A system for generating energy from geothermal sources, and its operation and construction methods.

Abstract

This disclosure describes a system and method for generating energy from a geothermal source. The system includes an insulated injection pipe and a common well segment, an injection well and a production well, a first lateral section connected to the injection well and a second lateral section connected to the production well, a multi-branch connector joining the first and second lateral sections, the insulated injection pipe coordinating with the common well segment and defining a pressure-tested loop within the rock formation and in a heat transfer configuration with it. The loop is steel-cased and fixed in place with cement. The loop receives a working fluid that can undergo a phase change within the underground well loop as a result of heat transferred from the rock formation. The system also includes a pump for circulating the working fluid, a turbine system for converting the flow of the working fluid into electricity, and a cooler.

Description

[Technical Field]

[0001] This disclosure generally relates to generating energy from geothermal sources, and more specifically to systems for generating energy from geothermal sources, as well as methods for operating and constructing such systems. [Background technology]

[0002] A system for generating energy from a geothermal source (also referred to herein as a geothermal energy generation system) is designed such that a working fluid or water circulates underground and is heated, and then the thermal energy is returned to the surface and converted into electricity. The working fluid or water is then cooled and returned to the heat source underground.

[0003] In some known geothermal energy generation systems, the working fluid flowing underground is exposed to the subsurface bedrock, allowing the first working fluid to pick up solid debris, rocks, and other solids as it flows underground. Picking up solid debris, rocks, and other solids can cause problems for any equipment with moving parts, such as pumps needed to circulate the working fluid or turbines used to generate electricity from the thermal energy of the working fluid when it returns to the surface.

[0004] One way to solve this is to provide a filter along the working fluid path or before the working fluid enters the machine. A filter can help reduce the amount of solid foreign matter or solids carried by the working fluid into any machine. However, this increases maintenance costs because the filter needs to be replaced. Furthermore, the filter is an additional component and therefore leads to another potential point of failure in the system.

[0005] Another way to solve the problem of solid foreign matter in the working fluid is to use a binary cycle power plant that uses two working fluids, the first working fluid which is heated underground and then passes alongside an isolated secondary working fluid in a second loop, thereby heating the second working fluid which is used to power the turbine. This can prevent the turbine from encountering solid foreign matter, but the pumps required to circulate the first working fluid underground still need to deal with solid foreign matter. Furthermore, binary cycle power plants are not efficient due to high parasitic loads, and a considerable amount of heat can be lost when transferring heat from the first working fluid to the second working fluid.

[0006] Furthermore, the working fluid looping underground may also begin to erode the rock surface along the fluid flow path. This erosion of the rock surface can lead to unstable underground pathways, potentially resulting in environmental damage. Thus, to prevent erosion and protect the integrity of the rock layer, the flow rate of the working fluid must be minimized. This adds to the underground residence time of the working fluid.

[0007] When working fluid flows underground, it can leak into the surrounding environment through gaps in the underground bedrock, potentially causing subsurface contamination. Therefore, to be environmentally friendly, the working fluid needs to be an environmentally friendly fluid such as water. However, if the first working fluid picks up unenvironmentally unfriendly substances along its path, such as oil, as it flows through the pump, this can still leak into the external environment.

[0008] In other known geothermal energy systems, a chemical layer, chemical treatment layer, or polymer coating layer is provided to prevent erosion, leakage into the environment, and the inclusion of solid foreign matter in the working fluid along the underground loop. The polymer coating is applied to the rock layer, sealing the rock layer from the circulating fluid. However, some inherent drawbacks associated with polymer coating layers include the inability to pressure test the polymer-coated underground loop. Without pressure testing of the underground loop, there is no guarantee as to whether the polymer coating layer will hold up to the depth where the working fluid is subjected to high pressure, and whether the polymer coating layer will react with various working fluids, and therefore leakage, including underground contamination, may occur.

[0009] Furthermore, the polymer coating itself is susceptible to erosion, which can lead to erosion of the bedrock layer. This can result in contamination of the primary working fluid. To prevent this, the polymer coating may need to be applied in several layers and may also need to be replaced continuously, leading to high maintenance costs, additional downtime, and loss of production time. Even after the polymer coating has been applied, it is difficult to ensure that the bedrock layer and the entire pathway / loop of the primary working fluid are coated, and it is even more difficult to guarantee the thickness or integrity of the polymer coating.

[0010] Other prior art, such as U.S. Patent Application Publication 2018 / 0291880 and International Patent Application Publication WO2022029699, provides a casing, but this casing is not cemented in place and may result in instability. Furthermore, this casing is not pressure-tested and may become unstable at high pressures or with high-flow or fluctuating-flow working fluids underground. If a working fluid other than water leaks, as provided in both of the aforementioned patent application publications where two working fluids are used, the instability may result in reduced operational performance and potential subsurface contamination. Subsurface contamination can occur due to leakage of the working fluid into voids in the rock layer. These voids may be previously existing, unknown cracks or cracks induced by drilling during the construction of the geothermal energy generation system. If there is a working fluid leak, the fluid may be transported through the cracks to sensitive resources such as groundwater.

[0011] In other prior art, such as U.S. Patent Application Publication 2011 / 0048005, a continuous series of pipes are cemented inside the entire length of two connected wells, specifically running from the injection wellhead of one borehole to a nearly horizontal underground pipeline, ascending a rising well and returning to the production wellhead. This allows the working fluid to be transported underground, undergo a phase change due to heat from the surrounding subsurface rock, and then transported back to the surface for use at the power plant. Only a single underground horizontal pipeline exists connecting the injection wellhead and the production wellhead. In this type of system, the single underground horizontal pipeline and the distance between the injection wellhead and the production wellhead tend to be very long in order to provide sufficient heat transfer between the rock layer and the production fluid. This large distance between the injection wellhead and the production wellhead tends to create a large footprint both above and below ground. This increases the overall system cost because of the additional piping length required above ground between the injection wellhead and the production wellhead, the additional amount of working fluid for the additional above-ground piping length, and the heat lost due to the additional time the production fluid remains above ground, which could potentially increase parasitic loads. Furthermore, the construction technique provided in U.S. Patent Application Publication 2011 / 0048005 does not allow for pressurized connection between the two sections.

[0012] Therefore, it would be advantageous for geothermal energy generation systems to have underground loops that include pressure-testable barriers, and to have solutions that minimize the risk of erosion, inclusion of solid foreign matter, and leakage into the surrounding bedrock and environment. Furthermore, it would be beneficial to have solutions that require minimal maintenance, save costs, minimize downtime, and have fewer points of failure within the system. [Prior art documents] [Patent Documents]

[0013] [Patent Document 1] U.S. Patent Application Publication No. 2018 / 0291880 [Patent Document 2] International Patent Application Publication No. WO2022029699 [Patent Document 3] U.S. Patent Application Publication No. 2011 / 0048005 [Overview of the Initiative]

[0014] According to a broad embodiment of the present invention, a system for generating energy from a geothermal source is provided. The system includes a common well segment extending underground into a rock formation. The common well segment has an upper end and a lower end. The system further includes an adiabatic injection pipe extending underground into a rock formation. A portion of the adiabatic injection pipe is located in the same location as the common well segment. The adiabatic injection pipe is also fluidly isolated from the common well segment. The system also includes an injection well extending further underground from the lower end of the common well segment. The injection well also has an upper end and a lower end, and the upper end of the injection well is fluidly connected to the adiabatic injection pipe. Furthermore, the system includes a production well extending further underground from the lower end of the common well segment. The production well also has an upper end and a lower end, and the upper end of the production well is fluidly connected to the common well segment. The system also includes a first lateral section connected to a location along the injection well and extending away from there. The system further includes a second lateral section connected to a location along the production well and extending away from there. The system also includes a multi-branch connector joining the first and second lateral sections. The common well segment, injection well, production well, and the first and second lateral sections are cased in steel and cemented into place within the rock formation. Furthermore, the adiabatic injection pipe, injection well, first lateral section, multi-branch connector, second lateral section, production well, and common well segment cooperate with each other to define a pressure-tested underground well loop within the rock formation and are in a heat transfer configuration with it. The pressure-tested underground well loop receives a working fluid that can undergo a phase change between liquid and gas within the pressure-tested underground well loop as a result of heat transferred from the rock formation. The system also includes a fluid-connected pump in the adiabatic injection pipe, which circulates the working fluid through the pressure-tested underground well loop. The system further includes a fluid-connected turbine system in the common well segment, which is operable to convert the mechanical energy generated from the flow of the working fluid into electricity. Furthermore, the system includes a cooler fluid-connected between the pump and the turbine system to cool the working fluid.

[0015] In one feature, the system can include a surface casing that surrounds the opening of the common well segment. The surface casing may be partially above the ground surface and may prevent the leakage of the working fluid into the rock formation.

[0016] In another feature, the system can have a ground surface area of 30,100 m 2 .

[0017] In a further feature, the working fluid may be a homogeneous working fluid.

