a first flow passage connected between the turbine system and the cooler and a second flow passage connected between the pump and the injection well. The recuperator is configured to transfer heat from the first flow passage to the second flow passage.

[0038] In addition, the system may include a channel well having a lateral section, wherein a multi-branch connector is located within the lateral section of the channel well.

[0039] The system may further include: wherein the injection well is a first injection well, the production well is a first production well, the multi-branch connector is a first multi-branch connector, the pressure-tested downhole loop is a first pressure-tested downhole loop, and the pump is a first pump; a second injection well extending underground into a rock formation, the second injection well having an upper end and a lower end. In addition, the system may further include a second production well extending underground into the rock formation and adjacent to the second injection well, the second production well having an upper end and a lower end. In addition, the system may include a third lateral section connected to a location of the second injection well and extending away therefrom, and a fourth lateral section connected to a location of the second production well and extending away therefrom, wherein the third lateral section and the fourth lateral section are connected together by a second multi-branch connector, and the length of each of the third lateral section and the fourth lateral section is greater than the distance between the upper end of the second injection well and the upper end of the second production well. In addition, each of the second injection well, the second production well, the third lateral section, and the fourth lateral section is sleeved with steel and cemented in place within the rock formation. The second injection well, the third lateral section, the second multi-branch connector, the fourth lateral section, and the second production well cooperate with each other to define a second pressure-tested downhole loop within the rock formation and form a heat transfer arrangement with the rock formation, the second pressure-tested downhole loop being configured to receive a working fluid that can undergo a phase change between liquid and gas within the second pressure-tested downhole loop due to heat transferred from the rock formation. The system may further include a second pump fluidly connected to the second injection well, the second pump being configured to circulate the working fluid through the second pressure-tested downhole loop. In addition, the system may include a turbine system fluidly connected to the second production well, the turbine system being configured to receive the working fluid from the first production well of the first pressure-tested downhole loop and the second production well of the second pressure-tested downhole loop. Both the first pump connected to the first injection well and the second pump connected to the second injection well may be fluidly connected to a cooler, and the second multi-branch connector of the second pressure-tested downhole loop is located at a position spaced apart from the first multi-branch connector within the lateral section of the channel well.

[0040] In addition, the first injection well includes a first inlet, the first production well includes a first outlet, the second injection well includes a second inlet, and the second production well includes a second outlet, and the second inlet and the second outlet are located close to each other on the ground surface, and the distance between the second inlet and the second outlet is 7 m to 50 m.

[0041] In addition, the first inlet and the second inlet may be located close to each other on the ground surface, and the distance between the first inlet and the second inlet is at least 20 m.

[0042] In addition, the first outlet and the second outlet can be positioned close to each other on the ground surface, and the distance between the first outlet and the second outlet is at least 20 m.

[0043] The system can also have a ground surface area of 45000 m 2 square meters.

[0044] According to various aspects of the present invention, a method for generating energy from a geothermal resource is provided. The method includes providing a pressure-tested downhole loop extending underground into a rock formation, the pressure-tested downhole loop including an injection well, a production well close to the injection well, a first lateral section connected to the injection well, a second lateral section connected to the production well, and a multi-branch connector connecting the first lateral section and the second lateral section, wherein each of the injection well, the production well, the first lateral section, and the second lateral section is sleeved with steel and cemented in place within the rock formation, and the lengths of the first lateral section and the second lateral section are greater than the distance on the ground surface between the injection well and the production well. The method includes conveying a working fluid through the pressure-tested downhole loop, the working fluid being received by the injection well in a liquid state. When conveying the working fluid through the pressure-tested downhole loop, heat is transferred from the surrounding rock formation to the liquid working fluid, and pressure is applied to the liquid working fluid. The method further includes causing a phase change of the working fluid from a liquid state to a gaseous state, the working fluid leaving the production well in a gaseous form. In addition, the method includes converting the mechanical energy generated by the flow of the gaseous working fluid into electricity. The method also includes: cooling the working fluid and causing a phase change of the working fluid to a liquid state; and returning the working fluid to the injection well.

[0045] Conveying the working fluid through the pressure-tested downhole loop can include pumping the working fluid.

[0046] Applying pressure to the liquid working fluid can include applying a pressure of 7 MPa to 31 MPa to the liquid working fluid.

[0047] The step of converting the mechanical energy generated by the flow of the gaseous working fluid into electricity can generate an output electricity of 0.5 MW to 2 MW.

[0048] The step of cooling the working fluid and causing its phase change can be cooled using a cooler.

[0049] The method can include storing the excess working fluid in a storage tank.

[0050] The working fluid can be a homogeneous working fluid.

[0051] Alternatively, the working fluid can be a heterogeneous working fluid.

[0052] The working fluid can be selected from the group consisting of refrigerants, carbon-based fluids, ammonia, carbon dioxide, and water.

[0053] If the working fluid is a hydrocarbon-based working fluid, the hydrocarbon-based working fluid may be selected from the group consisting of propane, ethane, pentane, butane, and hydrocarbon mixtures.

[0054] Alternatively, the working fluid is propane.

[0055] When the working fluid is propane, the temperature of the propane received by the injection well may be from 10°C to 40°C, and the pressure may be from 1000 kPag to 2000 kPag.

[0056] Alternatively, the temperature of the propane received by the injection well may be 20°C, and the pressure may be 1300 kPag.

[0057] When the working fluid is propane, the step of causing a phase change of the propane from liquid to gas may occur when the propane reaches conditions of a temperature of 140°C and a pressure of 6250 kPag.

[0058] In addition, the phase change of the propane from liquid to gas may occur in the second lateral section or the production well.

[0059] The temperature of the propane leaving the production well in gaseous form may be from 90°C to 110°C, and the pressure may be from 3000 kPag to 4000 kPag.

[0060] Alternatively, the temperature of the propane leaving the production well in gaseous form may be 106°C, and the pressure may be 3500 kPag.

[0061] When the working fluid is transported through a pressure-tested downhole loop, the temperature of the propane may increase by 76°C, and the pressure of the propane may increase by 2170 kPag.

[0062] After converting the mechanical energy generated by the flow of the gaseous working fluid into electricity, the temperature of the propane may be from 16°C to 63°C, and the pressure may be from 700 kPag to 1500 kPag.

[0063] Cooling the working fluid may cool the propane to a temperature of 30°C and a pressure of 1080 kPag.

[0064] The method may include using a recuperator to transfer heat from the working fluid in a first region to the working fluid in a second region, where the working fluid in the first region is between the steps of converting the mechanical energy generated by the flow of the gaseous working fluid and cooling the working fluid, and the working fluid in the second region is between the steps of transporting the working fluid through a pressure-tested downhole loop and the working fluid being received by the injection well in liquid form.

[0065] According to various aspects of the present invention, there is provided a method of constructing a pressure-tested downhole loop for a system configured to generate energy from a geothermal resource, the pressure-tested downhole loop being configured to transfer heat from surrounding rock formations to a working fluid flowing within the pressure-tested downhole loop and to cause a phase change of the working fluid from a liquid state to a gaseous state. The method includes: providing an access well extending underground into a rock formation; and drilling an injection well into the underground rock formation and spaced apart from the access well. The method further includes: drilling a first lateral section extending away from the injection well and connected to the access well; and installing a first steel casing for the injection well and the first lateral section. Additionally, the method includes: cementing the first steel casing for the injection well and the first lateral section in place within the rock formation; and drilling a production well into the underground rock formation and the production well being close to the injection well. The method further includes: drilling a second lateral section extending away from the production well towards a connection point between the first lateral section and a second lateral section, the connection point being located in the access well and adjacent to the first lateral section; and installing a second steel casing for the production well and the second lateral section. Additionally, the method includes: providing a multi-branch connector through the access well and installing the multi-branch connector at the connection point between the first lateral section and the second lateral section; pressure testing the downhole loop including the injection well, the first lateral section, the multi-branch connector, the second lateral section, and the production well, the lengths of the first lateral section and the second lateral section being greater than the distance between the injection well and the production well on the surface. The method further includes cementing the second steel casing for the production well and the second lateral section to the rock formation.

[0066] The method may further include drilling a hole for the surface casing of the injection well prior to drilling the injection well and setting the surface casing of the injection well in place.

[0067] Cementing the first casing for the injection well and the first lateral section in place within the rock formation may include drilling a bridging hole at the intersection between the first lateral section and the second lateral section, and drilling the second lateral section may include connecting the second lateral section to the bridging hole.

[0068] The method may further include installing a first isolation packer and a first cementing stage tool prior to cementing the first casing for the injection well and the first lateral section in place within the rock formation, the first isolation packer and the first cementing stage tool being installed close to the intersection between the first lateral section and the access well, the first isolation packer being installed around the outer diameter of the first casing, and the first cementing stage tool being installed within the inner diameter of the first casing and plugging the inner diameter of the first casing.

[0069] Drilling the second lateral section extending away from the production well towards the connection point may include installing a whipstock within the first lateral section close to the connection point.

[0070] The method may further include drilling a hole for the surface casing of the production well prior to drilling the production well and setting the surface casing of the production well in place.

[0071] Pressure testing the downhole loop can include subjecting the downhole loop to the pressure at the maximum depth within the downhole loop.

[0072] The method can include installing a second isolation packer and a second cementing stage tool before cementing in place the second casing for the production well and the second lateral section, with the second isolation packer and the second cementing stage tool installed near the intersection between the second lateral section and the multi-branch connector, the second isolation packer installed around the outer diameter of the second casing, and the second cementing stage tool installed within the second casing and plugging the inner diameter of the second casing.

[0073] In accordance with various aspects of the present invention, there is provided a system for generating energy from a geothermal resource. The system includes a first injection well and a second injection well extending underground into a rock formation, each of the first injection well and the second injection well having an upper end and a lower end. The system includes a first production well and a second production well extending underground into the rock formation, the first production well and the second production well being respectively proximate to the first injection well and the second injection well, each of the first production well and the second production well having an upper end and a lower end. The system further includes a first lateral section connected to a location of the first injection well and extending away therefrom, a second lateral section connected to a location of the first production well and extending away therefrom, a third lateral section connected to a location of the second injection well and extending away therefrom, and a fourth lateral section connected to a location of the second production well and extending away therefrom. The first lateral section and the second lateral section are connected together using a first multi-branch connector, and the length of each of the first lateral section and the second lateral section is greater than the distance between the upper end of the first injection well and the upper end of the first production well. The third lateral section and the fourth lateral section are connected together using a second multi-branch connector, and the length of each of the third lateral section and the fourth lateral section is greater than the distance between the upper end of the second injection well and the upper end of the second production well. Further, each of the first injection well, the second injection well, the first production well, the second production well, the first lateral section, the second lateral section, the third lateral section, and the fourth lateral section is sleeved with steel and cemented in place within the rock formation. The system further includes: the first injection well, the first lateral section, the first multi-branch connector, the second lateral section, and the first production well cooperating with each other to define a first pressure-tested downhole circuit within the rock formation, the second injection well, the third lateral section, the second multi-branch connector, the fourth lateral section, and the second production well cooperating with each other to define a second pressure-tested downhole circuit within the rock formation, the two pressure-tested downhole circuits forming a heat transfer arrangement with the rock formation, each of the first pressure-tested downhole circuit and the second pressure-tested downhole circuit being configured to receive a working fluid that is capable of undergoing a phase change between a liquid state and a gaseous state due to heat transferred from the rock formation. The system further includes a first pump fluidly connected to the first injection well, the first pump being configured to circulate the working fluid through the first pressure-tested downhole circuit, and a second pump fluidly connected to the second injection well, the second pump being configured to circulate the working fluid through the second pressure-tested downhole circuit. The system further includes a turbine system fluidly connected to the first production well and the second production well, the turbine system being operable to convert mechanical energy generated by the flow of the working fluid into electricity. Further, the system includes a cooler fluidly connected between the first pump and the second pump and the turbine system, the cooler being operable to cool the working fluid received from the turbine system and supply the cooled working fluid to the first pump and the second pump, the first pressure-tested downhole circuit and the second pressure-tested downhole circuit being positioned close to each other.

[0074] According to various aspects of the present invention, a system for generating energy from geothermal resources is provided. The system includes an injection well extending underground into a rock formation, the injection well having an upper end and a lower end. The system further includes a production well extending underground into the rock formation and adjacent to the injection well, the production well having an upper end and a lower end. The system also includes a first lateral section connected to a location on the injection well and extending away therefrom, and a second lateral section connected to a location on the production well and extending away therefrom. The first lateral section and the second lateral section are connected together using a multi-branch connector. Each of the injection well, the production well, the first lateral section, and the second lateral section is sleeved with steel and cemented in place within the rock formation. The system further includes: the injection well, the first lateral section, the multi-branch connector, the second lateral section, and the production well cooperate with each other to define a pressure-tested downhole circuit within the rock formation and form a heat transfer arrangement with the rock formation, the pressure-tested downhole circuit being configured to withstand a pressure of at least 7 MPa and receive a working fluid, the working fluid being capable of undergoing a phase change between liquid and gas within the pressure-tested downhole circuit due to heat transferred from the rock formation. The system further includes a pump fluidly connected to the injection well, the pump being configured to circulate the working fluid through the pressure-tested downhole circuit. Additionally, the system includes a turbine system fluidly connected to the production well, the turbine system being operable to convert mechanical energy generated by the flow of the working fluid into electrical power, and a cooler fluidly connected between the pump and the turbine system for cooling the working fluid. BRIEF DESCRIPTION OF THE DRAWINGS

[0075] Embodiments of the present invention can be more clearly understood by reference to the following detailed description of embodiments in conjunction with the accompanying drawings, in which:

[0076] Figure 1 is a schematic cross-sectional view showing a system for generating energy from geothermal resources according to an embodiment;

[0077] Figure 2 is Figure 1 a conceptual schematic diagram of the system for generating energy from geothermal resources shown in ;

[0078] Figure 3 is according to Figure 2 another conceptual schematic diagram of a system for generating energy from geothermal resources according to an alternative embodiment of the embodiment shown in ;

[0079] Figure 4 is a flowchart listing the steps of a method for generating energy from geothermal resources according to the embodiment shown in ; Figure 2 ;

[0080] Figure 5 is a flowchart listing the steps of an alternative method for generating energy from geothermal resources according to the embodiment shown in ; Figure 3 ;

[0081] Figure 6A is a schematic cross - sectional view showing an alternative embodiment of a system for generating energy from geothermal resources according to an embodiment, where two fully cased downhole loops are connected to a single access well;