[0018] In yet another feature, the working fluid may be a heterogeneous working fluid.

[0019] In another feature, the common well segment can have a depth of about 650 m.

[0020] Preferably, the first lateral section extends away from the injection well at a depth of 1000 m to 3500 m.

[0021] Preferably, the second lateral section extends away from the production well at a depth of 1000 m to 3500 m.

[0022] Preferably, the first lateral section has a length of 2000 m to 4000 m.

[0023] Preferably, the second lateral section has a length of 2000 m to 4000 m.

[0024] Optionally, the first lateral section is at a depth lower than the depth of the second lateral section.

[0025] Optionally, the second lateral section is at a depth lower than the depth of the first lateral section.

[0026] Alternatively, the first lateral section may be at the same depth as the second lateral section, or it may be spaced apart from the second lateral section.

[0027] One feature is that, during operation, the pressure-tested underground well loop can receive pressurized fluid at 7 MPa to 31 MPa.

[0028] Another characteristic is that the pressure-tested underground well loops can withstand a pressure of at least 7 MPa.

[0029] One feature is that the pump may be a positive displacement pump equipped with a variable speed drive controller.

[0030] In terms of further features, the positive displacement pump may be selected from the group consisting of plunger pumps, gear pumps, and rotary vane pumps.

[0031] Another feature is that the turbine system may include a turbine expander.

[0032] Another feature is that the turbine system can generate an output power of 0.5 to 2 MW.

[0033] One feature is that the cooler can use ambient air as a coolant.

[0034] Optionally, the system may include a storage tank. The storage tank may be connected between the cooler and the pump and may hold excess working fluid.

[0035] One characteristic is that the working fluid may be a refrigerant, a hydrocarbon fluid, ammonia, carbon dioxide, or water.

[0036] Optionally, if the working fluid is a hydrocarbon-based working fluid, the working fluid may be propane, ethane, pentane, butane, or a hydrocarbon blend.

[0037] Preferably, the working fluid is propane.

[0038] In one feature, the system may include a reheater having a first flow path connected between the turbine system and the cooler, and a second flow path connected between the pump and the adiabatic injection pipe. The reheater can transfer heat from the first flow path to the second flow path.

[0039] In another feature, the insulated injection pipe may be a steel pipe having an insulating compound that coats the steel pipe.

[0040] Another feature is that a portion of the adiabatic injection pipe may extend along the central axis of the common well segment.

[0041] Another feature is that the upper end of the injection well may include a downward sloping section, and the lower end of the injection well may include a vertical section.

[0042] Preferably, most of the injection wells are spaced apart from the production wells.

[0043] More preferably, most of the injection wells are spaced at least 80 m laterally from the production wells.

[0044] One feature of the system is that it may also include a geothermal isolation junction located along the bottom of the common well segment. The adiabatic injection pipe may be connected to the injection well via the geothermal isolation junction. The system may also include an isolation packer located along the top of the production well. Furthermore, the system may include an adiabatic production pipe that fluidly connects the production well and the common well segment. A portion of the adiabatic production pipe may extend between the isolation packer and the geothermal isolation junction. The geothermal isolation junction isolates the working fluid in the adiabatic injection pipe from the working fluid in the adiabatic production pipe.

[0045] One feature is that a portion of the insulated injection pipe is positioned concentrically with the common well segment.

[0046] Alternatively, the portion of the insulated injection pipe c is positioned eccentrically with the common well segment, in the same location.

[0047] One feature is that the system may include an access well having lateral segments. Multi-branch connectors may be located within the lateral segments of the access well.

[0048] In yet another feature, if the common well segment is the first common well segment, the adiabatic injection pipe is the first adiabatic injection pipe, the injection well is the first injection well, the production well is the first production well, the multi-branch connector is the first multi-branch connector, the pressure-tested underground well loop is the first pressure-tested underground well loop, and the pump is the first pump, then the system may include a second common well segment extending underground into the rock formation. The second common well segment may have an upper and a lower end. The system may further include a second adiabatic injection pipe extending underground into the rock formation. A portion of the second adiabatic injection pipe is located in the same place as the second common well segment. The second adiabatic injection pipe is fluidly isolated from the second common well segment. The system may also include a second injection well extending further underground from the lower end of the second common well segment. The second injection well may have an upper and a lower end. The upper end of the second injection well is fluidly connected to the second insulated injection pipe. The system further includes a second production well extending further underground from the lower end of the second common well segment. The second production well has an upper and a lower end. The upper end of the second production well is fluidly connected to the common well segment. The system also includes a third lateral section connected to a position along the second injection well and extending away from it. The system further includes a fourth lateral section connected to a position along the second production well and extending away from it. Furthermore, the system includes a second multi-branch connector joining the third and fourth lateral sections. Each of the second common well segment, the second injection well, the second production well, and the third and fourth lateral sections is cased with steel and cemented into place within the rock mass. The system includes a second injection pipe, a second injection well, a third lateral section, a second multi-branch connector, a fourth lateral section, a second production well, and a second common well segment, which work together to define a second pressure-tested underground well loop within the rock formation and are in a heat transfer configuration with it.Furthermore, the second pressure-tested underground well loop can receive a working fluid that can undergo a phase change between liquid and gas within the second pressure-tested underground well loop as a result of heat transferred from the rock layer. The system also includes a second pump fluid-connected to the second adiabatic injection pipe. The second pump circulates the working fluid through the pressure-tested underground well loop. Furthermore, the second common well segment is fluid-connected to a turbine system. The turbine system receives working fluid from the first production well in the first pressure-tested underground well loop and the second production well in the second pressure-tested underground well loop. Furthermore, a cooler is fluid-connected to both the first pump connected to the first adiabatic injection pipe and the second pump connected to the second adiabatic injection pipe.

[0049] In one feature, the second multi-branch connector of the second pressure-tested underground well loop is located within the lateral segment of the access well at a position spaced apart from the first multi-branch connector.

[0050] Alternatively, the lateral segment of the access well is the first lateral segment, and the second multi-branch connector of the second pressure-tested underground well loop is located within the second lateral segment of the access well. The second lateral segment of the access well may be spaced apart from the first lateral segment of the access well.

[0051] Another characteristic is that the first lateral segment is located at a different depth than the second lateral segment.

[0052] Another feature is that the system has a range of 30,100m 2 It has the following surface area above ground.

[0053] According to another aspect of the present invention, a system for generating energy from a geothermal source is provided. The system includes a common well segment extending underground into a rock formation. The common well segment has an upper end and a lower end. The system also includes an insulated production pipe extending underground into a rock formation. A portion of the insulated production pipe is located in the same location as the common well segment. The insulated production pipe is fluidly isolated from the common well segment. The system further includes an injection well extending further underground from the lower end of the common well segment. The injection well has an upper end and a lower end. The upper end of the injection well is fluidly connected to the common well segment. The system also includes a production well extending further underground from the lower end of the common well segment. The production well has an upper end and a lower end. The upper end of the production well is fluidly connected to the insulated production pipe. Furthermore, the system includes a first lateral section connected to a location along the injection well and extending away from there. The system also includes a second lateral section connected to a location along the production well and extending away from there. The system further includes a multi-branch connector that joins the first lateral section and the second lateral section. Each of the common well segment, injection well, production well, and the first and second lateral sections is cased with steel and cemented into place within the rock formation. The common well segment, injection well, first lateral section, multi-branch connector, second lateral section, production well, and insulated production pipe cooperate with each other to define a pressure-tested underground well loop within the rock formation and to which a heat transfer configuration exists. The pressure-tested underground well loop receives a working fluid that can undergo a phase change between liquid and gas within the pressure-tested underground well loop as a result of heat transferred from the rock formation. The system includes a pump fluid-connected to the common well segment. The pump circulates the working fluid through the pressure-tested underground well loop. The system also includes a turbine system fluid-connected to the insulated production pipe. The turbine system operates to convert the mechanical energy generated from the flow of the working fluid into electricity. The system further includes a cooler fluid-connected between the pump and the turbine system to cool the working fluid.

[0054] According to another aspect of the present invention, a method for generating energy from a geothermal source is provided. The method comprises providing a pressure-tested underground well loop extending into a rock formation underground. The pressure-tested well loop includes an insulated injection pipe, an injection well, a production well, a first lateral section connected to the injection well, a second lateral section connected to the production well, a multi-branch connector connecting the first and second lateral sections, and a common well segment. A portion of the insulated injection pipe is located in the same location as the common well segment. Each of the injection well, production well, the first and second lateral sections, and the common well segment is cased with steel and cemented into place in the rock formation. The method further comprises transporting a working fluid through the pressure-tested underground well loop. The working fluid is received in liquid form into the insulated injection pipe. While transporting the working fluid through the pressure-tested underground well loop, the method further comprises transferring heat from the surrounding rock formation to the liquid working fluid and pressurizing the liquid working fluid. Furthermore, while transporting the working fluid through a pressure-tested underground well loop, the method further includes inducing a phase change from a liquid state to a gaseous state of the working fluid. The working fluid exits the common well segment in a gaseous state. The method includes converting the mechanical energy generated from the flow of the gaseous working fluid into electricity. The method also includes cooling the working fluid and inducing a phase change from a liquid state to a gaseous state of the working fluid. The method further includes returning the working fluid to an adiabatic injection pipe.

[0055] One feature involves transporting the working fluid through a pressure-tested underground well loop, which includes pumping the working fluid.

[0056] Another characteristic is that applying pressure to the liquid working fluid includes applying 7 MPa to 31 MPa to the liquid working fluid.

[0057] Another feature is that the step of converting the mechanical energy generated from the flow of the gaseous working fluid into electricity generates an output power of 0.5 to 2 MW.

[0058] In another feature, the step of cooling the working fluid and inducing a phase change in the working fluid is performed using a cooler.

[0059] Optionally, the method may include storing excess working fluid in a storage tank.

[0060] One characteristic is that the working fluid is homogeneous.

[0061] Alternatively, the working fluid is a heterogeneous working fluid.

[0062] One characteristic is that the working fluid may be a refrigerant, a hydrocarbon fluid, ammonia, carbon dioxide, or water.

[0063] If the working fluid is a hydrocarbon-based working fluid, the working fluid may be propane, ethane, pentane, butane, or a hydrocarbon blend.

[0064] Alternatively, the working fluid is propane.

[0065] One feature is that the propane received through the insulated injection pipe can have a temperature of 10°C to 40°C and a pressure of 1000kPag to 2000kPag.

[0066] Alternatively, the propane received through the insulated injection pipe may have a temperature of 20°C and a pressure of 1300 kPag.

[0067] One characteristic is that when propane reaches a temperature of 140°C and a pressure of 6250 kPag, a phase change from liquid to gaseous is induced.

[0068] Another characteristic is that the induction of the phase change of propane from liquid to gaseous state occurs in either the second lateral section, the production well, or the common well segment.

[0069] One characteristic is that propane exiting a common well segment in a gaseous state can have a temperature of 90°C to 110°C and a pressure of 3000 kPag to 4000 kPag.

[0070] Alternatively, propane exiting the common well segment in a gaseous state can have a temperature of 106°C and a pressure of 3500 kPag.

[0071] One characteristic observed was that while the working fluid was being transported through a pressure-tested underground well loop, the propane temperature increased by 76°C and the propane pressure increased by 2170 kPag.

[0072] Another characteristic is that, after converting the mechanical energy generated from the flow of the gaseous working fluid into electricity, propane can have temperatures of 16°C to 63°C and pressures of 700kPag to 1500kPag.

[0073] Another feature is that the working fluid is cooled, thereby cooling the propane to a temperature of 30°C and a pressure of 1080 kPag.

[0074] In one feature, the method involves using a reheater to transfer heat from a working fluid in a first region to a working fluid in a second region. The working fluid in the first region occurs between the step of converting the mechanical energy generated from the flow of a gaseous working fluid and the step of cooling the working fluid. The working fluid in the second region occurs between the step of transporting the working fluid through a pressure-tested underground well loop and the step of receiving the working fluid in a liquid state through an adiabatic injection pipe.

[0075] According to another aspect of the present invention, a method is provided for constructing a pressure-tested underground well loop for a system for generating energy from a geothermal source. The pressure-tested underground well loop transfers heat from the surrounding rock formation to a working fluid flowing within the pressure-tested well loop, inducing 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. The method further includes drilling a common well segment into the underground rock formation. The common well segment has an upper end and a lower end. The method also includes installing a first steel casing for the common well segment. The method further includes fixing the first steel casing for the common well segment in place in the rock formation with cement. The method also includes drilling a production well further underground from the lower end of the common well segment to a first proposed intersection. The method includes drilling a first lateral section along the access well to a first proposed intersection. The method also includes connecting the first lateral section and the production well at the first proposed intersection. The method further includes installing a second steel casing for the production well and the first lateral section. The method also includes cementing the second steel casing for the production well and the first lateral section into place within the rock formation. The method includes drilling an injection well further underground from the lower end of the common well segment to the second proposed intersection. The injection well has an upper end and a lower end. The method also includes drilling a second lateral section along the access well to the second proposed intersection. The drilling of the first lateral section along the access well and the drilling of the second lateral section along the access well begin close to each other along the access well. The method also includes connecting the second lateral section and the injection well at the second proposed intersection. The method further includes installing a third steel casing for the second lateral section and the injection well. The method also includes cementing a second lateral section and a third steel casing for the injection well into place within the rock mass. The method also includes providing a multi-branch connector through the access well and installing the multi-branch connector at the connection point between the first and second lateral sections.The method also includes providing an adiabatic injection pipe fluid-connected to the upper end of the injection well. A portion of the adiabatic injection pipe is located in the same location as the common well segment. The method also includes pressure testing an underground well loop, which includes the adiabatic injection pipe, the injection well, a first lateral section, a multi-branch connector, a second lateral section, a production well, and a common well segment.

[0076] According to another aspect of the present invention, a system for generating energy from a geothermal source is provided. The system includes a first common well segment and a second common well segment extending underground into a rock formation. Each of the first and second common well segments has an upper end and a lower end. The system also includes a first adiabatic injection pipe and a second adiabatic injection pipe extending underground into a rock formation. A portion of the first adiabatic injection pipe is located in the same location as the first common well segment. Furthermore, a portion of the second adiabatic injection pipe is located in the same location as the second common well segment. Each of the first and second adiabatic injection pipes has an upper end and a lower end. The system also includes a first injection well extending further underground from the lower end of the first common well segment. The system further includes a second injection well extending further underground from the lower end of the second common well segment. Each of the first and second injection wells has an upper end and a lower end. The upper end of the first injection well is fluidly connected to the first adiabatic injection pipe. Furthermore, the upper end of the second injection well is fluidly connected to the second adiabatic injection pipe. The system further includes a first production well extending further underground from the lower end of the first common well segment. The system also includes a second production well extending further underground from the lower end of the second common well segment. Each of the first and second production wells has an upper end and a lower end. The upper end of the first production well is fluidly connected to the first common well segment. The upper end of the second production well is fluidly connected to the second common well segment. The system further includes a first lateral section connected to a position along the first injection well and extending away from it. The system also includes a second lateral section connected to a position along the first production well and extending away from it. The system further includes a third lateral section connected to a position along the second injection well and extending away from it. The system also includes a fourth lateral section connected to a location along the second production well and extending away from it. The system includes a first multi-branch connector joining the first lateral section and the second lateral section. The system further includes a second multi-branch connector joining the third lateral section and the fourth lateral section.Each of the first and second common well segments, the first and second injection wells, the first and second production wells, and the first, second, third, and fourth lateral sections is cased with steel and cemented into place within the rock mass. Furthermore, the system includes a first insulated injection pipe, a first injection well, a first lateral section, a first multi-branch connector, a second lateral section, a first production well, and a first common well segment, which work together to define a first pressure-tested underground well loop within the rock mass. The system also includes a second insulated injection pipe, a second injection well, a third lateral section, a second multi-branch connector, a fourth lateral section, a second production well, and a second common well segment, which work together to define a second pressure-tested underground well loop within the rock mass. The first and second pressure-tested underground well loops are in a heat transfer configuration with the rock mass. Each of the first and second pressure-tested underground well loops receives a working fluid that can undergo a phase change between liquid and gas as a result of heat transferred from the rock layer. The system includes a first pump fluid-connected to a first adiabatic injection pipe. The first pump circulates the working fluid through the first pressure-tested underground well loop. The system also includes a second pump fluid-connected to a second adiabatic injection pipe. The second pump circulates the working fluid through the second pressure-tested underground well loop. The system includes a turbine system fluid-connected to the first and second common well segments, which converts the mechanical energy generated from the flow of the working fluid into electricity. The system also includes a cooler fluid-connected between the first and second pumps and the turbine system, which is operable to cool the working fluid received from the turbine system and supply the cooled working fluid to both the first and second pumps. Furthermore, the first and second pressure-tested underground well loops are positioned in close proximity to each other.