[0082] Figure 6B is Figure 6A a conceptual schematic diagram of an embodiment of a system for generating energy from geothermal resources in , where two fully cased downhole loops are fluidly connected to a single turbine system and a single cooler, and where the working fluid is propane;

[0083] Figure 7 is a depiction of the construction Figure 1 schematic cross - sectional view of the initial steps of the system for generating energy from geothermal resources shown in , showing the drilling of the injection well, the construction well, and the first lateral connection section;

[0084] Figure 8 is a depiction of the construction Figure 1 schematic cross - sectional view of the second step of the system for generating energy from geothermal resources shown in , showing the casing installed along the injection well and passing through a portion of the first lateral connection section;

[0085] Figure 9 is a depiction of the construction Figure 1 schematic cross - sectional view of the third step of the system for generating energy from geothermal resources shown in , showing the installed isolation packers and cementing stage tools, and pouring cement between the casing and the walls of the injection well and a portion of the wall of the first lateral connection section;

[0086] Figure 10 is a depiction of the construction Figure 1 schematic cross - sectional view of the fourth step of the system for generating energy from geothermal resources shown in , showing the installation of a two - part whipstock near the isolation packer and drilling the wellbore hole of the production well;

[0087] Figure 11 is a depiction of the construction Figure 1 schematic cross - sectional view of the fifth step of the system for generating energy from geothermal resources shown in , showing the open - hole well of the production well, the second lateral connection section, and the casing window of the two - part whipstock;

[0088] Figure 12 is a depiction of the construction Figure 1 schematic cross - sectional view of the sixth step of the system for generating energy from geothermal resources shown in , showing the removal of the core of the two - part whipstock, retaining the window guide installed between the two lateral connection sections, and installing the casing along the open - hole well of the production well, the second lateral connection section, and the casing window of the two - part whipstock;

[0089] Figure 13 is a schematic cross-sectional view depicting the seventh step of the system for generating energy from a geothermal resource as shown in the configuration Figure 1 , showing the installation of a multi-branch connector between two lateral connection segments along a window guide, and connecting an injection well and a production well through the two lateral connection segments and the multi-branch connector;

[0090] Figure 14 is a schematic cross-sectional view depicting the eighth step of the system for generating energy from a geothermal resource as shown in the configuration Figure 1 , showing the installation of an isolation packer and a cementing staging tool along the open hole of the casing window of a two-piece whipstock, and pouring cement between the casing and the walls of the production well, the wall of the second lateral connection segment, and the wall of the open hole of the casing window of the two-piece whipstock;

[0091] Figure 15 is a flow chart listing the steps of the method of the system for generating energy from a geothermal resource as shown in the configuration Figure 1 . DETAILED DESCRIPTION

[0092] The following description and the embodiments described therein are provided by way of one or more examples of specific embodiments that illustrate the principles and aspects of the present invention. These examples are provided for explanation and not for limiting the principles of the present invention. In the following description, the same components are labeled with the same corresponding reference numerals throughout the specification and the drawings.

[0093] Generally speaking, a system for generating energy from a geothermal resource 100 using a single heat exchange loop (also referred to herein as a geothermal power generation system 100) is provided, wherein the system 100 includes a fully cased, pressure-tested and cemented downhole loop 108 (also referred to herein as a fully cased downhole loop 108) for isolating and circulating a single fluid 200 (also referred to as a working fluid 200) over an underground extension length to effect heat exchange between the working fluid 200 and the heat dissipated / radiated from the earth (i.e., the underground heat source). The system 100 employs a Rankine cycle (preferably an organic Rankine cycle) to convert the energy stored in the heated working fluid 200 into mechanical energy for power generation.

[0094] Those skilled in the art will recognize that in a Rankine cycle, the working fluid 200 may undergo a phase change. For clarity, in the following description, the working fluid 200 will be collectively referred to as the working fluid 200 regardless of its physical state. The working fluid 200 in the liquid state will be referred to as the liquid working fluid 204, and the working fluid 200 in the gaseous state will be referred to as the gaseous working fluid 208.

[0095] The geothermal power generation system 100 includes a fully cased downhole loop 108 underground, which has: a vertical injection well 112 extending underground; a first lower lateral section 116 connected to the vertical injection well 112 and extending away from it; a vertical production well 128 extending underground; and a second upper lateral section 124 connected to the vertical production well 128 and extending away from it. The first lateral section 116 and the second lateral section 124 meet at a junction where a multi-branch connector 120 is installed. The geothermal power generation system 100 includes a pump 104 above ground fluidly connected to the injection well 112, which is configured to cause a liquid working fluid 204 to move downward along the injection well 112 from the earth's surface 316, through the first lower lateral section 116, the multi-branch connector 120, and the second upper lateral section 124, and then move upward along the production well 128 back to the earth's surface 316. The liquid working fluid 204 undergoes a phase change underground and returns to the earth's surface 316 as a gaseous working fluid 208 through the production well 128 and flows into a turbine system 132 for power generation. Inside the turbine system 132, the gaseous working fluid 208 causes the turbine to rotate, thereby rotating a shaft and generating mechanical energy. This mechanical energy is converted into electrical power by a shaft-driven generator (not shown). A cooler 136 is also provided fluidly connected to the turbine system 132. The cooler 136 condenses the low-pressure gaseous working fluid 208 leaving the turbine system 132, returning it to its original liquid state, where the working fluid in the liquid state can be pumped downward along the injection well 112 and circulated through the fully cased downhole loop 108.

[0096] Those skilled in the art will understand, and it will be apparent from the following description, that the disclosed geothermal power generation system 100 is used to address the above challenges. More specifically, using the full casing downhole loop 108 will eliminate any risk of cross - contamination between the working fluid 200 and any rock formation 320 or formation fluid as the working fluid 200 flows through the full casing downhole loop 108, and will eliminate any risk of the working fluid 200 eroding the rock formation 320 because the working fluid 200 never contacts the rock formation 320. Due to the absence of the risk of eroding the rock formation 320 by contact, the velocity of the working fluid 200 within the full casing downhole loop 108 may also be faster. In addition to preventing the erosion of the wellbore wall, adding the casing will also eliminate the risk of wellbore instability and rock mass failure due to in - situ and induced stresses around the wellbore. In prior art systems, in order to achieve minimal cross - contamination, the velocity of the working fluid needs to be strictly managed and monitored to ensure minimal erosion of any wellbore or underground section. Ensuring minimal or no erosion is important as it not only helps to protect the environment but also avoids earthquakes or other potential consequences due to the instability of the rock formation 320. Furthermore, since the working fluid 200 is isolated from the rock formation 320, there is no risk of dissolved minerals or other substances that may change the composition of the working fluid 200. In other prior arts, when the working fluid 200 may contact the surrounding rock formation 320, there is a risk of dissolved minerals or other substances, especially when the working fluid 200 erodes the surface of the rock formation 320 and undergoes thermal changes. The dissolution of minerals may also cause the minerals to deposit in the pipes or other components of the geothermal power generation system 100 when the working fluid 200 cools, causing blockages and increasing the maintenance workload of the system 100.

[0097] The fully cased downhole loop 108 is pressure tested and cemented into the surrounding underground rock formation 320. Due to its construction, the likelihood of any working fluid 200 leaving the fully cased downhole loop 108 is greatly reduced. Therefore, the risk of any working fluid 200 leaking or leaving the fully cased downhole loop 108 and potentially causing contamination or other environmental problems is greatly reduced, especially when the working fluid 200 undergoes significant temperature and pressure changes. In contrast, other prior art systems may suffer from fluid loss because, since the working fluid is not fully isolated from the rock formation 320, fluid leaks into the formation and / or is contaminated by formation fluid inflow. This is because these systems do not have a casing, including failing to successfully pass an effective pressure test. Therefore, the fully cased downhole loop 108 can use unconventional working fluids 200 with different heat capacities and phase change points, thus allowing for potentially more efficient systems, greater power generation, and a smaller footprint for the geothermal power generation system while reducing environmental pollution problems. Additionally, parasitic power losses are minimized. Those skilled in the art should recognize that parasitic losses can be described as absorbed power, i.e., the energy required to operate pumps, cooler fans, and other loads, thereby reducing the net energy output of the system. Those skilled in the art should also recognize that net energy is the remaining power after the power generated is subtracted by the power consumed by the system operation.

[0098] The casing material for the fully cased downhole loop 108 can be steel. Different from other prior art which may use chemical linings, steel, as a hardened and inert material, can withstand high pressures in combination with the support of cement. Additionally, the risk of steel reacting chemically with the working fluid 200 is small, thus allowing the geothermal power generation system 100 to select more working fluids 200. Moreover, when ensuring no leakage within the fully cased downhole loop 108, the construction and application of the steel casing are safer compared to chemical linings.

[0099] By using a single heat exchange loop with a single working fluid 200 instead of two loops with two working fluids, parasitic energy losses can be significantly reduced because the heat is retained within the single working fluid 200 and is not lost to the environment during any heat transfer, which is not the case when there are multiple working fluids.

[0100] Furthermore, since the working fluid 200 is fully contained within the geothermal power generation system 100, the working fluid 200 can be easily replaced if environmental conditions change. For example, if the underground temperature changes, the working fluid 200 can be easily replaced with another working fluid 200 with a lower boiling point. This allows the geothermal power generation system 100 to continue operating without changing the structure (such as adjusting the depth of the lateral section to obtain the required heat).

[0101] By providing two lateral sections underground and a multi-branch connector connecting these two lateral sections, injection well 112 and production well 128 are allowed to be relatively closely adjacent to each other. Thus, compared with other prior art systems, geothermal power generation system 100 tends to occupy a smaller footprint, including both underground and above-ground surface areas. The smaller footprint can reduce capital and operating costs. For example, U.S. Patent Application Publication No. 2011 / 0048005 has a single horizontal pipeline underground. This results in a significantly larger distance between the injection wellhead and the production wellhead, and thus the occupied footprint is larger than the embodiments described below. The larger footprint may lead to low heat transfer efficiency and significant construction costs.

[0102] Reference Figure 1 and Figure 2 , which shows an embodiment of geothermal power generation system 100. The main components of geothermal power generation system 100 include a fully cased downhole loop 108, more specifically including injection well 112, first lower lateral section 116, multi-branch connector 120 (also referred to herein as cross-connect diverter 120 or multi-branch joint 120), second upper lateral section 124, and production well 128. Geothermal power generation system 100 also includes a pump 104 and a turbine system 132 that are fluidly connected to the fully cased downhole loop 108. More specifically, pump 104 is connected to injection well 112, and turbine system 132 is connected to production well 128. A cooler 136 is fluidly connected between turbine system 132 and pump 104, thus closing the line for a single heat exchange loop.

[0103] As Figure 1 shown, an additional wellbore 140 is arranged near the fully cased downhole loop 108. This wellbore 140 (also referred to herein as connecting wellbore 140, access wellbore 140, or sacrificial wellbore 140) is drilled to assist in constructing the fully cased downhole loop 108. However, it is not part of geothermal power generation system 100 and does not participate in the normal operation of geothermal power generation system 100. Wellbore 140 will be further described below regarding the construction of geothermal power generation system 100.

[0104] As can be seen from Figure 1 , the flow direction of the liquid working fluid 204 is indicated by solid arrows, and the flow direction of the gaseous working fluid 208 is indicated by dashed arrows. Details regarding the operation and phase change of the working fluid 200 will be further described below.

[0105] Although the fully cased downhole loop 108 is located in the surrounding underground rock formation 320, there are access points to the fully cased downhole loop 108 at the surface 316. More specifically, an inlet 112A is located at the upper end 180 of the injection well 112 and an outlet 128A is located at the upper end 192 of the production well 128. The inlet 112A is part of the injection well 112 and is configured as an entry point for the liquid working fluid 204 at the surface 316. The inlet 112A is surrounded by the surface casing 144. Similarly, the production well 128 includes an outlet 128A which is configured as an exit point for the gaseous working fluid 208 at the surface 316. The outlet 128A is surrounded by the surface casing 148 which is similar to the surface casing 144. In the current embodiment, except for the above-mentioned inlet 112A, outlet 128A, and surface casings 144 and 148, the remaining part of the fully cased downhole loop 108 is located underground. The surface casings 144 and 148 are provided to isolate those sections of the injection well 112 and the production well 128 near the surface 316 from the underground fresh water and to prevent the working fluid 200 from escaping into or migrating into the groundwater and / or the environment. The relevant details of the construction of the surface casings 144 and 148 will be provided below. Those skilled in the art should appreciate that the mentioned rock formation 320 is not limited to rock and may also include any underground geological formation or combination of geological formations.

[0106] In addition, in the current embodiment, the inlet 112A of the injection well 112 and the outlet 128A of the production well 128 are close to each other. Compared with the prior art systems, by bringing the injection well 112 and the production well 128 closer to each other, the geothermal power generation system 100 occupies a smaller footprint on the surface 316. In this embodiment, the distance between the inlet 112A and the outlet 128A is 50 m. However, the distance between the inlet 112A and the outlet 128A can be between 7 m and 50 m. In addition, in a preferred embodiment, the distance between the inlet 112A and the outlet 128A is less than the length of the upper lateral section 124 or the length of the lower lateral section 116. In addition, in a preferred embodiment, the footprint of the geothermal power generation system 100 on the surface is 22500 m 2 or 150 m × 150 m. However, the configurations of the inlet 112A, the injection well 112, the outlet 128A, the production well 128, the lower lateral section 116, and the upper lateral section 124 may not be limited by the positions of the inlet 112A and the outlet 128A. In other configurations, the distance between the inlet 112A and the outlet 128A may be greater. In fact, in some alternative configurations of the fully cased downhole loop 108, the lower lateral section 116 and the upper lateral section 124 may be located at the same depth. Those skilled in the art should recognize the different potential configurations of the fully cased downhole loop 108 and the different potential arrangements of the inlet 112A, the injection well 112, the outlet 128A, and the production well 128.