[0077] A system for generating energy from a geothermal source. This system includes a common well segment extending underground into the bedrock layer. The common well segment has an upper and a lower end. The system also includes an adiabatic injection pipe extending underground into the bedrock layer. Part of the adiabatic injection pipe is located in the same location as the common well segment. The adiabatic injection pipe is fluidly isolated from the common well segment. The system also includes an injection well extending further underground from the lower end of the common well segment. The injection well has an upper and a lower end. The upper end of the injection well is fluidly connected to the adiabatic injection pipe. The system also includes a production well extending further underground from the lower end of the common well segment. The production well has an upper and a lower end. The upper end of the production well is fluidly connected to the common well segment. The system also includes a first lateral section connected to a location along the injection well and extending away from it. The system further includes a second lateral section connected to a location along the production well and extending away from it. The system includes a multi-branch connector joining the first and second lateral sections. Each of the common well segment, injection well, production well, and first and second lateral sections is cased with steel and cemented into place within the rock formation. The system further includes an insulated injection pipe, injection well, first lateral section, multi-branch connector, second lateral section, production well, and common well segment, which cooperate with each other to define a pressure-tested underground well loop within the rock formation in a heat transfer configuration with respect to it. The pressure-tested underground well loop withstands a pressure of at least 7 MPa and receives a working fluid that can undergo a phase change between liquid and gas within the pressure-tested underground well loop as a result of heat transferred from the rock formation. The system further includes a pump fluid-connected to the insulated injection pipe. The pump circulates the working fluid through the pressure-tested underground well loop. Furthermore, the system includes a turbine system fluid-connected to the common well segment. The turbine system converts the mechanical energy generated from the flow of the working fluid into electricity. The system also includes a cooler fluid-connected between the pump and the turbine system to cool the working fluid. [Brief explanation of the drawing]

[0078] Embodiments of the present invention will be better understood by referring to the following detailed description of embodiments of the present invention in conjunction with the accompanying drawings.

[0079] [Figure 1] This is a schematic cross-sectional view showing a system for generating energy from a geothermal source according to one embodiment.

[0080] [Figure 2] Figure 1 is a conceptual schematic diagram of a system for generating energy from a geothermal source.

[0081] [Figure 3] This is another conceptual schematic diagram of a system for generating energy from a geothermal source, according to an alternative embodiment of the embodiment shown in Figure 2.

[0082] [Figure 4] This flowchart shows the steps of a method for generating energy from a geothermal source according to the embodiment shown in Figure 2.

[0083] [Figure 5] Figure 3 is a flowchart showing the steps of an alternative method for generating energy from a geothermal source according to the embodiment shown.

[0084] [Figure 6A] This schematic cross-sectional view shows an alternative embodiment of a system for generating energy from a geothermal source having two fully cased underground well loops connected to a single access well, according to one embodiment.

[0085] [Figure 6B] Figure 6A is a conceptual schematic diagram of an embodiment of a system for generating energy from a geothermal source, in which two fully cased underground well loops are fluidly connected to a single turbine system and a single cooler, and the working fluid is propane.

[0086] [Figure 6C] This is a schematic top view of five fully cased underground well loops and a single connecting well.

[0087] [Figure 7A] This is a first flowchart showing the steps for constructing a system for generating energy from a geothermal source shown in Figure 1, according to one embodiment of the present invention.

[0088] [Figure 7B] This is a second flowchart that continues the steps of how to construct a system for generating energy from a geothermal source, as shown in Figure 7A.

[0089] [Figure 8] Figure 1 is a schematic cross-sectional view illustrating the first steps in constructing a system for generating energy from the geothermal source shown, and shows the drilling of the connecting well and common well segment.

[0090] [Figure 9] Figure 1 is a schematic cross-sectional view showing the second step in constructing a system for generating energy from the geothermal source shown, illustrating the drilling of the production well and the first lateral section, which intersect.

[0091] [Figure 10] Figure 1 is a schematic cross-sectional view showing the third step in constructing a system for generating energy from a geothermal source, showing that the casing is installed along the production well through a portion of the first lateral section, that the first isolation packer and the first cementing stage tool are installed along the first lateral section close to the construction well, that the second isolation packer is installed along the well between the common well segment and the production well, and that cement is being injected between the casing and the walls of the production well and portion of the first lateral section.

[0092] [Figure 11]Figure 1 is a schematic cross-sectional view showing the fourth step in constructing a system for generating energy from a geothermal source, where the first two-part whip stock is installed adjacent to the first isolation packer, the first opening of the first casing window is installed adjacent to the first two-part whip stock, the second two-part whip stock is installed adjacent to the second isolation packer, and the second opening of the second casing window is installed adjacent to the second two-part whip stock.

[0093] [Figure 12] Figure 1 is a schematic cross-sectional view showing the fifth step in constructing a system for generating energy from the geothermal source shown, illustrating the drilling of the injection well and the second lateral section.

[0094] [Figure 13] Figure 1 is a schematic cross-sectional view showing the sixth step in constructing a system for generating energy from a geothermal source, indicating that the casing is installed along the injection well through a second lateral section.

[0095] [Figure 14] Figure 1 is a schematic cross-sectional view showing the seventh step in constructing a system for generating energy from a geothermal source, where a third isolation packer and a second cementing stage tool are installed along the second lateral section close to the construction well, and a fourth isolation packer is installed along the injection well close to the common well segment, showing that cement is being injected between the casing and the walls of the injection well and the second lateral section.

[0096] [Figure 15] Figure 1 is a schematic cross-sectional view showing the eighth step in constructing a system for generating energy from the geothermal source shown, where the cores of the first and second two-part whip stocks have been removed, leaving the first window guide installed between the two lateral connection sections and the second window guide installed between the common well segment and the production well.

[0097] [Figure 16] Figure 1 is a schematic cross-sectional view showing the ninth step in constructing a system for generating energy from a geothermal source, illustrating the installation of a multi-branch connector along the first window guide between two lateral sections, as well as the connection of the injection well and production well via the two lateral connection sections and the multi-branch connector.

[0098] [Figure 17] Figure 1 is a schematic cross-sectional view showing the tenth step in constructing a system for generating energy from a geothermal source, illustrating the installation of a geothermal isolation junction along a second window guide, the first leg of which connects a common well segment to a production well, and the second leg of which connects the surface to an injection well via an isolation injection pipe, and the installation of the geothermal isolation junction provides a circulating flow of working fluid for a closed-loop fully cased underground well loop. [Modes for carrying out the invention]

[0099] The following description and embodiments are provided as examples of the principles and aspects of the present invention, or as examples of specific embodiments. These examples are provided for illustrative purposes only, and not as limitations, on these principles of the present invention. Throughout the following description, the same reference numerals are used for similar portions in the specification and drawings.

[0100] As a general overview, a system for generating energy from a geothermal source 100 (also referred to herein as geothermal energy generation system 100) having a single heat exchange loop is provided, the system 100 includes a fully cased, pressure-tested, and cement-fixed underground well loop 108 (also referred to herein as fully cased underground well loop 108) for isolating and circulating a single fluid 200 (also referred to as working fluid 200) over a length extending underground to achieve heat exchange between the working fluid 200 and heat emitted / radiated from the Earth (i.e., subterranean heat source). The system 100 uses a closed-loop direct turbine expansion cycle similar to the organic Rankine cycle to convert the energy stored in the heated working fluid 200 into mechanical energy, which is then used to generate electricity.

[0101] Those skilled in the art will recognize that in the Rankine cycle, the working fluid 200 may undergo a phase change. For clarity, in the following description, the working fluid 200 will be referred to collectively regardless of its state of matter. The working fluid 200 in a liquid state will be called the liquid working fluid 204, and the working fluid 200 in a gaseous state will be called the gaseous working fluid 208.

[0102] The geothermal energy generation system 100 includes a fully cased underground well loop 108 having a well assembly 110 that extends underground beneath the ground. The well assembly 110 has a common well segment 118, a lower section 154 of an insulated injection conduit or pipe, an injection well 112, and a production well 128. The injection well 112 and the production well 128 branch off from the common well segment 118 at connection point 122 and extend further underground. Also forming part of the underground well loop 108 are a first upper lateral section 116 that connects to and extends away from the injection well 112, and a second lower lateral section 124 that connects to and extends away from the production well 128. The first lateral section 116 and the second lateral section 124 merge at a joint where a multi-branch connector 120 is installed. Above ground, the geothermal energy generation system 100 includes a pump 104 fluid-connected to the top of an adiabatic injection conduit or pipe 142, which carries a liquid working fluid 204 downward to the lower part 154 of the underground adiabatic injection pipe 114, through a common well segment 118, away from the surface 316 into the injection well 112, through a first upper lateral section 116, a multi-branch connector 120 and a second lower lateral section 124, then ascends to the production well 128, through the adiabatic production pipe 166, and returns towards the surface 316 through the common well segment 118. The liquid working fluid 204 undergoes a phase change underground and returns to the surface 316 through the production well 128 and the common well segment 118 as a gaseous working fluid 208, flowing into the turbine system 132 for power generation. Within the turbine system 132, a gaseous working fluid 208 rotates the turbine, which in turn rotates the shaft, generating mechanical energy. This mechanical energy is converted into electricity by a shaft-driven generator (not shown). A cooler 136 is also provided, which is fluid-connected to the turbine system 132. The cooler 136 condenses the low-pressure gaseous working fluid 208 after it leaves the turbine system 132, returning it to its original liquid state. The low-pressure gaseous working fluid 208 is then pumped to a common well segment 118, passes through the injection well 112, and circulates through a fully cased underground well loop 108.