[0107] All pipes, wells, and sections of the full-casing downhole loop 108 are lined with cement 152 and sleeved with steel 156. More specifically, in the current embodiment, the steel pipes are cemented in the wellbores of the injection well 112 and the production well 128, in a portion of both the lower lateral section 116 and the upper lateral section 124, in a portion of the multi-branch connector 120, and in any connecting piece between the components. The entire full-casing downhole loop 108 is pressure tested to ensure no leakage. The pressure test can be defined as a hydraulic pressure test in which the continuously joined steel casing 156 is subjected to a minimum downhole pressure that is associated with the maximum pressure that the full-casing downhole loop 108 may be subjected to. The maximum pressure that the full-casing downhole loop 108 may be subjected to may be at the location of the maximum depth of the full-casing downhole loop 108 and may be along the lower lateral section 116. In certain embodiments, to determine the total downhole pressure for the pressure test, the following formula can be used:

[0108] Surface pressure + Hydrostatic pressure

[0109] where the hydrostatic pressure can be calculated by the following formula: (Maximum depth × Specific gravity of water).

[0110] For example, if the deepest point of the full-casing downhole loop 108 is in the lower lateral section 116 at a depth of 2500 m, the surface pressure is 2 MPa, and the specific gravity of water is 10 kPa / m, the total downhole pressure can be calculated by adding the surface pressure and the hydrostatic pressure. Specifically, in this example, it is 2 MPa + (2500 m × 10 kPa / m) = 27 MPa.

[0111] It should be noted that there seems to be a calculation error in the original text. The correct calculation result for the example in ID=10 should be 2 MPa+(2500m×10KPa / m) = 2MPa + 25MPa = 27MPa. The above translation has corrected this error in the translation of the calculation result.Since any leakage of water under high pressure will not cause any pollution to the surrounding environment, water is used for pressure testing. The above formula for the hydrostatic pressure of water can be used for the working fluid 200, where the specific gravity of water is greater than that of the working fluid 200. For example, the specific gravity of propane is less than that of water, so the pressure test provided by the above formula is higher than the pressure required for propane as the working fluid 200, thus ensuring the safe operation of the full casing downhole loop 108. Those skilled in the art should recognize that if the specific gravity of the working fluid 200 is higher than that of water, the above formula can be compensated by providing the specific gravity of the working fluid 200, and then water can be used to perform the corresponding pressure test on the full casing downhole loop 108. In addition, in some embodiments, for safety reasons, a safety factor can be added to the total downhole pressure calculated for the above pressure test, so as to test the full casing downhole loop 108 at a pressure higher than the operating limit. The pressure borne by the construction and pressure testing of the full casing downhole loop 108 is a pressure not seen in the prior art systems for generating energy from geothermal resources. This is because the operating pressure of the working fluid in the prior art systems is often much lower than the operating pressure of the working fluid 200 flowing through the full casing downhole loop 108.

[0112] The full casing downhole loop 108 for pressure testing is capable of receiving and transporting the working fluid 200 pressurized between 7 MPa and 31 MPa. In an embodiment where the working fluid 200 is pentane, the full casing downhole loop 108 for pressure testing can receive and transport the working fluid 200 pressurized between 7 MPa and 22 MPa. In a preferred embodiment where the working fluid 200 is propane, the full casing downhole loop 108 for pressure testing can receive and transport the propane working fluid 200 pressurized between 7 MPa and 20 MPa.

[0113] During operation, the full casing downhole loop 108 is capable of withstanding a pressure of at least 7 MPa. In other embodiments, the pressure test of the full casing downhole loop 108 can include a pressure test up to 31 MPa, and can be designed to rupture or fail at a maximum pressure of 39 Mpa.

[0114] Cement 152 is used to structurally fix the steel 156 casing to the surrounding rock formation 320. However, in alternative embodiments, cement 152 can be mixed with other substances (such as adding hematite) to adjust the thermal conductivity of cement 152. Although cement 152 and steel 156 are used in the current embodiment, those skilled in the art should think that any other materials can be used as a barrier as long as they physically isolate the working fluid 200 from the external environment / rock formation 320 and can withstand the pressure required for the working fluid 200 to expand and contract during the phase change process, and as long as heat can be conducted through the material.

[0115] The injection well 112 extends vertically underground from an inlet 112A at the ground surface 316 to a predetermined distance (or depth). This predetermined distance (or depth) can be determined on a site-by-site basis according to the geothermal gradient, rock thermal properties, geology, and geological composition of the target area. The geothermal gradient and rock thermal properties are variables that need to be considered to determine the depth and the residence time at that depth, so as to cause a phase change of the working fluid 200. The depth of the injection well is selected to achieve a high rock temperature while minimizing the drilling cost that increases with various factors including depth and the geological composition of the rock formation 320. In the current embodiment, the injection well 112 is joined to the lower lateral section 116 at its lower end 196 by a bent connector 160. However, the lower lateral section 116 can be connected to the injection well 112 at any position of the injection well 112 and extend away from the injection well 112. Based on the preferred working fluid temperature of 140 °C to be achieved, the depth of the injection well 112 is approximately between 1000 m and 4000 m, and the inner diameter of the production steel casing 156 is approximately 139 mm. However, the injection well can have different sizes (i.e., the drilling depth can be greater or smaller, and the inner diameter can also be greater or smaller) to suit specific applications. In Figure 1 the depicted embodiment, the injection well 112 is shown extending vertically downward underground. It should be understood that this does not have to be the case for every embodiment. In some embodiments, the injection well can extend downward underground at an angle relative to the vertical direction.

[0116] In the preferred embodiment, it can be seen that the lower lateral section 116 is perpendicular to the injection well 112 and extends laterally therefrom toward the XC connector 120. Additionally, the length of the lower lateral section 116 is approximately between 2000 m and 4000 m, and the inner diameter of the production steel casing 156 is approximately 139 mm. In other embodiments, the lower lateral section 116 does not necessarily have to be arranged laterally relative to the injection well 112, but extends away from the injection well 112 at an angle relative to the lateral direction. The lower lateral section can also have different sizes.

[0117] Joining the lower lateral section 116 to the upper lateral section 124 is the multi-branch connector 120. The multi-branch connector 120 can include an XC diverter or other similar connection devices that can be connected between the lower lateral section 116 and the upper lateral section 124, thereby ensuring that the full-casing downhole loop 108 can be pressure-tested and operated under pressure. For example, the SAGD XC Diverter Multi-Branch System manufactured by Baker Hughes. The multi-branch connector 120 is well-known in the oil and gas industry, and those skilled in the art should recognize the various types of multi-branch connectors 120 available. However, the use of the multi-branch connector 120 in geothermal power generation systems is novel.

[0118] In the current embodiment, the upper horizontal section 124 extends laterally away from the multi-branch connector 120 to engage the lower end 198 of the production well 128 via the bending connector 164. However, the upper horizontal section 124 can engage the production well 128 at any position of the production well 128. The upper horizontal section 124 is arranged perpendicular to the production well 128. In addition, the length of the upper horizontal section 124 is approximately between 2000 m and 4000 m, and the inner diameter of the production steel casing 156 is approximately 139 mm. In other embodiments, the upper horizontal section 124 is not necessarily arranged laterally with respect to the production well 128, but can extend at an angle with respect to the lateral direction towards the production well 128. The upper horizontal section can also have different dimensions.

[0119] In embodiments where the lower horizontal section 116 is arranged laterally with respect to the injection well 112 and the upper horizontal section 124 is arranged laterally with respect to the production well 128, the two horizontal sections 116 and 124 can be located in the same vertical plane. However, those skilled in the art should appreciate that in alternative configurations, the horizontal sections 116 and 124 can be offset from each other in this vertical plane.

[0120] In this embodiment, the production well 128 does not extend as deep underground as the injection well 112. Preferably, the depth of the production well is between 1000 m and 4000 m, and the inner diameter of the production steel casing 156 is approximately 139 mm. However, the production well can have different dimensions (i.e., the drilling depth can be greater or smaller, and the inner diameter can also be greater or smaller) to accommodate specific applications.

[0121] In the current embodiment, due to the positions of the inlet 112A and the outlet 128A, the length of the upper horizontal section 116 is shorter than the length of the lower horizontal section 116. The length of each of the lower horizontal section 116 and the upper horizontal section 124 is selected based on the amount of time (i.e., residence time) required for the working fluid 200 to remain in contact with the heat-generating rock formation 320 underground and the flow rate of the working fluid 200. For example, if the working fluid 200 requires a longer time to heat up to undergo a phase change, either due to the thermal conductivity characteristics of the surrounding rock formation 320, the well casing, and the lining of the horizontal sections 116 and 124, or due to the characteristics of the type of working fluid 200 used, both horizontal sections 116 and 124 may need to be longer to accommodate the time required for the working fluid 200 to heat up to cause a phase change. The flow rate is another variable that needs to be considered because a lower flow rate means a shorter travel distance in the same amount of time, and thus, the lengths of the horizontal sections 116 and 124 can be further adjusted.

[0122] In a preferred embodiment, the lower horizontal section 116 extends deeper than the upper horizontal section 124. The two horizontal sections 116 and 124 being at different depths can enhance the heat absorption from the surrounding rock formation 320 because the thermal interference between wells 112 and 128 may be less. However, the full-casing downhole loop 108 is not limited to this configuration. In an alternative embodiment (not shown), the horizontal section returning to the production well 128 can be located deeper than the horizontal section connected to the injection well 112. Additionally, in an alternative embodiment (not shown), the two horizontal sections 116 and 124 can be at the same depth but may be angled with respect to each other, where the multi-branch connector 120 connects the two horizontal sections 116 and 124 at different angles. Those skilled in the art will recognize the different potential configurations and lengths available for the two horizontal sections 116 and 124, as well as the different potential configurations of the full-casing downhole loop 108 as a whole.

[0123] As Figure 1 and Figure 2 shown in, the pump 104 located on the surface 316 is fluidly connected to the inlet 112A of the injection well 112. The pump 104 is operable to circulate the working fluid 200 through the full-casing downhole loop 108, entering from the inlet 112A of the injection well 112 and advancing underground.

[0124] The pump 104 is also configured to maintain the liquid working fluid 204 flowing through the entire single heat exchange loop by maintaining an appropriate flow rate of the working fluid 200. The flow rate (and the corresponding residence time) is determined by the downhole loop to conduct sufficient thermal energy to convert the working fluid from a liquid to a gas with a sufficient temperature. In the current embodiment, the pressure range of the liquid working fluid 204 received by the pump 104 can be from 500 kPag to 2000 kPag, and the temperature range can be from 10°C to 40°C. The pump 104 is configured to increase the pressure range to 700 kPag to 3000 kPag and maintain a flow rate of 15 kg / sec to 25 kg / sec. In a preferred embodiment, the pump 104 is capable of providing the liquid working fluid 204 to the inlet 112A of the injection well 112 at a pressure of approximately 1300 kPag and a temperature of approximately 30°C. A preferred embodiment of the pump 104 is to use a liquid pump to improve the thermodynamic efficiency. Compared with using a mechanical gas compressor, the liquid pump minimizes the parasitic energy loss of the system.

[0125] In other prior art geothermal systems, because the working fluid 200 contacts the rock formation 320 (due to the lack of casing), or because the working fluid 200 may pick up debris underground, the pump may need to be more robust and may need to handle abrasive materials during operation. Additionally, in prior art systems where the working fluid 200 is water, the pump may need to handle water chemistries with scaling characteristics during operation. In contrast, in the current embodiment, since the fully cased downhole loop 108 is completely lined with cement 152 and sleeved with steel 156, the working fluid 200 does not contact any rock formation 320 and is physically isolated from the environment. Accordingly, the working fluid 200 does not pick up any debris and remains a clean and uniform fluid. This allows the pump 104 to have a long service life and minimal maintenance effort, thereby saving procurement and operating costs and allowing the use of a less robust or standard pump design.

[0126] In a preferred embodiment, the pump 104 can be a positive displacement pump with a variable speed drive controller. Positive displacement pumps generally have a high overall thermal efficiency and are capable of maintaining the required discharge head when paired with a variable speed drive. Positive displacement pumps include piston pumps, gear pumps, or rotary vane pumps. However, it should be clear to those skilled in the art that the pump 104 can also be any type of pump that can handle the pressures and temperatures described above. This can include, but is not limited to, centrifugal pumps or diaphragm pumps. Those skilled in the art should recognize that different potential pumps can be used based on the above pressure, flow rate, and temperature specifications, as well as procurement and maintenance costs.

[0127] There is also a turbine system 132 on the surface fluidly connected to the upper end 192 of the production well 128. The turbine system 132 can include a turbine (not shown) whose output shaft is connected to a generator (not shown).

[0128] In the current embodiment, the turbine system 132 is positioned closely adjacent to the outlet 128A to prevent heat loss of the gaseous working fluid 208 as it travels along the insulated conduit between the outlet 128A and the turbine system 132. In other embodiments, the turbine system 132 can be positioned further away from the outlet 128A, but this is generally not preferred. Although the outer surface conduit transporting the gaseous working fluid 208 to the turbine system can be insulated, heat and pressure losses can still occur, so the travel distance and time are important considerations. Those skilled in the art are familiar with the structure, configuration, and operation of the turbine system 132 and the associated electric generator such that they need not be described herein.

[0129] During operation, the turbine system 132 receives the gaseous working fluid 208 from the outlet 128A of the production well 128, and the gaseous working fluid 208 drives the turbine connected to the shaft. The mechanical energy generated by the rotation of the turbine is transmitted to the electric generator, which can convert the mechanical energy into commercially saleable electricity. Then, the electricity can be delivered to the utility grid for further distribution. In the current embodiment, the turbine system 132 can generate electricity between 0.5 MW and 2 MW. In the preferred embodiment, the turbine system 132 can generate approximately 1 MW of electricity.

[0130] Alternatively, if the grid does not require electricity, the electricity can be delivered to a battery, other local loads, or can be consumed through a resistive load bank in a short period of time. Consuming electricity using the load bank allows the device to operate without being connected to the power transmission line in real time. This can be used for device testing and short-term operation fluctuations (not shown).

[0131] In other embodiments, the turbine system 132 can include a turboexpander, a piston expander, or a scroll expander. In the preferred embodiment, a turboexpander is used, where the turboexpander can be radial or axial. The radial turboexpander is connected to one end of the shaft, and the electric generator is connected to the other end of the shaft. The output power shaft of the expander can be directly connected to the electric generator or via a reduction gearbox. The reduction gearbox can match the high-speed (rpm) turbine impeller with the required operating speed of the electric generator. The types of the expander and the generator will determine whether a gearbox is needed and the type of the gearbox. In an alternative embodiment, the turboexpander can also be a positive displacement machine, such as a scroll, screw, and vane expander can also be used. The preferred output target of the geothermal power generation system 100 is that each expander generates more than 1 MW of electricity, which makes the high-speed and compact turboexpander the preferred embodiment because for the target power output, the positive displacement expander is larger in size and more expensive.

[0132] In another embodiment, multiple expanders can be used to maximize the generated electricity. Using multiple expanders is beneficial when trying to limit the size of the expander to achieve constructability or reduce efficiency, or allow certain working fluids 200 to expand (flash) in stages, where the first-stage flash occurs in the main expander, but there is still energy in the working fluid that can be flashed again to a lower pressure or in parallel with the first-stage flash.

[0133] In the case of including a turboexpander, the gaseous working fluid 208 can expand as it passes through a radially constrained turbine in a conical shape, thereby reducing the pressure and temperature of the gaseous working fluid 208 while driving the turbine. Similar to the previous embodiments of the turbine system 132, the rotation of the radial turbine generates mechanical energy and transfers it to an electric generator, which converts the mechanical energy into commercially saleable electricity. The voltage of the electric generator can be increased using a step-up transformer to match the requirements of a third-party power transmission line for selling electricity to the desired market.

[0134] The low-pressure gaseous working fluid 208 is output from the turbine system 132. In an alternative embodiment, depending on the characteristics of the working fluid 200 used, the turbine system 132 can partially change the state of the received input gaseous working fluid 208 into a mixture of gas and liquid.

[0135] The cooler 136 (also referred to as the condenser 136) is arranged between and fluidly connected to the turbine system 132 and the pump 104. The cooler 136 is configured to receive the low-pressure gaseous working fluid 208 output from the turbine system 132 and is configured to cool and condense the low-pressure gaseous working fluid 208 into a liquid working fluid 204 by using a heat exchanger (cooled by forced ventilation) or by a mechanical cooler (not shown). In an embodiment where the working fluid 200 leaving the turbine system 132 and received by the cooler 136 is in a mixed state of both gas and liquid, the energy used by the cooler 136 can be reduced because the amount of work required to cool the working fluid 200 to a liquid state can be reduced. Alternatively, the residence time of the working fluid 200 within the cooler 136 can also be reduced. Those skilled in the art should recognize that the specifications of the cooler 136 used may depend on the specifications of the working fluid 200, the type of the turbine system 132, and the final target temperature and pressure after the liquid working fluid 204 leaves the cooler 136.

[0136] When the cooler 136 is fluidly connected to the pump 104, the resulting liquid working fluid 204 output from the cooler 136 returns to the pump 104 and passes through the full-borehole downhole loop 108 again. Preferably, the cooler 136 is of the finned-tube type and uses ambient air with forced ventilation as the coolant. This type of condenser cooler 136 is effective and relatively inexpensive. However, other embodiments can also be used, such as brazed aluminum plate type, tube type, or other heat exchangers that cool the working fluid by isolating the coolant.

[0137] Connectors 168, 172, and 176 serve as additional components for completing the portion of a single heat exchange loop above the ground surface 316. Specifically, connector 168 serves as a connector for fluidly connecting the outlet 128A of production well 128 to the inlet of turbine system 132. Similarly, connector 172 fluidly connects the outlet of turbine system 132 to the inlet of cooler 136. Additionally, connector 176 serves as a connector for fluidly connecting the outlet of cooler 136 to the inlet of pump 104.

[0138] As described above, the full-casing downhole loop 108 is fully lined and cased to physically isolate the working fluid 200 from the rock formation 320 and the environment. In the current embodiment, connectors 168, 172, and 176 may be steel pipes. However, in alternative embodiments, connectors 168, 172, and 176 may be constructed of other materials that do not leak and can withstand the pressure and temperature variations on the ground surface. In a preferred embodiment, connector 168 between outlet 128A and turbine system 132 may also be insulated to prevent heat loss of the gaseous working fluid 208 before it reaches turbine system 132. However, in alternative embodiments, all surface connectors 168, 172, and 176 may also be insulated to reduce heat loss and thus reduce parasitic losses. Additionally, the single heat exchange loop of the geothermal power generation system 100 may include connectors 168, 172, and 176, which will be pressure tested to ensure that these connectors do not leak when the working fluid 200 undergoes pressure variations during the transportation of the working fluid 200. Those skilled in the art will appreciate that connectors 168, 172, and 176 may have any shape or size, depending on the positions and specifications of the working fluid 200, outlet 128A, turbine system 132, cooler 136, pump 104, and inlet 112A. Those skilled in the art will also appreciate that in embodiments where multiple components are combined into a single unit (such as cooler 136 and pump 104), certain connectors may not be required and may be omitted.

[0139] As Figure 2As shown, the geothermal power generation system 100 may further include a storage container 188 (also referred to herein as storage tank 188) for storing excess liquid working fluid 204 and providing a sufficient and stable mass flow to pump 104. Although not shown, other components (such as valves, heat exchangers, and other instruments) may be used to optimize the geothermal power generation system 100. In an alternative embodiment, a filter or filter separator may also be added at outlet 128A upstream of the turbine system 132. However, in the current embodiment, if all pipes are clean enough before the turbine system 132 is put into operation, removing manufacturing lubricants, scale, dirt, and other contaminants, the filter is not necessary because the single working fluid 200 in the single heat exchange loop is not expected to generate debris or foreign particles during normal operation.

[0140] Figure 3 depicts a geothermal power generation system 100A, which is Figure 1 and Figure 2 an alternative embodiment of the geothermal power generation system shown in Figure 2 and Figure 3The same components or structures shown are identified by the same reference numerals. System 100A is similar to system 100 in all substantial respects, except that the geothermal power generation system 100A is provided with a recuperator 184 (also referred to herein as heat exchanger 184). The recuperator 184 is arranged between and connected to the turbine system 132 and the cooler 136, and is also arranged between and connected to the pump 104 and the injection well 112. The recuperator 184 is configured to minimize the cooling load of the cooler 136 by exchanging heat between the warm low-pressure gaseous working fluid 208 discharged from the turbine system 132 and the cold liquid working fluid 204 from the outlet of the pump 104, and to preheat the liquid working fluid 204 before it enters the injection well 112. When the warm low-pressure gaseous working fluid 208 discharged from the turbine system 132 travels through the recuperator 184, it can transfer heat to the cold liquid working fluid 204 flowing from the outlet of the pump 104 through the recuperator 184 to the injection well 112. By supplying the heat of the low-pressure gaseous working fluid 208 discharged from the turbine system 132 to the cold liquid working fluid 204 flowing to the injection well 112, thermal energy can be saved and reused. Since the low-pressure gaseous working fluid 208 flows to the cooler 136 after leaving the turbine system 132 to condense and cause a phase change, transferring thermal energy from the low-pressure gaseous working fluid 208 reduces the time and energy required for the cooler 136 to condense the gaseous working fluid 208 into a liquid before entering the cooler 136. In addition, the liquid working fluid 204 flowing to the injection well 112 is heated on its way into the ground, so preheating the liquid working fluid 204 in advance can reduce the required underground residence time, which can allow the lateral sections 116 and 124 to be shorter, or allow the lateral sections 116 and 124 to be located at shallower depths. Those skilled in the art should recognize the potential of the recuperator 184 and the potential configurations of the geothermal power generation system having the recuperator 184.

[0141] In an alternative embodiment, the geothermal power generation system 100 can be used for other purposes in addition to power generation. For example, the work generated by the geothermal power generation system 100 can be used to perform other mechanical work. Alternatively, the work generated by the geothermal power generation system 100 can be used to generate hydrogen.

[0142] Reference Figure 4, which shows a flowchart listing the steps of a method 400 for operating a geothermal power generation system 100 according to an embodiment of the present invention. The operation of the geothermal power generation system 100 occurs after the system is started and initialized and follows a Rankine cycle (preferably an organic Rankine cycle using an organic carbon-based working fluid). An example of starting the geothermal power generation system 100 includes slowly circulating the working fluid 200 through the injection well 112 and allowing any residual liquid or gas (from the construction process or from a previous operation of the geothermal power generation system 100) to be discharged and collected in a storage container. After all the residual liquid or gas is removed, the working fluid 200 can continue to circulate through the geothermal power generation system 100 as part of its normal operation. It can be seen that the method 400 is a cycle. For ease of understanding, the process can be described as starting at step 405 and ending at step 440, and then starting again at step 405.

[0143] As described above, the geothermal power generation system 100 is a single heat exchange loop having a fully cased downhole loop 108. Since the fully cased downhole loop 108 is fully cased and pressure tested, the working fluid 200 can be various liquids, gases, or plasmas. In alternative embodiments, the working fluid 200 can be a commercially available and environmentally friendly carbon-based refrigerant or refrigerant mixture, such as a mixture of 90% propane and 10% mole fraction ethane. Alternatively, the working fluid 200 can be a composition (heterogeneous working fluid 200) or a single substance (homogeneous working fluid 200) of hydrocarbons, carbon dioxide, or ammonia. In a preferred embodiment where the geothermal power generation system 100 employs an organic Rankine cycle, the working fluid 200 can be propane. In the case of using propane, when the depth is 2000 m and the temperature of the rock formation 320 is approximately 160 °C, the maximum temperature achieved by the propane working fluid 200 is approximately 140 °C. In addition, the propane working fluid 200 can be condensed into a liquid working fluid 208 by forcing ambient air to flow through a finned tube cooler 136 in a hot summer without the need for significant cooling. Although propane is the selected working fluid 200, other organic (carbon-based) substances, such as hydrocarbons or hydrocarbon mixtures, can also be used. Hydrocarbon mixtures can be used to maximize the return pressure of the working fluid 200. Hydrocarbon mixtures allow the working fluid 200 to be adjusted according to specific depth and temperature conditions. For example, adding ethane to a mainly propane working fluid 200 allows for earlier wellbore flashing at a specific rock formation 320 temperature. Early flashing will allow an increase in the flow rate of the working fluid 200, thereby increasing power generation. Another example is mixing hydrocarbons with butane to increase the heat capacity of the working fluid. By mixing heavier hydrocarbons, the flash point / vaporization point of the fully cased downhole loop 108 can be adjusted according to the temperature of the surrounding rock formation 320. For example, the vaporization point can be adjusted based on the temperature of the surrounding rock formation 320 to be located in the upper lateral section 124 or the production well 128 to maximize the velocity of the working fluid 200 and minimize the friction of the working fluid 200 with the remainder of the pipeline before it is discharged from the fully cased downhole loop 108. Those skilled in the art should recognize the potential combinations of different variations of the rock formation 320 temperature and hydrocarbon mixtures to adjust the location of the vaporization point of the fully cased downhole loop 108. Although the working fluid 200 can also be water, the above fluids are preferably used because the boiling points of these substances are lower than that of water, and the required underground residence time is shorter. In addition, the above fluids may have favorable heat capacities and different phase change points, thereby allowing for a more efficient system and reducing the residence time in the fully cased downhole loop 108 underground.

[0144] The following steps depict an embodiment in which the working fluid 200 is propane. In step 405, the propane liquid working fluid 204 is delivered underground by flowing downward along the injection well 112 and then along the lower lateral section 116, the multi-branch connector 120, and the upper lateral section 124. To reach the injection well 112, the liquid working fluid 204 is pumped using the pump 104. In fact, the working fluid 200 is circulated through a single heat exchange loop with a full casing using the pump 104. To ensure normal circulation, the pump 104 will increase the pressure of the liquid working fluid 204 from 1080 kPag to 1300 kPag to be received by the inlet 112A of the injection well 112. In the current embodiment, the working fluid 200 is propane. After leaving the pump 104 and before being received by the inlet 112A, the approximate temperature range of the liquid working fluid 204 can be between approximately 10 °C and approximately 40 °C, preferably, the temperature is approximately 20 °C, and the approximate pressure range is from approximately 1000 kPag to approximately 2000 kPag, preferably, the pressure is approximately 1300 kPag. Once the liquid working fluid 204 is received by the inlet 112A, it will flow downward along the vertical injection well 112.

[0145] When the liquid working fluid 204 reaches the bend connector 160, the flow direction of the liquid working fluid 204 changes from the vertical direction to the lateral direction and then continues to flow along the lower lateral section 116. Then, the liquid working fluid 204 reaches the multi-branch connector 120, changes direction and flows into the upper lateral section 124, and then continues to flow until it reaches the bend connector 164 adjacent to the lower end 198 of the production well 128.

[0146] At the lower end 196 of the injection well 112 and at the depth where the lower lateral section 116 is located, heat is naturally conducted from the surrounding environment and rock formation 320 from the surrounding rock formation 320. As the liquid working fluid 204 flows downward along the injection well 112, when the liquid working fluid 204 reaches a certain depth where the temperature of the rock formation 320 exceeds the temperature of the liquid working fluid 204, heat is transferred from the surrounding environment or the rock formation 320 to the liquid working fluid 204 (step 405). Heat transfer can occur while the liquid working fluid 204 is still flowing downward through the injection well 112 and will continue to occur as the liquid working fluid 204 flows through the connector 160 and the lower lateral section 116. This heat can be conductively transferred from the surrounding environment to the liquid working fluid 204 through the cement sheath 152 and the steel casing 156. The depth threshold at which the liquid working fluid 204 begins to receive heat and thus increase the temperature of the liquid working fluid 204 is the case where the surrounding environment temperature is greater than the temperature of the liquid working fluid 204. This depth threshold depends on the geothermal gradient of the location and the reinjection temperature of the working fluid. As the liquid working fluid 204 flows through the multi-branch connector 120 and the upper lateral section 124, heat will continue to be transferred to the liquid working fluid 204, thereby raising the temperature as the liquid working fluid 204 flows through the components.

[0147] In addition, as the liquid working fluid 204 flows downward in the injection well 112, due to the action of the hydrostatic head, the pressure exerted on the liquid working fluid 204 will increase (step 415). When the liquid working fluid 204 reaches the connector 160 and the lower lateral section 116, as the fluid absorbs thermal energy, the pressure of the liquid working fluid 204 will continue to increase. Although the frictional loss of the flow rate in the wellbore may cause a slight decrease in pressure, the pressure of the liquid working fluid 204 will still increase net. In the case where the depth is approximately 2000 m as provided by the current embodiment, the approximate pressure of the liquid working fluid 204 when it reaches the lower end 196 / connector 160 of the injection well 112 is approximately 10000 kPag. Although the increase in pressure is caused by the change in depth, the heat transfer rate and the temperature increase rate of the liquid working fluid 204 depend on the depth, rock thermal conductivity, residence time, and the temperature of the rock formation 320. Therefore, as the liquid working fluid 204 flows downward in the injection well 112 and flows laterally in the lower lateral section 116, the temperature will continue to increase. Step 415 depicts transferring heat and increasing the applied pressure.