[0103] As will be understood by those skilled in the art and will be apparent from the following description, the disclosed geothermal energy generation system 100 tends to address the challenges identified above. More specifically, the use of a fully cased underground well loop 108 eliminates the risk of cross-contamination between the working fluid 200 flowing through the fully cased underground well loop 108 and the rock layer 320 or formation fluid, and the risk of the working fluid 200 eroding the rock layer 320, since the working fluid 200 does not come into contact with the rock layer 320. The velocity of the working fluid 200 can also be greater within the fully cased underground well loop 108, as there is no risk of eroding the rock layer 320 due to the absence of contact. The addition of casing also eliminates the risk of well instability and rock fracture due to natural and induced stresses around the well, in addition to preventing erosion of the well wall. In systems of the prior art, the velocity of the working fluid must be carefully controlled and monitored to ensure that erosion to the well or underground section is minimal in order to minimize cross-contamination. Ensuring that erosion is minimal or nonexistent is important not only from the perspective of preserving the environment but also to avoid the occurrence of instability in the rock layer 320, which could lead to earthquakes or other potential consequences. Furthermore, since the working fluid 200 is isolated from the rock layer 320, there is no risk of minerals or other materials dissolving that could alter the composition of the working fluid 200. In other prior arts in which the working fluid 200 may come into contact with the surrounding rock layer 320, there is a risk of dissolving minerals or other materials that the working fluid 200 may come into contact with, particularly as the working fluid 200 is eroded and subjected to thermal changes at the surface of the rock layer 320. Mineral dissolution can also lead to the accumulation of such minerals in the pipes or other components of the geothermal energy generation system 100 when the working fluid 200 cools, creates blockages, and adds maintenance to the system 100.

[0104] The fully cased underground well loop 108 is pressure-tested and cemented to the surrounding rock formation 320 underground. Its structure significantly minimizes leakage of the working fluid 200 from the fully cased underground well loop 108. Therefore, the risk of the working fluid 200 leaking or leaking from the fully cased underground well loop 108, potentially causing contamination or other environmental concerns, is significantly minimized, especially when the working fluid 200 is subjected to significant temperature and pressure changes. In contrast, other conventional systems may suffer fluid loss due to leakage into the formation and / or fluid contamination by formation fluid inflow because the working fluid is not completely isolated from the rock formation 320. This is due to the lack of casing, including the inability to obtain a valid pressure test. As a result, the fully cased underground well loop 108 can use unconventional working fluids 200 having different heat capacities and different phase transition points, enabling a potentially more energy-efficient system, greater power output, and a smaller footprint geothermal power system while reducing concerns about environmental pollution. Furthermore, parasitic power losses are minimized. Those skilled in the art will recognize that parasitic losses can be described as absorbed power, which is the energy required to operate pumps, cooler fans, and other loads, and reduce the net energy output of the system. Those skilled in the art will also recognize that net energy is the power generated after subtracting the power used to operate the system.

[0105] The casing material for a fully cased underground well loop 108 may be steel. Unlike other conventional techniques where chemical liners may be used, steel, along with cement support, is a hardened, inert material that can withstand high pressure. Furthermore, the risk of steel chemically interacting with the working fluid 200 is lower, and the choice of working fluid 200 for the geothermal energy generation system 100 is wider. Moreover, the construction and application of steel casings are substantially safer compared to chemical liners, provided that no leaks are ensured within the fully cased underground well loop 108.

[0106] In contrast to two loops with two working fluids, using a single heat exchange loop with a single working fluid 200 significantly reduces parasitic energy losses because heat is retained within the single working fluid 200 and is not lost to the environment during heat transfer as would occur in the presence of multiple working fluids.

[0107] Furthermore, because the working fluid 200 is completely contained within the geothermal energy generation system 100, the working fluid 200 can be easily changed if environmental conditions change. For example, if the subsurface temperature changes, the working fluid 200 can be easily replaced with another working fluid 200 having a lower boiling point. This allows the geothermal energy generation system 100 to continue operating without requiring structural changes such as adjusting the depth of the lateral sections to obtain the necessary heat.

[0108] By locating the flow of the working fluid 200 downward within a fully cased underground well loop 108 and upward from the fully cased underground well loop 108 through a single opening 110A along a single common well segment 118, the geothermal energy generation system 100 can occupy a smaller footprint, both underground and above ground, compared to other prior art systems. A smaller footprint can potentially reduce capital and operating costs. For example, U.S. Patent Application Publication 2011 / 0048005 describes two vertical wells with a single horizontal pipeline underground and two wellheads above ground: an injection wellhead and a production wellhead. This results in the injection and production wellheads being significantly farther apart from each other and therefore occupying a larger footprint than the embodiments described below. A larger footprint can lead to inefficient heat transfer and higher construction costs. Furthermore, prior art systems with two vertical wells and two wellheads require additional drilling and foundation work. For example, at a second vertical wellhead and a second wellhead, a second surface casing may be required to prevent leakage of working fluid into the environment adjacent to the second wellhead. Additional drilling and construction of additional surface casings represent additional capital costs.

[0109] Referring to Figures 1 and 2, one embodiment of the geothermal energy generation system 100 is shown. The main components of the geothermal energy generation system 100 include a fully cased underground well loop 108, more specifically a common well segment 118, the lower part 154 of the insulated injection pipe 114, the injection well 112, a first upper lateral section 116, a multi-branch connector 120 (also referred herein as a cross-connect splitter 120 or multi-branch joint 120), a second lower lateral section 124, a production well 128, and an insulated production pipe 166. The geothermal energy generation system 100 further includes a pump 104 and a turbine system 132 fluidly connected to the fully cased underground well loop 108. More specifically, the pump 104 is connected to the upper part 142 of the insulated injection pipe 114 and the injection well 112, and the turbine system 132 is connected to the common well segment 118 and the production well 128. The cooler 136 is fluidly connected between the turbine system 132 and the pump 104, closing off the circuit for a single heat exchange loop.

[0110] As shown in Figure 1, the additional well 140 is located adjacent to the fully cased underground well loop 108. This well 140 (also referred to herein as the connecting well 140, access well 140, or sacrificial well 140) is drilled to assist in the construction of the fully cased underground well loop 108 and does not contribute to the normal operation of the geothermal energy generation system 100. Well 140 will be further described below in relation to the construction of the geothermal energy generation system 100.

[0111] As shown in Figure 1, the flow direction of the liquid working fluid 204 is indicated by a solid arrow, and the flow direction of the gaseous working fluid 208 is indicated by a dashed arrow. Further details regarding the operation and phase changes of the working fluid 200 are described below.

[0112] The fully cased underground well loop 108 is located beneath the surrounding rock layer 320, but there is an access point to the fully cased underground well loop 108 located above the surface 316, more specifically, an opening 110A located at the upper end 180 of the common well segment 108 of the well assembly 110. The opening 110A is configured to serve as an inlet and outlet point above the surface 316 for the working fluid 204. More specifically, the inlet point for the flow of liquid working fluid 204 underground through the insulated injection pipe 114 toward the injection well 112, and the outlet point for the flow of gaseous working fluid 208 toward the surface from the production well 128, the insulated production pipe 166, and the common well segment 118 are located at the same location in the opening 110A. The opening 110A is enclosed by a surface casing 144. The surface casing 144 is provided to isolate the upper end 180 of the common well segment 118 from freshwater groundwater and to prevent the outflow or movement of the working fluid 200 into the groundwater and / or the environment. Details relating to the structure of the surface casing 144 are provided below. It will be noted to those skilled in the art that the reference to the rock formation 320 is not limited to rock and may include any subsurface formation or combination of formations.

[0113] The common well segment 118 places the flow of liquid working fluid 204 from the surface through the lower part 154 of the adiabatic injection pipe 114 to the injection well 112 in the same location as the flow of gaseous working fluid 208 from the production well 128 and the adiabatic production pipe 166 to the surface. The gaseous working fluid 208 from the production well surrounds the lower part 154 of the adiabatic injection pipe 114 through which the liquid working fluid 204 flows, but the liquid working fluid 204 and the gaseous working fluid 208 do not mix and are fluidly isolated from each other along the length of the common well segment 118. By providing the common well segment 118 and a single opening 110A to the surface, the geothermal energy generation system 100 can occupy a smaller area on the surface 316 than other systems with separate, spaced-out injection and production wells accessible from the surface. In a preferred embodiment, the size of the installation area of ​​the geothermal energy generation system 100 on the surface is 30,100 m². 2 That is the case.

[0114] Furthermore, the use of the common well segment 118 can achieve labor and construction cost savings. Compared to other systems with spaced injection and production wells accessible from the surface for each closed loop, only a single well opening needs to be drilled, and furthermore, only a single surface casing needs to be installed. In addition, the use of the common well segment 118 reduces environmental impact on the area; specifically, having the common well segment 118 instead of injection and production wells at the surface means there is only a single opening at the surface, minimizing the environmental impact at the surface. Furthermore, carbon emissions are also reduced by using the common well segment 118.