[0148] In step 420, as the liquid working fluid 204 flows through the lower horizontal section 116, the connector 160, the multi-branch connector 120, the connector 164, and the upper horizontal section 124, the liquid working fluid 204 reaches its boiling point due to heat absorption and pressure increase (step 415), and the liquid working fluid 204 will undergo a phase change at some point, changing from a liquid state to a gaseous state. More specifically, the rate of temperature increase continues until the liquid working fluid 204 begins to vaporize, at which point the temperature will remain constant until all of the liquid working fluid 204 has been converted to a gaseous state (gaseous working fluid 208), and then the temperature will increase again to superheat the vapor or gaseous working fluid 208. Those skilled in the art will appreciate that the temperature and pressure required for the liquid working fluid 204 to vaporize will vary according to the specifications of the working fluid 200. In the current embodiment where the working fluid 200 is propane, it vaporizes at a temperature of approximately 140 °C and a pressure of approximately 6250 kPag. In a preferred embodiment, the phase change will occur within the upper horizontal section 124 or the production well 128 to minimize the amount of friction between the working fluid 200 and the remainder of the casing before the working fluid 200 exits the fully cased downhole loop 108, thereby maximizing the velocity of the working fluid 200. However, those skilled in the art will appreciate that the phase change of the working fluid 200 can occur at any location within the fully cased downhole loop 108. Those skilled in the art will appreciate that the location of the flow path of the working liquid within the fully cased downhole loop 108 will vary according to the configuration of the fully cased downhole loop 108, the length and depth of the internal components of the fully cased downhole loop 108, the flow rate of the working liquid 200, the flow rate of the working fluid 200, the boiling point of the working fluid 200, the temperature of the rock formation 320, and the rate of heat conduction from the rock through the steel casing 156 and the cement 152 to the working fluid 200.

[0149] In step 425, the gaseous working fluid 208 rises through the production well 128 to the surface 316 and exits the fully cased downhole loop 108 at the outlet 128A. As the gaseous working fluid 208 rises to the surface 316, there will be a slight loss of pressure and temperature due to the change in depth. However, the temperature of the working fluid 200 will be high enough to maintain the gaseous state of the working fluid 208. The approximate temperature of the gaseous working fluid 208 at the outlet 128A is between approximately 90 °C and approximately 110 °C, preferably approximately 106 °C, and the approximate pressure is between approximately 3000 kPag and approximately 4000 kPag, preferably 3500 kPag. Then, the gaseous working fluid 208 is conveyed along the connector 168 towards the turbine system 132.

[0150] Thus, in the present embodiment, the temperature of the liquid working fluid 204 at the inlet 112A is approximately 30 °C and the pressure is approximately 1080 kPag, while the temperature of the gaseous working fluid 208 at the outlet 128A is approximately 106 °C and the pressure is approximately 3500 kPag. The passage of the working fluid 200 through the concentric annulus downhole loop 108 increases its temperature by approximately 76 °C and its pressure by approximately 2170 kPag. Additionally, in the present embodiment, the residence time of the working fluid 200 between entering the inlet 112A and leaving the outlet 128A is approximately 30 minutes. Those skilled in the art will recognize that the temperature difference and residence time are affected by a variety of factors, including but not limited to the configuration, depth, and length of the components of the concentric annulus downhole loop 108, as well as the formation 320 temperature, rock thermal conductivity, the rate of heat transfer from the rock through the casing 156 and cement 152 to the working fluid 200, and the flow rate of the working fluid 200.

[0151] In the present embodiment where the working fluid 200 is propane, the temperature range of propane can vary from the approximate temperature of the surrounding / environment (ambient temperature) when it enters the concentric annulus downhole loop 108 at the inlet 112A to 185 °C when it leaves the concentric annulus downhole loop 108 at the outlet 128A. The ambient temperature can vary depending on the environment in which the geothermal power generation system 100 is located and can range between -43 °C and 45 °C.

[0152] In the current embodiment, the turbine system 132 is a turboexpander. In step 430, the turbine system 132 receives the gaseous working fluid 208, and the gaseous working fluid 208 will drive the turbine (also referred to herein as the turbine impeller) to generate mechanical energy. Since the turbine impeller is connected to a shaft, and the shaft is in turn connected to a generator, the mechanical energy is transferred to the generator, and in step 435, the generator then converts the mechanical energy into electrical energy. In this embodiment, the gaseous working fluid 208 expands by virtue of the shape of the expander / valve, and the pressure and temperature of the gaseous working fluid 208 also decrease when causing the turbine connector connected to the shaft to rotate radially. The approximate pressure and temperature of the propane gaseous working fluid 208 leaving the turbine system 132 are in the range of approximately 1500 kPag and approximately 63 °C and approximately 700 kPag and approximately 16 °C. In a preferred embodiment, the approximate pressure and temperature of the gaseous working fluid 208 can easily condense the gaseous working fluid 208 into a liquid working fluid 204 at the ambient air temperature by means of the cooler 136. In step 435, the electrical energy generated by the generator is approximately 1 MW, and may fluctuate depending on the condensation pressure of the cooler under ambient conditions. Therefore, a reduction in the load required for the cooler 136 to condense the gaseous working fluid 208 will increase the net electrical energy generated by the generator. Those skilled in the art should recognize that any reduction in parasitic load (such as the energy required to cool the gaseous working fluid 200) will increase the electrical energy generated and improve the efficiency of the geothermal power generation system 100. Those skilled in the art should conceive that in some embodiments, depending on the efficiency of the turbine system 132 and the specifications of the working fluid 200, the working fluid 200 leaving the turbine system 132 can be in a mixed state of both gaseous and liquid states.

[0153] In step 440, the gaseous working fluid 208 leaving the turbine system 132 can travel along the connection member 172 and be received by the cooler 136. The cooler 136 can condense the gaseous working fluid 208 into a liquid. The temperature and pressure of the propane liquid working fluid 204 at the outlet of the cooler 136 can be 30 °C and 1080 kPag, but may fluctuate depending on the ambient air temperature and pressure.

[0154] After leaving the cooler 136, the liquid working fluid 204 can return to the pump 104 through the connection member 176, where the liquid working fluid 204 is recycled again, as can be seen in step 405.

[0155] Reference Figure 5 , a flowchart is shown listing the steps of a method 400A for operating a geothermal power generation system 100A according to an embodiment of the present invention. For convenience, in Figure 4 and Figure 5The same reference numerals are used to depict the same steps. Method 400A is similar to method 400 in all material respects, except that it includes additional steps 437 and 432 related to the regenerator 184.

[0156] Steps 405, 415, 420, 425, 430, and 435 are performed as described in the context of method 400 as shown in Figure 4 Steps 437 occurs after step 435, where the gaseous working fluid 208 transfers heat to the parallel pipes containing the liquid working fluid 204 (the heat is received by the liquid working fluid 204, as detailed in step 442 below). By transferring heat through the regenerator 184, the temperature of the gaseous working fluid 208 decreases, so the energy required for the condenser 136 to condense the gaseous working fluid 208 in the subsequent step 440 can be reduced. The temperature of the gaseous working fluid 208 decreases by approximately 15 °C after leaving the regenerator 184 and before being received by the condenser 136.

[0157] Thereafter, step 440 is performed as described in the context of method 400 as shown in Figure 4 to condense the gaseous working fluid into a liquid working fluid. After step 440, i.e., in step 442, the liquid working fluid 204 enters the regenerator 184 and receives heat therefrom. More specifically, the regenerator 184 interacts with the working fluid 200 at two locations in a single heat exchange loop, specifically as the gaseous working fluid 208 after the turbine system 132 and as the liquid working fluid 204 after the pump 104. These two pipes carrying the working fluid 200 are in close proximity in the regenerator 184, allowing heat to be transferred from the gaseous working fluid 208 to the liquid working fluid 204. Thus, in step 442, the liquid working fluid 204 receives heat from the gaseous working fluid 208 (the heat transferred from the gaseous working fluid 208 in step 437), thereby increasing the temperature of the liquid working fluid 204 before continuing forward to the inlet 112A. In this embodiment, the temperature of the liquid working fluid 204 can increase by up to 10 °C after leaving the regenerator 184 and before reaching the inlet 112A.

[0158] Those skilled in the art will appreciate that the approximate temperature ranges and approximate pressure ranges provided above may vary depending on the configuration of the geothermal power generation system 100 or 100A, and may also vary depending on the specifications of the working fluid 200 used and the ambient air temperature. Those skilled in the art will also recognize that although the above embodiments provide approximate temperature ranges and pressure ranges, where the preferred working fluid 200 is a commercially available and environmentally friendly carbon-based refrigerant, the geothermal power generation system 100 will still continue to operate even if the preferred working fluid 200 exceeds the approximate temperature ranges and pressure ranges.

[0159] Reference Figure 6A Figure 6A , which shows an embodiment of the geothermal power generation system 100-1, including two full-casing downhole loops 108A and 108-2, both of which are connected to a single connecting wellbore 140. As will be further described below, since only a single connecting wellbore 140 needs to be drilled, the construction is facilitated. In addition, using a single connecting wellbore 140 further minimizes the footprint of the geothermal power generation system. Those skilled in the art should recognize that the geothermal power generation system 100-1 is not limited to two full-casing downhole loops, but may include any number of full-casing downhole loops.

[0160] Reference Figure 6B Figure 6B , the components of the two full-casing downhole loops 108-1 and 108-2 can be seen. The components of the two full-casing downhole loops 108-1 and 108-2 are similar to those of the full-casing downhole loop 108 mentioned previously in Figure 1 , Figure 2 and Figure 3 . Therefore, the components within each of the two full-casing downhole loops 108-1 and 108-2 are numbered similarly to those of the full-casing downhole loop 108, with a -1 or -2 suffix added to indicate the first full-casing downhole loop 108-1 or the second full-casing downhole loop 108-2. Considering that these components are similar, they will not be further described.

[0161] In the embodiment 100-1, the two full-casing downhole loops 108-1 and 108-2 operate in the same manner as the embodiment of the full-casing downhole loop 108 mentioned previously. However, after the respective outlets 128A-1 and 128A-2 of the production wells 128-1 and 128-2, the two streams of the gaseous working fluid 208 can be combined into a single stream to be received by a single turbine system 132. Therefore, the merging connector 168-1 can be configured to allow the merging of the two streams of the gaseous working fluid 208. In addition, a single cooler 136 can receive the gaseous working fluid 208 leaving the turbine system 132 to condense the gaseous working fluid 208 into a liquid working fluid 204. Then, the liquid working fluid 204 can be divided into two streams using the splitting connector 176-1 to be received by the pump 104-1 and the pump 104-2, where the pump 104-1 can increase the pressure of the liquid working fluid 204 to be injected into the injection well 112-1, and the pump 104-2 can increase the pressure of the liquid working fluid 204 to be injected into the injection well 112-2.

[0162] When implementing Embodiment 100-1, since the turbine system 132 and the cooler 136 can share the full-casing downhole loops 108-1 and 108-2, the number of required components or equipment can be minimized. This further minimizes costs. In addition, since there is only a single turbine system 132 and cooler 136 on the ground, rather than a turbine system 132 and a cooler 136 for each of the full-casing downhole loops 108-1 and 108-2, the footprint and the surface area on the ground are minimized. In addition, the design of Embodiment 100-1 has inherent advantages in terms of scalability and economies of scale, which will be further discussed below.

[0163] Those skilled in the art should recognize the modular nature of the turbine system 132, the cooler 136, and the pump 104. Specifically, those skilled in the art should recognize that any number of full-casing downhole loops 108 can be connected to a single turbine system 132, a single cooler 136, and a single pump 104. Alternatively, any number of full-casing downhole loops can be connected to multiple turbine systems 132, a single cooler 136, and a single pump 104. Similarly, any number of full-casing downhole loops can be connected to a single turbine system 132, multiple coolers 136, and a single pump 104. Or as can be seen from Embodiment 100-1, multiple pumps 104 can be used. Therefore, those skilled in the art should recognize the different combinations and variations of the full-casing downhole loops 108, the turbine system 132, the cooler 136, and the pump 104.

[0164] In commercial operations, when multiple well loops produce and sell electricity to the power transmission line through a sales meter, power generation needs to be controlled. For example, when 25 MW of electricity needs to be delivered to the power grid, twenty-five (25) full-casing downhole loops 108 can be used. An on / off power control scheme is adopted to output the optimal amount of electricity to the power grid on an hourly basis. The system can electronically monitor the grid capacity and power demand and then provide feedback to the facility process logic controller (PLC). In an embodiment where a single turbine system 132 is connected to twenty-five (25) full-casing downhole loops 108, the PLC will then automatically shut down the pump 104 and other rotating equipment and close the electronically actuated wellhead valve to quickly "shut down" individual geothermal well loops. This on / off control system allows the facility to change the power output between 0 MW and 25 MW in 1-MW increments. Alternatively, in an embodiment where twenty-five (25) turbine systems 132 are connected to twenty-five (25) full-casing downhole loops 108, the PLC can then shut down the pump 104 of each full-casing downhole loop 108 and shut down the turbine system 132, thus allowing the facility to provide a power output between 0 MW and 25 MW in 1-MW increments.

[0165] This control scheme can also be used according to a predetermined schedule. The advantage of the on / off control system is that it is relatively simple to design and operate, and provides good control of the power output. This control scheme can be used because in the single closed-loop system shown in Figure 6B the working fluid only interacts with the underground reservoir by conduction. No reservoir fluid enters the geothermal circuit, and no well working fluid 200 enters the reservoir. All well heating is by conduction. Therefore, power generation can be quickly changed by isolating the flow rate of the working fluid 200 in the injection well 112, thus stopping the power generation of the well. In addition, when the well is closed, it allows the underground rock to be "recharged" by conduction heating, and when the well is reopened, the fully cased downhole circuit 108 will be able to increase power production (compared to steady-state operation). Those skilled in the art should recognize that the above control scheme can control any number of fully cased downhole circuits 108 and turbine systems 132.

[0166] Reference Figure 15 shows a flowchart listing the steps of a method 1500 for constructing a fully cased downhole circuit 108 of a geothermal power generation system 100 according to an embodiment of the present invention. Constructing the fully cased downhole circuit 108 uses a drilling rig to drill and connect two wellbores (injection well 112 and production well 128), and a third wellbore (connection wellbore 140) can be drilled and extended to provide a connection point between the injection well 112 and the production well 128.

[0167] Step 1505 includes drilling the connection wellbore 140, the injection well 112, and a lower lateral section 116 extending between the connection wellbore 140 and the injection well 112.

[0168] Two drilling rigs can be moved to different surface locations and fixed. Referring to Figure 7 these locations are locations 304 and 308. The predetermined distance between locations 304 and 308 is at least the length of the lateral sections 116 and 124 (as depicted in Figure 1 ), and is at any offset distance required for the construction angle in the well trajectory. Those skilled in the art should be clear that in this case, the positioning of the two drilling rigs is based on the embodiment of the fully cased downhole circuit 108, where the injection well 112, the production well 128, the lateral sections 116 and 124, and the multi-branch connector 120 are in the same vertical plane, and the positioning of the two drilling rigs can be adjusted based on the component positions and configurations of the fully cased downhole circuit 108. In addition, although two drilling rigs are used in the current embodiment, those skilled in the art should envision that an additional third drilling rig can be used if the order of events is changed.

[0169] The first drilling rig located at position 304 above the planned connection wellbore 140 will drill a hole with a diameter of 440 mm (17 1 / 4 ”) and a hole with a depth of 650 m. The drilling mud / drilling fluid used can be an environmentally friendly fresh water gel system. Examples of drilling mud include, but are not limited to, bentonite as a gel, and additives such as barium sulfate (barite), calcium carbonate (limestone), or hematite. Those skilled in the art should recognize the different drilling muds that can be used in combination with the rig. The surface casing 212 will be set in place, with a diameter of 340 mm (13 3 / 8”), extending to a depth of 650 m. The entire length and circumference of the surface casing 212 will be cemented to the surface 316. The importance of the surface casing 212 is to ensure that the planned connection wellbore 140 is fixed in place, prevent shallow formations from collapsing into the wellbore, and provide a base for the 5-stage blowout preventer described below.

[0170] The second rig located at position 308 at the planned injection well 112 will drill a hole with a diameter of 311 mm (12 1 / 4 ”) and a depth of 650 m. Similar to the drilling of the first rig located at position 304, the drilling mud of the second rig can be an environmentally friendly fresh water gel system. The surface casing 144 will be set in place, with a diameter of 244 mm (9 5 / 8”), extending to a depth of 650 m. The entire length and circumference of the surface casing 144 will be cemented to the surface 316. Similar to the surface casing 212, the purpose of the surface casing 144 is to ensure that the planned injection well 112 is fixed in place, prevent shallow formations from collapsing into the wellbore, and provide a base for the 5-stage blowout preventer described below. In addition, the surface casing 144 is used to ensure that any working fluid 200 does not leak into the surrounding environment.

[0171] The cement casing for the surface casings 144 and 212 will preferably use a hot mix cement with a total calculated hole volume plus a 50% surplus, with a density of 1860 kg / m 3 (the total mass of cement is approximately 80 t). Then, the cement casing can undergo a first pre-flush with 2.5 m 3 of fresh water. Then, the cement casing can undergo a second pre-flush with 5 m 3 of thickened water (weighted to 1200 kg / m3). An example of thickened water includes Optiflush TM . Those skilled in the art should recognize other forms or variants of thickened water. Then, a cement plug can be placed and displaced with fresh water.

[0172] A 5-stage blowout preventer (not shown) may be installed on or near surface casings 144 and 212. The 5-stage blowout preventer is used to seal, control, and monitor injection well 112 and connecting wellbore 140 to prevent blowouts. In the current embodiment, the low-pressure test for the 5-stage blowout preventer is 1400 kPa and the high-pressure test is 35000 kPA, with each pressure test lasting at least ten (10) minutes. The 5-stage blowout preventer may also be pressure tested according to formation pressure and any relevant regulatory requirements.

[0173] The drilling of injection well 112 and connecting wellbore 140 will be directionally controlled using a directionally controlled drilling assembly and maintained at target accuracy through measurement-while-drilling (“MWD”) surveys. Specifically, a first drill rig located at position 304 will drill an intermediate wellbore (not shown) with a diameter of 311 mm (12 1 / 4 ”) through the surface casing to a predetermined depth. Initially, connecting wellbore 140 will be drilled vertically and then directionally drilled to achieve a 90-degree inclination at entry formation point 228 near the lower end 216 of connecting wellbore 140. Entry formation point 228 will be located in the geothermal target formation, which is at a depth with a target temperature. In the current embodiment, connecting wellbore 140 is drilled using an oil-based mud system to minimize washout and protect wellbore integrity. However, the drilling mud system used may depend on the region and historical drilling problems in that region. Those skilled in the art will recognize different potential drilling mud systems that can be used.

[0174] An intermediate thermal casing 236 with a diameter of 244 mm (9 5 / 8”) will extend along the total depth of connecting wellbore 140, and intermediate thermal casing 236 may be cemented to the surface of surrounding rock formation 320. Then, intermediate thermal casing 236 may undergo a first pre-flush with 5 m 3 of thickened water, where the thickened water is weighted to provide a greater wellbore pressure / hydrostatic pressure than the formation pressure, thus maintaining wellbore overbalance. Then, intermediate thermal casing 236 may undergo a second pre-flush with 5 m 3 of a cleaning agent (weighted to 1450 kg / m3 or higher), thus maintaining wellbore overbalance. The overbalanced wellbore will prevent gases or fluids in the formation from entering the wellbore and rising to the surface. Then, a thermal setting cement (approximately 75 t) equal to the total calculated pore volume plus a 20% surplus is filled / provided into intermediate thermal casing 236. Then, a tail cement is set with 20% of airtight cement (approximately 45 t). Then, the inner diameter of the cement is displaced with fresh water to form a hollow wellbore, thus cementing the outer diameter to rock formation 320.

[0175] The volume and mixture ratio of the cement may be adjusted according to historical well data, formation pressure, and regional regulatory isolation requirements for certain formations to prevent cross-flow contamination.

[0176] The intermediate thermal casing 236 can be fixed at the wellhead / inlet 232 using the velocity head or an additional wellhead section to set the slips. The slips (also referred to as anchors herein) can be set in a fully tensioned state together with the intermediate thermal casing 236 to hold the intermediate thermal casing 236 inside the surface casing 212. In some embodiments, it may be necessary to remove the 5-stage blowout preventer on the surface casing 212 for installing the slips. After reassembly, the 5-stage blowout preventer may be pressure tested again at the same pressure and specifications to confirm the integrity of the 5-stage blowout preventer after reassembly. However, the intermediate thermal casing 236 already exists in the connecting well 140.

[0177] A gyro wireline survey tool can be deployed in the connecting wellbore 140. The gyro wireline survey tool will allow for continuous measurements from vertical to horizontal and the kick-off point. The gyro wireline survey tool provides well geometry with extremely high accuracy and can give the exact coordinates of the connecting wellbore 140 to assist in association with the injection well 112.

[0178] Then, the first drill rig will drill a main hole with a diameter of 222 mm (8 3 / 4 ”) through the intermediate thermal casing 236 to provide an open hole with a diameter of 200 m. Similar to the above, the first drill rig can use an oil-based mud system to drill the main hole.

[0179] After drilling the main hole, the directional control drilling assembly will be removed from the well. Then, a magnetic tool will be lowered into the wellbore until the end of the 200 m open hole section. An example of the magnetic tool is Lodestone provided by Scientific Drilling Corporation. TM . The magnetic tool is an active ranging system dedicated to wellbore-related construction. It can be used in combination with all MWD systems. The sensors of the magnetic tool can be deployed in the connecting wellbore 140, while the magnetic sub-system can be deployed on the directional control drilling assembly in the injection well 112. The resulting magnetic field accurately ranges the intersection between the connecting wellbore 140 side and the injection well 112 side on the lateral section 116.

[0180] The second drill rig will drill a hole with a diameter of 222 mm (8 3 / 4The main hole of the (") is drilled through the surface casing 144 to a predetermined depth. In a preferred embodiment, the predetermined depth is between 2300 m and 2500 m. However, the depth may vary depending on the preferred temperature or the geothermal target formation. Initially, the well may be drilled vertically and then directionally drilled to achieve a 90-degree inclination at the entry formation point 224 near the lower end 196 of the injection well 112. The entry formation point 224 will be located in the geothermal target formation. Similar to the first drill rig that drills the main hole of the connecting wellbore 140, an oil-based mud system can be used to drill the main hole of the injection well 112. Then, the drilling assembly can be removed from the well. Then, a gyro cable logging tool can be deployed in the injection well 112 to provide the coordinates of the injection well 112, thereby assisting in the association with the connecting well 140. A new directionally controlled drilling assembly equipped with a magnetic tool (such as the Lodestone TM kit) will be lowered into the wellbore.

[0181] To associate the two ends of the lower lateral section 116, lateral drilling will continue in the direction of the connecting wellbore 140 from the entry formation point 224 ends of the injection well 112 and the lower lateral section 116. The magnetic tool will assist in associating the two wellbores. After the two ends of the lower lateral section 116 are associated at the intersection point 240, the two directionally controlled drilling assemblies can be removed from their respective wellbores.

[0182] In step 1510 (shown in Figure 15 ), production steel casing 156 is installed in the injection well 112 and the lower lateral section 116.

[0183] Referring to Figure 8 , production steel casing 156 with a diameter of 139 mm (5 1 / 2 ”) can be installed along the injection well 112 and the lower lateral section 116 from the entry formation point 224 to the intersection point 240. Specifically, the production steel casing 156 can extend 50 m from the inlet 112A of the injection well 112 at the surface 316 into the intermediate heat casing 236 of the connecting wellbore 140. The lowermost section 248 of the production steel casing 156 will have a connection / seal assembly (not shown) for pressure test connection to the multi-branch connector 120. In the current embodiment, the connection / seal assembly is a polished hole socket. The polished hole socket will be equipped with a Baker coiled tubing centralizer / reverse seal hole extension structure and an anchor seal assembly latch profile (not shown).

[0184] Prior to cementing, a customized steel centralizer (not shown) can also be attached to the exterior of the casing 156. The centralizer is typically designed to lift the casing 156 from the bottom of the lower lateral section 116, allowing the cement to completely surround the casing 156. Customized elongated centralizers can also be used to provide higher conductivity (since they are made of steel) for conducting formation heat through the cement 152 directly to the steel casing 156. As previously mentioned, hematite can also be added to the cement 152 to optimize thermal conductivity.

[0185] In step 1515 (shown in Figure 15 ), the isolation packer 252 and the cementing stage tool 256 are installed, and the production steel casing 156 of the injection well 112 and the lower lateral section 116 are cemented in place.

[0186] Refer to Figure 9 , the isolation packer 252 is a rubber element that can expand to create an impermeable seal between the outer diameter of the production steel casing 156 and the inner diameter of the intermediate thermal casing 236. This will prevent cement from entering the remaining intermediate casing, thus avoiding blockage of the connection well 140. In a preferred embodiment, two isolation packers 252 can be used to increase the integrity of the seal packer (not shown).

[0187] The cementing stage tool 256 will be opened (it also creates an inner diameter plug at the end of the production steel casing 156 to prevent cement from entering the intermediate thermal casing 236 from the connection well 140). Then, the production steel casing 156 of the injection well 112 can be cemented to the surface of the surrounding rock formation 320.

[0188] Cementing the production steel casing 156 includes first circulating around the injection well 112 to remove all drill cuttings. Then, a first dart can be dropped from the surface into the injection well 112 to expand the isolation packer 252 and open the cementing stage tool 256, allowing the cement to circulate around the outer diameter of the production steel casing 156. Then, the injection well 112 undergoes a first pre-flush of 5 m 3 of thickened water, which is weighted similar to the previous flush to maintain wellbore overbalance. Then, the injection well 112 undergoes a 5 m 3 cleaning agent (weighted to 1450 kg / m 3)'s second pre - flush to keep the injection well 112 over - balanced. Then, a thermosetting cement with a total calculated pore volume plus a 20% surplus (about 62t) is filled / supplied into the intermediate thermal casing 236. Then, the tail cement has an airtight cement with a 20% surplus (about 98t). Then, the cement is displaced with fresh water. Those skilled in the art should recognize that, similar to the drilling process for connecting well 140 described above, the volume, ratio, and intervals of the cement and pre - flush can be adjusted based on geographical location, historical data of the formation, formation pressure, and regional regulatory isolation requirements for certain formations to prevent cross - flow contamination. A second projectile is also dropped from the surface into the injection well 112 and falls into the cementing stage tool 256 (acting as a check valve), which closes the cementing port, thus effectively preventing the cement from flowing back into the injection well 112.

[0189] The production steel casing 156 will be set in a tensioned state together with the automatic slips in the casing slip seat, which allows the production steel casing 156 to be bolted to the 5 - stage blowout preventer.

[0190] The second rig will pick up the milling assembly, which includes a bit of 114.3mm (4 1 / 2 ”), a mud motor, and drill pipe with a diameter of 73mm (2 7 / 8”). It is lowered into the well and mills out the cementing stage tool 256 and the floating equipment to allow the working fluid 200 to flow freely. Debris is also removed from the connecting wellbore 140, the lower lateral section 116, the connector 160, and the injection well 112 by circulating inhibitory water so that it flows down along the injection well 112 through the connector 160 and the lower lateral section 116 and back up along the connecting wellbore 140 to the surface 316.

[0191] In step 1520 (shown in Figure 15 ), a two - part whipstock 260 is installed, a pilot hole is drilled to allow the planned production well 128 and the upper lateral section 124 to be associated with the lower lateral section 116, and the initial hole of the production well 128 is drilled.

[0192] Referring to Figure 10 , a two - part whipstock 260 (also referred to herein as whipstock 260) is installed within the lower lateral section 116, near the isolation packer 252, between the formation entry point 228 and the isolation packer 252. The whipstock 260 includes an upper section (spoon - shaped) that forces a pineapple mill (not shown) to cut a diamond - shaped window 264 (also referred to herein as the milling window 264 and the bridging hole 264) through the intermediate casing 236. The whipstock 260 also includes a lower section (not shown) that includes a guide and an anchor (not shown) that can be permanently set in the intermediate casing. The guide allows the drilling and completion assembly to be guided out through the window. In addition, there is a diameter of 139.7 (51 / 2 ”) The hole allows the completion assembly to turn to the lower section of the wellbore. Those skilled in the art should recognize the use of whipstocks and their use in forming wellbore junctions.