[0115] Having a common well segment 118 allows for a greater number of fully cased underground well loops 108 within a given area than other systems. More specifically, the density of fully cased underground well loops 108, and therefore the density of geothermal energy generation systems 100 within a given area, may be greater than the density of other systems. When constructing a given number of geothermal energy generation systems 100, the surface footprint of multiple geothermal energy generation systems 100 is smaller or more compact than the surface footprint of constructing the same number of conventional systems. Furthermore, geothermal energy generation systems using a common well segment tend to use fewer above-ground components compared to conventional systems. More specifically, there is one fewer above-ground component because there is a single opening 110A, unlike two well heads, an inlet and an outlet. The arrangement and configuration of the geothermal energy generation systems 100 and fully cased underground well loops 108 will be described further below.

[0116] The entire section of the piping, wells, and fully cased underground well loop 108 that is in physical contact with the rock layer 320 is lined with cement 152 and cased with steel 156. In this embodiment, the steel pipes are cemented in place within the wells of the common well segment 118, the injection well 112, and the production well 128. Furthermore, the steel pipes are also cemented in place as part of both the upper lateral section 116 and the lower lateral section 124 as part of the multi-branch connector 120 and any connecting pieces between the components.

[0117] In this embodiment, as shown in Figure 1, the insulated injection pipe 114 includes a first upper part 142 of the insulated injection pipe 114 above ground, which is fluidly connected to the pump 104, and a second lower part 154 of the insulated injection pipe 114 below ground, which extends parallel to the central axis of the common well segment 118 and is not in physical contact with it. More specifically, the insulated injection pipe 114 is located in the same place as the common well segment 118, and the insulated injection pipe 114 and the common well segment 118 occupy the same space simultaneously. The insulated injection pipe 114 may be located concentrically with the common well segment 118, and a portion of the insulated injection pipe 114 extends along the central axis of the common well segment 118. In other embodiments, the insulated injection pipe 114 may be located eccentrically with the common well segment 118, and a portion of the insulated injection pipe extends parallel to, but not precisely along, the central axis of the common well segment 118. Those skilled in the art will recognize various potential arrangements of the insulated injection pipe 114, which is located in the same location as the common well segment 118. The insulated injection pipe 114 may be a steel pipe 158 coated with a non-thermal-conductive compound 162. The non-thermal-conductive compound 162 (also referred to herein as the non-thermal-conductive layer 162) minimizes the amount of heat transferred between the liquid working fluid 204 flowing toward the injection well 112 and the gaseous working fluid returning from the production well 128 to the surface 316. Examples of the non-thermal-conductive compound 162 surrounding the steep pipe 158 include, but are not limited to, insulating spray foam. In other embodiments, those skilled in the art will recall that the insulated injection pipe 114 may be made of a material other than the steel pipe 158. Furthermore, those skilled in the art will recognize various available sortings and arrangements of materials for both the material of the insulated injection pipe 114 and the non-thermal-conductive layer 162. Those skilled in the art will also recognize that a single or multiple material may be used in the insulated injection pipe 114 to physically and thermally isolate the liquid working fluid 204 flowing toward the injection well 112 from the gaseous working fluid 208 returning to the surface from the production well 128.

[0118] In an alternative embodiment (not shown), the lower portion 154 of the insulated injection pipe 114 may extend along the perimeter of the common well segment 118. The lower portion 154 of the insulated injection pipe 114 may also be in contact with the wall of the common well segment 118 as it extends along the perimeter of the common well segment 118. Those skilled in the art will recognize that various configurations and arrangements of the lower portion 154 of the insulated injection pipe 114 within the common well segment 118 are possible.

[0119] To ensure there are no leaks, the entire full-casing underground well loop 108 is pressure-tested. The pressure test can be defined as a hydraulic test in which the continuously joined steel casing 156 is subjected to a minimum underground pressure related to the maximum pressure that the full-casing underground well loop 108 may experience. The maximum pressure that the full-casing underground well loop 108 may experience may be at a point along the full-casing underground well loop 108 with the greatest depth, and is likely to be along the lower lateral section 124. In certain embodiments, the following formula can be used to determine the total underground pressure for the pressure test.

[0120] Surface pressure + hydrostatic pressure

[0121] Here, hydrostatic pressure can be calculated as (maximum depth × specific gravity of water).

[0122] For example, if the deepest point along the fully cased underground well loop 108 is along the lower lateral section 124 at a depth of 2500m, and the pressure applied to the surface is 2MPa, then the specific gravity of water is 10kPa / m, and the total underground pressure can be calculated by adding the surface pressure and hydrostatic pressure, specifically in this example as 2MPa + (2500m × 10kPa / m) = 21MPa.

[0123] In cases of leaks caused by high pressure, the pressure test is performed using water, and the leaked water does not cause contamination of the surrounding environment. If the specific gravity of water is greater than the specific gravity of the working fluid 200, the above formula using the hydrostatic pressure of water may be used for the working fluid 200. For example, since the specific gravity of propane is less than that of water, the above formula provides a pressure test higher than what is required for propane as the working fluid 200, ensuring the safe operation of the fully cased underground well loop 108. Those skilled in the art will recognize that if the working fluid 200 has a higher specific gravity than water, the above formula provides the specific gravity of the working fluid 200, and this can then be compensated for by pressure testing the fully cased underground well loop 108 with water accordingly. Furthermore, in certain embodiments, the total underground pressure calculated for the above pressure test can be increased to provide a safety factor, and therefore, for safety reasons, the fully cased underground well loop 108 is tested at a pressure higher than the operating limit. The pressures to which the fully cased underground well loop 108 is constructed and pressure-tested to withstand are pressures not seen in conventional systems for generating energy from geothermal sources. This is due to the fact that the working pressure of the working fluid in conventional systems tends to be much lower than the working pressure of the working fluid 200 flowing through the fully cased underground well loop 108.

[0124] A pressure-tested fully cased underground well loop 108 can receive and transport a working fluid 200 pressurized at 7 MPa to 31 MPa. In embodiments where the working fluid 200 is pentane, the pressure-tested fully cased underground well loop 108 can receive and transport a working fluid 200 at 7 MPa to 22 MPa. In preferred embodiments where the working fluid 200 is propane, the pressure-tested fully cased underground well loop 108 can receive and transport a propane working fluid 200 at 7 MPa to 20 MPa.

[0125] During operation, the fully cased underground well loop 108 can withstand a pressure of at least 7 MPa. In other embodiments, pressure testing of the fully cased underground well loop 108 may include pressure tests up to 31 MPa and may be designed to rupture or fail at up to 39 MPa.

[0126] Cement 152 is used to structurally fix the steel 156 casing to the surrounding rock layer 320, but in alternative embodiments, cement 152 may be mixed with other substances, such as the addition of hematite to adjust the thermal conductivity of cement 152. In this embodiment, cement 152 and steel 156 are used, but it will be recognizable to those skilled in the art that any other material could be used as a barrier, as long as it physically isolates the working fluid 200 from the external environment / rock layer 320, can withstand the pressure requirements from the working fluid 200 which undergoes both expansion and contraction while undergoing phase changes, and can conduct heat through the material.

[0127] The common well segment 118 extends downward from the opening 110A at the surface 316 to a predetermined depth underground, to a connection point 122 where it branches into the injection well 112 and the production well 128. The predetermined depth can be determined on a site-by-site basis depending on the geothermal gradient, rock thermal properties, geology, and geological composition of the area under consideration. In this embodiment, the common well segment 118 is vertical, and the depth and length of the common well segment are the same. However, in other embodiments, the common well segment 118 may be inclined. Therefore, the length of the common well segment 118 can be determined by the predetermined depth of the common well segment 118 and the gradient or angle of the common well segment 118. Alternatively, the depth or gradient of the common well segment 118 can be based on a predetermined length, and the length of the common well segment 118 can be determined based on the type of working fluid 200, the amount of potential heat transfer between the liquid working fluid 204 in the lower part 154 of the adiabatic injection pipe 114 and the gaseous working fluid 208 flowing through the annular cylindrical space surrounding the lower part 154 of the adiabatic injection pipe 114 along the common well segment 118. Having a single well with a single opening 110A to the surface 316 saves construction costs compared to other systems with multiple wells, but it will be understood that the longer the common well segment 118, the greater the heat transfer between the liquid working fluid 204 and the gaseous working fluid 208. In a preferred embodiment, the common well segment 118 is vertical, and the depth and length of the common well segment 118 are approximately 650 meters. Those skilled in the art will also recognize that in other embodiments the common well segment 118 may extend at an angle, or may be a combination of any number of vertical, offset, or horizontal segments, in which case length, as well as depth, must also be considered with respect to heat transfer.