[0193] The whipstock and the milling window 264 will allow a second wellbore to be drilled from the connecting wellbore 140 in the geothermal target formation.

[0194] Then, the second rig can be moved to position 312 above the planned production well 128. The second rig will drill a hole with a diameter of 311 mm (12 1 / 4 ”) and a depth of 650 m. Similar to the initial holes of the injection well 112 and the connecting wellbore 140, the drilling mud can be an environmentally friendly fresh water gel system. The surface casing 148 can be set in place with a diameter of 244 mm (9 5 / 8”) and extending to a depth of 650 m, and the entire length of the surface casing 148 can be cemented to the surface of the surrounding rock formation 320.

[0195] The cement casing used in combination with the surface casing 148 preferably has its volume plus 50% of hot cement (about 45 t) with a density of 1860 kg / m3. Then, the cement casing can undergo a first pre-flush with 2.5 m 3 of fresh water. Then, the cement casing can undergo a second pre-flush with 5 m 3 of thickened water (weighted to 1200 kg / m 3 ). Then, a cement plug can be placed and displaced with fresh water.

[0196] Similar to the setting in place of the surface casing 144, a 5-stage blowout preventer can be installed on or near the surface casing 148. Then, the 5-stage blowout preventer can be pressure tested under the same conditions and considerations as the 5-stage blowout preventer used for the injection well 112.

[0197] In step 1525 (shown in Figure 15 ), the production well 128 and the upper lateral section 124 are drilled and the upper lateral section 124 is associated with the lower lateral section 116.

[0198] Referring to Figure 11 , the first rig can drill a hole with a diameter of 222 mm (8 3 / 4The main hole of (“) is provided through the intermediate thermal casing 236 to provide an additional 200 m of open hole. In the current embodiment, the main hole can be drilled using an oil-based mud system. The directional control drilling assembly can be removed from the connecting wellbore 140. Then, the magnetic tool is lowered into the connecting wellbore 140 until the end of the 200 m open hole extending from the connector 160. The magnetic tool can be deployed in the connecting well 140, while the magnetic subsystem can be deployed on the directional assembly in the production well 128.

[0199] The second rig will drill a main hole with a diameter of 222 mm (8 3 / 4 ”) through the surface casing 148 to a predetermined depth. Initially, the production well 128 will be drilled vertically and then directionally drilled to achieve a 90-degree inclination at the formation entry point 272. The formation entry point 272 is located in the geothermal target formation. Similar to the previous drilling process, the production well 128 can be drilled using an oil-based mud system. The directional control drilling assembly can be removed from the production well 128, and a gyro wireline survey tool can be deployed in the production well 128. The gyro wireline survey tool can provide the coordinates of the production well 128 to assist in its association with the connecting wellbore 140. A new drilling assembly configured with a magnetic tool can be lowered into the production well 128. Drilling will continue in the direction of the connecting wellbore 140. The magnetic tool and magnetic sensors will assist in associating the two wellbores. After the connecting wellbore 140 and the production well 128 are associated, the two directional control drilling assemblies can be removed from the wellbores.

[0200] The upper section of the whipstock (spoon-shaped) is removed, leaving the lower section of the whipstock 260 inside the intermediate thermal casing 236 of the connecting wellbore 140. The lower section of the whipstock (guide and anchor) allows the multi-branch connector 120 with a casing nipple or directional control drilling assembly to turn away from the window and enter the open hole section connected to the production well 128. Additionally, the guide has a hole with a diameter of 139 mm (5 1 / 2 ”) passing through the center of the whipstock 260. This allows the multi-branch connector 120 with a specific outer diameter to be lowered below the whipstock and connected to the production casing on the injection well 112. By adjusting the outer diameter of the completion assembly, the installer can ensure that the appropriate components enter the correct wellbore.

[0201] In step 1530 (shown in Figure 15 ), the production steel casing 156 is installed in the production well 128 and the upper lateral section 124.

[0202] Refer to Figure 12 and install a production steel casing with a diameter of 139 mm (5 1 / 2The production steel casing 156 of “) is installed in the associated wellbore connecting the wellbore 140. The production steel casing 156 can extend approximately 20 m from the outlet 128A of the production well 128 at the surface 316 into the intermediate thermal casing window 264 in the connecting wellbore 140. The lowermost section 276 of the production steel casing 156 can have a connection / sealing assembly similar to the lowermost section 248. Specifically, in the current embodiment, the connection / sealing assembly can be a polished hole socket with a Baker centralizer / reverse seal bore extension and an anchor seal assembly latch profile.

[0203] In step 1535 (shown in Figure 15 ), the multi-branch connector 120 is installed and connected between the upper lateral section 124 and the lower lateral section 116. Then, a pressure test is performed on the full-casing downhole loop 108.

[0204] Refer to Figure 13 , two simulated run-in-hole operations are performed on the injection well 128. The first run-in-hole is performed with a polished hole locating seal assembly without a latch and an outer diameter greater than 139.7 mm (5 1 / 2 ”), for calibrating the socket in the production well 128 to verify the exact spacing depth. The second run-in-hole is performed with a polished hole locating seal assembly without a latch and an outer diameter less than 139.7 mm (5 1 / 2 ”), for calibrating the socket in the injection well 112 to verify the exact spacing depth. This process allows for exact depth measurements and distances between the connection well 140, the injection well 112, and the production well 128. Then, the multi-branch connector 120 can be constructed with appropriate spacing to connect the injection well 112 and the production well 128.

[0205] The multi - branch connector 120 can be lowered into the connection well 140 (for formation entry operations using drill pipe) to connect the injection well 112 and the production well 128. The multi - branch connector 120 will consist of two different "legs", each leg designed to ensure and facilitate entry into a specific well (either the injection well 112 or the production well 128) and create a pressure - test connection with the production steel casing 156 in each of the injection well 112 and the production well 128. One leg 292 will include a polished - hole positioning seal assembly having a central shear - type protective cover with an outer diameter less than 139 mm. This will allow the polished - hole positioning seal assembly to be lowered through the window guide and connect to the polished - hole socket of the production steel casing on the injection well 112. The second leg 296 of the multi - branch connector 120 has the same design, except that the outer diameter is greater than 139 mm, forcing the polished - hole positioning seal assembly with the central shear - type protective cover out of the milled window and connecting to the production steel casing 156 through the polished - hole socket on the production well 128. The second leg 296 may also include a pin / shear - activated sleeve to protect the seal from frictional damage through the window 280 and the open - hole section.

[0206] The multi - branch connector 120 provides complete mechanical and hydraulic isolation support for the re - entry capable junction area. The multi - branch connector 120 is designed to accommodate re - entry connections for steam - assisted gravity drainage applications. It typically has a full - length liner extended through one fitting, and a second fitting provides a pressure - test seal in the existing lateral direction. The multi - branch connector 120 uses the connection wellbore 140 as an entry point, thus providing a junction point for the injection well 112 and the production well 128.

[0207] The connection wellbore 140 can be used to construct multiple pairs of injection wells 112 and production wells 128. By adjusting the lateral length of the lateral section of the connection wellbore 140, multiple junctions and "multiple sets" of geothermal wells can be added to the system.

[0208] Once the connection of the multi - branch connector 120 to the injection well 112 and the production well 128 is completed, circulation can be established starting from the production well 128, through the production steel casing 156, and through the drill pipe up to the surface 316 on the connection wellbore 140. The valve at the surface 316 of the connection wellbore 140 can be closed, and a pressure test can be performed on the entire assembly and the sealed connections on the injection well 112 and the production well 128. The production well 128 can be circulated first to clear any remaining cuttings in the production well 128 and the injection well 112.

[0209] When circulation can be established, a pressure test can be performed on the entire cased - hole downhole loop 108 (known to those skilled in the art).

[0210] In step 1540 (at Figure 15As shown, the isolation packer 284 and the cementing stage tool 288 are installed, and the production steel casing 156 of the production well 128 and the upper lateral section 124 is cemented in place.

[0211] Refer to Figure 13 , after successfully completing the circulation and passing the pressure test, the cementing stage tool 288 can be opened. The cementing stage tool 288 also generates an internal diameter plug at the end of the production steel casing to prevent cement from entering the intermediate heat casing 236 from the connecting wellbore 140 and the injection well 112. The production steel casing 156 of the production well 128 will be cemented in full length to the surface of the surrounding rock formation 320 at the production well 128. This includes the entire open hole section and the internal diameter of the surface casing on the production well 128.

[0212] Cementing the production steel casing 156 follows the same process as described above, including launching the first projectile to expand the isolation packer 284 and open the cementing stage tool 288, pre-rinsing the production steel casing 156 first with thickened water and then with a cleaning agent, filling with thermosetting cement, providing tail cement, displacing the cement with fresh water, and finally launching the second projectile. The production steel casing 156 is set in a tensioned state together with the automatic slips in the casing slip seat.

[0213] The second rig will pick up the milling assembly, which consists of a 114.3 mm (4 1 / 2 ”) bit, a mud motor, and 73 mm (2 7 / 8”) diameter drill pipe. Subsequently, it is lowered into the well and the cementing stage tool 288 and the floating equipment are milled out. In addition, all debris in the wellbore is removed through the production steel casing 156 that initially circulates back to the production well 128 and finally circulates to the injection well 112.

[0214] In an alternative, after cementing, the cementing stage tools 256 and 288 together with the multi-branch connector 120 connected to the lateral sections 116 and 124 can be milled out from the injection well 112 and the production well 128. This can be done using a rig and jointed drill pipe or using a coiled tubing unit. In both cases, a 114 mm (4 1 / 2 ”) drilling bit can be used to mill out the cementing stage tools 256 and 288 and verify the full gauge internal diameter of the production steel casing 156. In addition, milling will clean any debris and excess cement in the internal diameter of the production steel casing 156. Coiled tubing can also be used to mill the production well 128 and the injection well 112.

[0215] A wireline retrievable isolation plug can be installed in the connecting wellbore 140 inside the intermediate heat casing 236, which is located on the multi-branch connector 120. Then, positive and negative pressure tests can be carried out.

[0216] Once the test is successfully executed, the geothermal power generation system 100 is ready to operate according to the Figures 4 to 5 method steps shown in

[0217] The construction of the geothermal power generation system 100 uses known techniques and methods of wellbore construction in the oil and gas fields, but applies the techniques and methods in a novel and creative way to generate and produce energy from geothermal resources.

[0218] Although the foregoing description and drawings are specific preferred embodiments of the invention currently contemplated by the inventors, it should be understood that various changes, modifications, and adaptations can be made without departing from the spirit of the invention.

Claims

1. A system for generating energy from geothermal resources, the system comprises: an injection well extending underground into a rock formation, the injection well having an upper end and a lower end; a production well extending underground into the rock formation and adjacent to the injection well, the production well having an upper end and a lower end; a first lateral section connected to a location of the injection well and extending away from that location; a second lateral section connected to a location of the production well and extending away from that location; and the first lateral section and the second lateral section are connected together by a multi-branch connector, and the length of each of the first lateral section and the second lateral section is greater than the distance between the upper end of the injection well and the upper end of the production well; each of the injection well, the production well, the first lateral section, and the second lateral section is sleeved with steel and cemented in place within the rock formation; the injection well, the first lateral section, the multi-branch connector, the second lateral section, and the production well cooperate with each other to define a pressure-tested downhole loop within the rock formation and form a heat transfer arrangement with the rock formation, the pressure-tested downhole loop being configured to receive a working fluid that can undergo a phase change between liquid and gas due to heat transferred from the rock formation within the pressure-tested downhole loop; a pump fluidly connected to the injection well, the pump being configured to circulate the working fluid through the pressure-tested downhole loop; a turbine system fluidly connected to the production well, the turbine system being operable to convert mechanical energy generated by the flow of the working fluid into electricity; and a cooler fluidly connected between the pump and the turbine system for cooling the working fluid.

2. The system according to claim 1, further comprising an injection well surface casing surrounding the inlet of the injection well, the injection well surface casing being partially above the surface and configured to prevent the working fluid from escaping into the rock formation.

3. The system according to claim 1 or 2, further comprising a production well surface casing surrounding the outlet of the production well, the production well surface casing being partially above the surface and configured to prevent the working fluid from escaping into the rock formation.

4. The system according to any one of claims 1 to 3, wherein, the injection well includes an inlet, the production well includes an outlet, the inlet and the outlet are positioned close to each other on the surface, and the distance between the inlet and the outlet is 7m to 50m.

5. The system according to any one of claims 1 to 4, wherein, The system has a ground surface area of 22,500 m 2 .

6. The system according to any one of claims 1 to 5, wherein, the working fluid is a homogeneous working fluid.

7. The system according to any one of claims 1 to 5, wherein, the working fluid is a heterogeneous working fluid.

8. The system according to any one of claims 1 to 7, wherein, the depth of the injection well is 1000m to 4000m.

9. The system according to any one of claims 1 to 8, wherein, the length of the first lateral section is 2000m to 4000m.

10. The system according to any one of claims 1 to 9, wherein, the length of the second lateral section is 2000m to 4000m.

11. The system according to any one of claims 1 to 10, wherein, the depth of the production well is from 1000 m to 4000 m.

12. The system according to any one of claims 1 to 11, wherein, the first lateral section is longer than the second lateral section, and wherein the depth of the first lateral section is greater than the depth of the second lateral section.

13. The system according to any one of claims 1 to 11, wherein, the first lateral section is located at the same depth as the second lateral section, the first lateral section extends away from the lower end of the injection well at a first angle, and the second lateral section extends away from the lower end of the production well at a second angle.

14. The system according to any one of claims 1 to 13, wherein, in operation, the pressure-tested downhole circuit is configured to receive fluid pressurized between 7 MPa and 31 MPa.

15. The system according to any one of claims 1 to 14, wherein, the pressure-tested downhole circuit is capable of withstanding a pressure of at least 7 MPa.

16. The system according to any one of claims 1 to 15, wherein, the pump is a positive displacement pump with a variable speed drive controller.

17. The system according to claim 16, wherein, the positive displacement pump is selected from the group consisting of a piston pump, a gear pump, and a rotary vane pump.

18. The system according to any one of claims 1 to 17, wherein, the turbine system includes a turboexpander.

19. The system according to any one of claims 1 to 18, wherein, the turbine system is capable of generating output power of 0.5 MW to 2 MW.

20. The system according to any one of claims 1 to 19, wherein, the cooler uses ambient air as a coolant.

21. The system according to any one of claims 1 to 20, further comprising a storage tank connected between the cooler and the pump and configured to hold excess working fluid.