[0128] The lower portion 154 of the insulated injection pipe 114 extends parallel to the central axis of the common well segment 118 and is fixed parallel to the central axis by the insulated injection pipe 114, which is fixed between the pump 104 above the surface 316 and the connection point 122 (also referred to herein as the branch point 122) between the injection well 112 and the common well segment, allowing the flow of liquid working fluid 204 between the pump 104 above the surface 316 and the injection well 112. In this embodiment, the lower portion 154 of the insulated injection pipe 114 connects to the injection well 112 at the connection point 122 using a curved connecting piece 134. The lower portion 154 of the insulated injection pipe 114 extends along the entire length of the common well segment 118. The insulated injection pipe 114 is not fixed with cement but undergoes the same pressure testing as the rest of the fully cased underground well loop 108.

[0129] The injection well 122 includes a first inclined section 126 and a second vertical section 138. At connection point 122, the injection well 112 branches off from the common well segment 118 along the inclined section 126 and extends with a downward inclination angle over a predetermined length. The downward inclination angle of the inclined section 126 is between 5 and 20 degrees relative to the plane of the ground surface 316, and may have an inclination rate of 6 degrees / 30 m. The downward inclination angle may be determined based on the flow rate of the working fluid 204. It will be understood that the steeper the downward inclination angle, the faster the flow velocity of the working fluid 204. In a preferred embodiment, the inclined section 126 is inclined downward with an inclination rate of 6 degrees / 30 m. The predetermined length of the inclined section 126 also depends on the downward inclination angle of the inclined section 126 and the distance 130 between the vertical section 138 and the production well 128. The spacing 130 is measured and defined as the closest point along the lateral plane between the central axis of the vertical section 138 and the production well 128. The spacing 130 is determined by the distance required to ensure thermal separation between the vertical section 138 of the injection well 112 and the production well 128, so as to ensure that thermal interference between the gaseous working fluid 208 in the production well 128 and the liquid working fluid 204 in the vertical section 138 of the injection well 112 is minimized. The spacing 130 may be influenced by the geothermal gradient, rock thermal properties, geology, and geological composition of the area of ​​interest or rock mass 320 surrounding the injection well 112 and the production well 128. In a preferred embodiment, the spacing 130 is 80 m. Furthermore, in a preferred embodiment, the inclined section 126 has a steel casing 156 with an inner diameter of approximately 139 mm. However, in other embodiments, the section 126 may be of a different size. Those skilled in the art will recognize the possibility of using different configurations of the downward inclination angle, the predetermined distance, and the spacing 130 of the inclined sections 126, based on the factors described above.

[0130] The vertical section 138 of the injection well 112 extends vertically downward by a predetermined distance (or depth) from the end of the inclined section 126. The predetermined distance (or depth) can be determined on a site-by-site basis depending on the geothermal gradient, rock thermal properties, geology, and geological composition of the area of ​​interest. The geothermal gradient and rock thermal properties are variables to be considered in determining the depth and residence time at said depth to induce a phase change in the working fluid 200. The depth of the vertical section 138 of the injection well 112 is selected to achieve a high rock temperature while minimizing drilling costs that increase with many factors, including the depth and geological composition of the rock layer 320. In this embodiment, the vertical section 138 is joined to the upper lateral section 116 at its lower end 196 by a curved connecting piece 160. However, the upper lateral section 116 may be connected to the vertical section 138 and extend away from the vertical section 138 of the injection well 112 at any point along the vertical section 138. The vertical section 138 can extend over a distance of approximately 0m to 2850m. More specifically, the vertical section 138 can begin at a depth of approximately 650m and extend to a depth of approximately 3500m. In a preferred embodiment, the vertical section 138 may have a production steel casing 156 with an inner diameter of approximately 139mm based on a preferred working fluid temperature of 140°C to be achieved. However, the vertical section 138 can be of different sizes (i.e., drilled to different depths, whether deeper or shallower, and having different diameters, whether larger or smaller) if it needs to be adapted to a particular application. In the embodiment shown in Figure 1, the first section 138 is shown extending vertically downward into the ground. Naturally, this does not have to be the case in all embodiments. In some embodiments, the first section can extend downward into the ground at an angle from the vertical.

[0131] In a preferred embodiment, the upper lateral section 116 can be seen as perpendicular to the vertical section 138 of the injection well 112, extending laterally from there toward the XC connector 120. Furthermore, the upper lateral section 116 has a production steel casing 156 with a length of approximately 2000m to 4000m and an inner diameter of approximately 139mm. In other embodiments, the upper lateral section 116 does not need to be positioned laterally to the vertical section 138 of the injection well 112, but can extend laterally away from the vertical section 138 of the injection well 112 at an angle. It can also be of different sizes.

[0132] A multi-branch connector 120 joins the upper lateral section 116 to the lower lateral section 124. The multi-branch connector 120 may include an XC splitter or other equivalent connecting device, which may be connected between the upper lateral section 116 and the lower lateral section 124 to ensure that the fully cased underground well loop 108 is pressure-tested and capable of operating under pressure. For example, the SAGD (Steam Assisted Gravity Drainage) XC splitter multi-lateral system manufactured by Baker Hughes. The multi-branch connector allows for complete mechanical and hydraulic isolation support of the joining area with re-entry capabilities. The multi-branch connector is designed to accommodate re-entry coupling in SAGD applications. The multi-branch connector 120 is well known in the oil and gas industry, and those skilled in the art will recognize the various types of multi-branch connectors 120 available.

[0133] In this embodiment, the lower lateral section 124 extends laterally away from the multi-branch connector 120 to join the lower end 198 of the production well 128 via a curved connecting piece 164. However, the lower lateral section 124 can be joined to the production well 128 at any position along the production well 128. The lower lateral section 124 is positioned perpendicular to the production well 128. Furthermore, the lower lateral section 124 has a production steel casing 156 with a length of approximately 2000m to 4000m and an inner diameter of approximately 139mm. In other embodiments, the lower lateral section 124 does not need to be positioned laterally to the production well 128, but can extend laterally toward the production well 128 at an angle. It can also be of different sizes.

[0134] In an embodiment where the upper lateral section 116 is positioned laterally relative to the vertical section 138 of the injection well 112 and the lower lateral section 124 is positioned laterally relative to the production well 128, both lateral sections 116 and 124 may lie on the same vertical plane. However, it will be recognizable to those skilled in the art that in an alternative configuration, the lateral sections 116 and 124 may be offset from each other in the vertical plane.

[0135] In this embodiment, the length of the upper lateral section 116 is shorter than the length of the lower lateral section 124. The lengths of the lower lateral section 116 and the upper lateral section 124 are selected based on the amount of time the working fluid 200 needs to remain underground in contact with the heat-generating rock layer 320 (i.e., residence time) and the flow rate of the working fluid 200. For example, if heating takes a long time for the working fluid 200 to undergo a phase change, whether due to the thermal conductivity characteristics of the surrounding rock layer 320, the well casing and the backing of the lateral sections 116 and 124, or due to the characteristics of the type of working fluid 200 being used, both lateral sections 116 and 124 may need to be longer to accommodate the time for which the working fluid 200 needs to be heated to induce a phase change. The flow rate is another variable that needs to be considered, and since a lower flow rate means a lower distance traveled over time, the lengths of the lateral sections 116 and 124 may be further adjusted.

[0136] In a preferred embodiment, the lower lateral section 124 extends deeper than the upper lateral section 116. Having two lateral sections 116 and 124 at different depths can reduce thermal interference between wells 112 and 128, thereby increasing heat absorption from the surrounding rock layer 320. However, the fully cased underground well loop 108 is not limited to this configuration. In an alternative embodiment (not shown), the lateral section returning to the production well 128 may be located shallower than the lateral section connected to the injection well 112. Furthermore, in an alternative embodiment (not shown), both lateral sections 116 and 124 may be at the same depth but at an angle to each other, in which case the multi-branch connector 120 connects the two lateral sections 116 and 124 from different angles. Alternatively, both lateral sections 116 and 124 may be at the same depth, or they may extend parallel to each other over a substantial portion of their length, and angled connecting pieces (not shown) may correspond to the initial branching angles from the multi-branch connector 120. In embodiments where both lateral sections 116 and 124 extend parallel to each other over a substantial length, the spacing between lateral sections 116 and 124 should be considered to ensure that there is heat absorption from the surrounding rock layer 320 and no thermal interference or heat transfer between lateral sections 116 and 124. Those skilled in the art will recognize the various potential configurations and lengths available for both lateral sections 116 and 124, as well as the various potential configurations for the entire full-casing underground well loop 108.

[0137] In the embodiment shown in Figure 1, the production well 128 is vertical and aligned with the same vertical trajectory of the common well segment 118. However, the configuration of the production well 128 is not limited to being vertical. The production well 128 may be inclined, or it may be divided into inclined and vertical sections, similar to the injection well 112 (not shown). In embodiments in which the production well 128 includes inclined and vertical sections, the spacing 130 can be measured between the vertical section 138 of the injection well 112 and the vertical section of the production well 128. Those skilled in the art will recognize the various potential configurations of the production well 128.