22. The system according to any one of claims 1 to 21, wherein, the working fluid is selected from the group consisting of a refrigerant, a hydrocarbon-based fluid, ammonia, carbon dioxide, and water.

23. The system according to claim 22, wherein, the hydrocarbon-based working fluid is selected from the group consisting of propane, ethane, pentane, butane, and hydrocarbon mixtures.

24. The system according to any one of claims 1 to 23, wherein, the working fluid is propane.

25. The system according to any one of claims 1 to 24, further comprising a recuperator having a first flow portion connected between the turbine system and the cooler and a second flow portion connected between the pump and the injection well, the recuperator being configured to transfer heat from the first flow portion to the second flow portion.

26. The system according to any one of claims 1 to 25, further comprising a channel well having a lateral section, wherein, the multi-branch connector is located within the lateral section of the channel well.

27. The system according to claim 26, further comprising: wherein, The injection well is a first injection well, the production well is a first production well, the multi-branch connector is a first multi-branch connector, the pressure-tested downhole loop is a first pressure-tested downhole loop, and the pump is a first pump; A second injection well extending underground into a rock formation, the second injection well having an upper end and a lower end; A second production well extending underground into a rock formation and adjacent to the second injection well, the second production well having an upper end and a lower end; A third lateral section connected to a location on the second injection well and extending away from that location; A fourth lateral section connected to a location on the second production well and extending away from that location; and The third lateral section and the fourth lateral section are connected together using a second multi-branch connector, and the length of each of the third lateral section and the fourth lateral section is greater than the distance between the upper end of the second injection well and the upper end of the second production well; Each of the second injection well, the second production well, the third lateral section, and the fourth lateral section is sleeved with steel and cemented in place within the rock formation; The second injection well, the second production well, the third lateral section, and the fourth lateral section cooperate with each other to define a second pressure-tested downhole loop within the rock formation and form a heat transfer arrangement with the rock formation, the second pressure-tested downhole loop being configured to receive a working fluid that can undergo a phase change between liquid and gas within the second pressure-tested downhole loop due to heat transferred from the rock formation; A second pump fluidly connected to the second injection well, the second pump being configured to circulate the working fluid through the second pressure-tested downhole loop; The turbine system is fluidly connected to the second production well, the turbine system being configured to receive the working fluid from the first production well of the first pressure-tested downhole loop and the second production well of the second pressure-tested downhole loop; The cooler is fluidly connected to both the first pump connected to the first injection well and the second pump connected to the second injection well; and The second multi-branch connector of the second pressure-tested downhole loop is located at a position spaced apart from the first multi-branch connector within the lateral section of the channel well.

28. The system according to claim 27, wherein, The first injection well includes a first inlet, the first production well includes a first outlet, the second injection well includes a second inlet, and the second production well includes a second outlet, the second inlet and the second outlet being located close to each other on the ground surface, and the distance between the second inlet and the second outlet is 7 m to 50 m.

29. The system according to claim 28, wherein, The first inlet and the second inlet are located close to each other on the ground surface, and the distance between the first inlet and the second inlet is at least 20 m.

30. The system according to claim 28, wherein, The first outlet and the second outlet are positioned close to each other on the ground surface, and the distance between the first outlet and the second outlet is at least 20 m.

31. The system according to claim 28, wherein, The system has a ground surface area of 45,000 m 2 .

32. A method of generating energy from a geothermal resource, the method comprising: providing a pressure-tested downhole circuit extending underground into a rock formation, the pressure-tested downhole circuit comprising: an injection well, a production well adjacent to the injection well, a first lateral section connected to the injection well, a second lateral section connected to the production well, and a multi-branch connector connecting the first lateral section and the second lateral section; each of the injection well, the production well, the first lateral section, and the second lateral section is sleeved with steel and cemented in place within the rock formation, and the lengths of the first lateral section and the second lateral section are greater than the distance between the injection well and the production well on the ground surface; conveying a working fluid through the pressure-tested downhole circuit, the working fluid being received by the injection well in a liquid state; while conveying the working fluid through the pressure-tested downhole circuit: transferring heat from the surrounding rock formation to the liquid working fluid and applying pressure to the liquid working fluid, a phase change of the working fluid from a liquid state to a gaseous state occurs, and the working fluid exits the production well in a gaseous state; converting the mechanical energy generated by the flow of the gaseous working fluid into electricity; cooling the working fluid and causing a phase change of the working fluid to a liquid state; and returning the working fluid to the injection well.

33. The method according to claim 32, wherein, conveying the working fluid through the pressure-tested downhole circuit includes pumping the working fluid.

34. The method according to any one of claims 32 and 33, wherein, applying pressure to the liquid working fluid includes applying a pressure of 7 MPa to 31 MPa to the liquid working fluid.

35. The method according to any one of claims 32 to 34, wherein, the step of converting the mechanical energy generated by the flow of the gaseous working fluid into electricity generates an output electricity of 0.5 MW to 2 MW.

36. The method according to any one of claims 32 to 35, wherein, the step of cooling the working fluid and causing a phase change of the working fluid is to cool using a cooler.

37. The method according to any one of claims 32 to 36, further comprising storing excess working fluid in a storage tank.

38. The method according to any one of claims 32 to 37, wherein, the working fluid is a homogeneous working fluid.

39. The method according to any one of claims 32 to 37, wherein, the working fluid is a heterogeneous working fluid.

40. The method according to any one of claims 32 to 39, wherein, the working fluid is selected from the group consisting of refrigerants, hydrocarbon-based fluids, ammonia, carbon dioxide, and water.

41. The method according to any one of claims 32 to 39, wherein, the hydrocarbon-based working fluid is selected from the group consisting of propane, ethane, pentane, and hydrocarbon mixtures.

42. The method according to any one of claims 32 to 39, wherein, The working fluid is propane.

43. The method according to any one of claims 32 to 42, wherein, the temperature of the propane received by the injection well is from 10°C to 40°C, and the pressure is from 1000 kPag to 2000 kPag.

44. The method according to any one of claims 32 to 42, wherein, the temperature of the propane received by the injection well is 20°C, and the pressure is 1300 kPag.

45. The method according to any one of claims 32 to 44, wherein, the phase change of propane from the liquid state to the gaseous state occurs when the propane reaches the conditions of a temperature of 140°C and a pressure of 6250 kPag.

46. The method according to any one of claims 32 to 45, wherein, the phase change of propane from the liquid state to the gaseous state occurs in the second lateral section or the production well.

47. The method according to any one of claims 32 to 46, wherein, the temperature of the propane leaving the production well in the gaseous state is from 90°C to 110°C, and the pressure is from 3000 kPag to 4000 kPag.

48. The method according to any one of claims 32 to 47, wherein, the temperature of the propane leaving the production well in the gaseous state is 106°C, and the pressure is 3500 kPag.

49. The method according to any one of claims 32 to 48, wherein, when the working fluid is transported through the pressure-tested downhole loop, the temperature of the propane increases by 76°C, and the pressure of the propane increases by 2170 kPag.

50. The method according to any one of claims 32 to 49, wherein, after converting the mechanical energy generated by the flow of the gaseous working fluid into electricity, the temperature of the propane is from 16°C to 63°C, and the pressure is from 700 kPag to 1500 kPag.

51. The method according to any one of claims 32 to 50, wherein, cooling the working fluid cools the propane to a temperature of 30°C and a pressure of 1080 kPag.

52. The method according to any one of claims 32 to 51, further comprising using a recuperator to transfer heat from the working fluid in a first region to the working fluid in a second region, the working fluid in the first region being between the step of converting the mechanical energy generated by the flow of the gaseous working fluid and the step of cooling the working fluid, and the working fluid in the second region being between the step of transporting the working fluid through the pressure-tested downhole loop and the step of receiving the working fluid in the liquid state by the injection well.

53. A method of constructing a pressure-tested downhole loop for a system for generating energy from a geothermal resource, the pressure-tested downhole loop configured to transfer heat from surrounding rock formations to a working fluid flowing within the pressure-tested downhole loop and to cause a phase change of the working fluid from a liquid state to a gaseous state, the method comprises: providing a channel well extending underground into a rock formation; drilling an injection well into the underground rock formation, the injection well being spaced apart from the channel well, drilling a first lateral section extending away from the injection well and connected to the channel well; Install a first steel casing for the injection well and the first lateral section; Fix the first steel casing for the injection well and the first lateral section in place within the rock formation; Drill a production well into the underground rock formation, the production well being close to the injection well; Drill a second lateral section that extends away from the production well towards the connection point between the first lateral section and the second lateral section, the connection point being located in the access well and adjacent to the first lateral section; Install a second steel casing for the production well and the second lateral section; Provide a multi-branch connector through the access well and install the multi-branch connector at the connection point between the first lateral section and the second lateral section; Conduct a pressure test on the downhole loop, the downhole loop including the injection well, the first lateral section, the multi-branch connector, the second lateral section, and the production well, the lengths of the first lateral section and the second lateral section being greater than the distance on the surface between the upper end of the injection well and the upper end of the production well; and Cement the second steel casing for the production well and the second lateral section to the rock formation.

54. The method according to claim 53, further comprising drilling a hole for the surface casing of the injection well before drilling the injection well and setting the surface casing of the injection well in place.

55. The method according to any one of claims 53 and 54, wherein, Fixing the first casing for the injection well and the first lateral section in place within the rock formation includes drilling a bridging hole at the intersection between the first lateral section and the second lateral section, and drilling the second lateral section includes connecting the second lateral section to the bridging hole.

56. The method according to any one of claims 53 to 55, further comprising installing a first isolation packer and a first cementing staging tool before fixing the first casing for the injection well and the first lateral section in place within the rock formation, the first isolation packer and the first cementing staging tool being installed close to the intersection between the first lateral section and the access well, the first isolation packer being installed around the outer diameter of the first casing, and the first cementing staging tool being installed inside the inner diameter of the first casing and plugging the inner diameter of the first casing.

57. The method according to any one of claims 53 to 56, wherein, Drilling the second lateral section that extends away from the production well towards the connection point includes installing a whipstock inside the first lateral section close to the connection point.

58. The method according to any one of claims 53 to 57, further comprising drilling a hole for the surface casing of the production well before drilling the production well and setting the surface casing of the production well in place.

59. The method according to any one of claims 53 to 58, wherein, Conducting a pressure test on the downhole loop includes subjecting the downhole loop to the pressure at the maximum depth within the downhole loop.

60. The method according to any one of claims 53 to 60 further includes installing a second isolation packer and a second cementing staging tool before cementing the second casing for the production well and the second lateral section in place within the rock formation, the second isolation packer and the second cementing staging tool being installed near the intersection between the second lateral section and the multi-branch connector, the second isolation packer being installed around the outer diameter of the second casing, and the second cementing staging tool being installed within the inner diameter of the second casing and blocking the inner diameter of the second casing.

61. A system for generating energy from a geothermal resource, the system comprising: a first injection well and a second injection well extending underground into a rock formation, each of the first injection well and the second injection well having an upper end and a lower end; a first production well and a second production well extending underground into a rock formation, the first production well and the second production well being respectively close to the first injection well and the second injection well, each of the first production well and the second production well having an upper end and a lower end; a first lateral section connected to a location of the first injection well and extending away from that location; a second lateral section connected to a location of the first production well and extending away from that location; a third lateral section connected to a location of the second injection well and extending away from that location; a fourth lateral section connected to a location of the second production well and extending away from that location; the first lateral section and the second lateral section being connected together by a first multi-branch connector, the length of each of the first lateral section and the second lateral section being greater than the distance between the upper end of the first injection well and the upper end of the first production well; the third lateral section and the fourth lateral section being connected together by a second multi-branch connector, the length of each of the third lateral section and the fourth lateral section being greater than the distance between the upper end of the second injection well and the upper end of the second production well; each of the first injection well, the second injection well, the first production well, the second production well, the first lateral section, the second lateral section, the third lateral section, and the fourth lateral section being sleeved with steel and cemented in place within the rock formation; the first injection well, the first lateral section, the first multi-branch connector, the second lateral section, and the first production well cooperating with each other to define a first pressure-tested downhole circuit within the rock formation, the second injection well, the third lateral section, the second multi-branch connector, the fourth lateral section, and the second production well cooperating with each other to define a second pressure-tested downhole circuit within the rock formation, these pressure-tested downhole circuits forming a heat transfer arrangement with the rock formation, each of the first pressure-tested downhole circuit and the second pressure-tested downhole circuit being configured to receive a working fluid that can undergo a phase change between liquid and gas due to heat transferred from the rock formation; a first pump fluidly connected to the first injection well, the first pump being configured to circulate the working fluid through the first pressure-tested downhole circuit; A second pump, fluidly connected to the second injection well, the second pump configured to circulate a working fluid through the second pressure-tested downhole loop; A turbine system, fluidly connected to the first production well and the second production well, the turbine system operable to convert mechanical energy generated by the flow of the working fluid into electricity; a cooler, fluidly connected between the first pump and the second pump and the turbine system, the cooler operable to cool the working fluid received from the turbine system and supply the cooled working fluid to the first pump and the second pump; and The first pressure-tested downhole loop and the second pressure-tested downhole loop are close to each other.

62. A system for generating energy from a geothermal resource, the system comprising: An injection well extending underground into a rock formation, the injection well having an upper end and a lower end; A production well extending underground into a rock formation and close to the injection well, the production well having an upper end and a lower end; A first lateral section connected to a location on the injection well and extending away from that location; A second lateral section connected to a location on the production well and extending away from that location; and The first lateral section and the second lateral section are connected together using a multi-branch connector; Each of the injection well, the production well, the first lateral section, and the second lateral section is sleeved with steel and cemented in place within the rock formation; The injection well, the first lateral section, the multi-branch connector, the second lateral section, and the production well cooperate with each other to define a pressure-tested downhole loop within the rock formation and form a heat transfer arrangement with the rock formation, the pressure-tested downhole loop configured to withstand a pressure of at least 7 MPa and receive a working fluid that can undergo a phase change between liquid and gas due to heat transferred from the rock formation within the pressure-tested downhole loop; A pump, fluidly connected to the injection well, the pump configured to circulate a working fluid through the pressure-tested downhole loop; A turbine system, fluidly connected to the production well, the turbine system operable to convert mechanical energy generated by the flow of the working fluid into electricity; and A cooler, fluidly connected between the pump and the turbine system for cooling the working fluid.

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