[0138] In this embodiment, the production well 128 is fluidly connected to an insulated production pipe 166 that starts along any portion of the production well 128 and rises to a depth directly above the connection point 122, where it can be fluidly connected to the common well segment 118. The insulated production pipe 166 may be held in place by an isolation packer 254 at its lower end along the production well 128, or by a geothermal isolation joint 170 directly above the connection point 122. By adding the insulated production pipe 166 fluidly connected to the common well segment 118 above the connection point 122, leakage of the gaseous working fluid 208 into the inclined section 126 of the injection well 112 is prevented. The isolation packer 254 along the production well 128 further prevents the gaseous working fluid 208 from leaking from below into the space around the connection point 122 and further guides the gaseous working fluid 208 from the production well 128 into the insulated production pipe 166. The geothermal isolation joint 170 is located close to above the connection point 122 and includes a penetration for the insulated injection pipe 114 and the insulated production pipe 166. The geothermal isolation joint 170 further forms a seal between the insulated injection pipe 114, the insulated production pipe 116, and the wall of the common well segment 118, preventing the gaseous working fluid 208 discharged from the insulated production pipe 166 into the annular cylindrical space surrounding the insulated injection pipe 114 in the common well segment 118 from flowing back downward into the space surrounding the connection point 122. The combination of the isolation packer 254 at the intersection between the inclined section 126 and the common well segment 108, the geothermal isolation joint 170, and the isolation packer 298 effectively forms and defines a seal space surrounding the connection point 122, preventing the liquid working fluid 204 from flowing down into the production well 128 or the working fluid 208 from flowing down into the injection well 112. Furthermore, the insulated injection pipe 114, the inclined section 126, and the curved connecting piece 134 are sealed and pressure-tested to ensure there is no leakage of the liquid working fluid 204 into the surrounding common well segment 118 or rock layer 320, but the addition of the insulated injection pipe provides an additional precaution against the gaseous working fluid 208 mixing with the liquid working fluid 204.

[0139] The insulated production pipe 166 may be made of the same material as the insulated injection pipe 114. In this embodiment, the insulated production pipe 166 may be a steel pipe 158 coated with a non-thermally conductive compound 162 to minimize the amount of heat transferred between the liquid working fluid 204 and the gaseous working fluid 208. However, those skilled in the art will recognize that, like the insulated injection pipe 114, the insulated production pipe 166 may be made of any material, combination or layer of materials that is non-thermally conductive and allows the insulated production pipe 166 to receive and withstand the pressure required for the full-casing underground well loop 108. In a preferred embodiment, the insulated production pipe 166 may extend in a length of 0m to 100m between the geothermal isolation joint 170 and the isolation packer 254. Those skilled in the art will recognize that the length of the insulated production pipe 166 is based on the distance between the geothermal isolation joint 170 and the isolation packer 254, so as to allow the flow of the liquid working fluid 208 to bypass any area that could potentially access the insulated well 112 and the milled window 266. By extending the insulated production pipe 166 over at least the length between the geothermal isolation joint 170 and the isolation packer 254, any potential opening portions are isolated and avoided.

[0140] The geothermal isolation joint 170 may also be made of a non-thermally conductive material to minimize any heat transfer between the adiabatic injection pipe 114 and the adiabatic injection pipe 166. In another alternative embodiment (not shown), the fully cased underground well loop 108 may not include the adiabatic production pipe 166, the isolation packer 254, and the geothermal isolation joint 170. The production well 128 can be fluidly connected to the common well segment 118, allowing the gaseous working fluid 208 to flow from the production well 128 along the common well segment 118 into the cylindrical annular space surrounding the adiabatic injection pipe 114. In this embodiment, the isolation packer 298 acts as a seal to prevent the gaseous working fluid 208 from mixing with the liquid working fluid 204. The isolation packer 298 further prevents the gaseous working fluid 208 from flowing into the inclined branch 126 of the injection well 112.

[0141] In yet another alternative embodiment (not shown), the common well segment 118 may also include the lower part 154 of an insulated injection pipe 114 extending along the length of the common well segment 118 to allow liquid working fluid 204 to flow downward into the injection well 112, and the lower part of another insulated pipe extending along the length of the common well segment 118 to allow gaseous working fluid 208 to flow upward from the production well 128 toward the surface. The lower part 154 of the insulated injection pipe 114 and the lower part of the insulated pipe connected to the production well may extend parallel to each other or spaced apart, allowing the spacing to act as further insulation to prevent heat transfer.

[0142] Here, those skilled in the art will recognize that the insulated production pipe can extend from anywhere along the production well 128 to the surface. Furthermore, those skilled in the art will also recognize that by arranging the insulated production pipe, the insulated injection pipe 114 may not be required, and the liquid working fluid 204 can flow toward the injection well 112 within a cylindrical annular region surrounding the lower part of the insulated production pipe within the common well segment 118. Furthermore, those skilled in the art will recognize different combinations and variations of the arrangement of the insulated pipe within the common well segment 118 and the flow of the working fluid 208, while ensuring that the flow of the liquid working fluid 200 and the flow of the gaseous working fluid 204 are thermally and physically separated from each other.

[0143] In another alternative embodiment (not shown), the flow of the working fluid 200 may differ in the fully cased underground well loop 108. Specifically, in this embodiment, the injection well 112 may be fluidly connected to a common well segment 118, and the production well 128 may be connected to a turbine system 132 via an insulated pipe, the lower part of which extends along the length of the common well segment 118. The liquid working fluid 204 can flow from the pump 104 downward along the common well segment 108 in the space surrounding the lower part of the insulated pipe, through the lower lateral section 124, through the multi-branch connector 120, and then through the upper lateral section 116. While flowing through the upper lateral section 116, the liquid working fluid 204 may undergo a phase change to a gaseous working fluid 208. The gaseous working fluid 208 can flow through the remainder of the upper lateral section 116, then through the vertical and inclined sections of the production well 128 to the surface, and then through the insulated tube to the turbine system 132, the insulated tube being similar in material and structure to the insulated injection tube 114 in the embodiment shown in Figure 1.

[0144] Furthermore, in yet another alternative embodiment (not shown), the injection well 112 may also be a single vertical well and may lack the inclined section 126 and the vertical section 138. Thus, it will be recalled by those skilled in the art that there are at least four possible configurations for the injection well 112 and production well 128 in which the common well segment 118 exists. Specifically, the injection well 112 may include the inclined section 126 and the vertical section 138 to maintain a gap 130 to ensure there is no heat transfer between the injection well 112 and the production well 128, and the production well 128 may be vertical and lack the inclined and vertical sections. Alternatively, the injection well 112 may be vertical and lack the inclined section 126 and the vertical section 138, and the production well 128 may include the inclined and vertical sections. Alternatively, each of the injection well 112 and the production well 128 may include its own inclined and vertical sections. Alternatively, both the injection well 112 and the production well 128 may have a slope or gradient along their entire length, and may not have any sloped or vertical sections, and a minimum spacing of 130 may be maintained for most of the distance between both the injection well 112 and the production well 128. Here, those skilled in the art will recognize various potential configurations for the injection well 112 and the production well 128.

[0145] Returning to the embodiment shown in Figure 1, since the lower lateral section 124 extends deeper than the upper lateral section 116, the production well 128 extends deeper into the ground than the vertical section 128 of the injection well 112. In a preferred embodiment, the production well 128 begins at a depth of 650 m at the confluence point 122 and ends at a depth of approximately 3500 m. However, the confluence point 122 may be at any depth, and therefore the production well 128 can begin and end at any depth that is reasonable considering the characteristics of the rock layer 320. The production well can be of different sizes (i.e., drilled to different depths, whether deeper or shallower, and having different diameters, whether larger or smaller) if it needs to be adapted to a particular application. As will be apparent to those skilled in the art, in the present embodiment in which the production well 128 aligns with the same vertical trajectory of the common well segment 118, the diameter of the production well 128 is the same as the diameter of the common well segment 118. However, in other embodiments where the production well 128 is not aligned with the common well segment 118, or where the production well 128 can include inclined and vertical sections, the diameter of the production well 128 may differ from the diameter of the common well segment 118.

[0146] As shown in Figures 1 and 2, a pump 104 located at the surface 316 is fluidly connected to an insulated injection pipe 114. The pump 104 is operable to circulate a working fluid 200 through the upper part 142 of the insulated injection pipe 114 and through a fully cased underground well loop 108, and to advance underground into the lower part 154 of the insulated injection pipe 114 and into the injection well 112.

[0147] Pump 104 is also configured to ensure that the liquid working fluid 204 flows through a single heat exchange loop by maintaining an appropriate flow rate of the working fluid 200. The flow rate (and corresponding residence time) is determined by the underground well loop and conducts enough thermal energy to convert the working fluid from liquid to a gas at a sufficiently high temperature. In this embodiment, the liquid working fluid 204 received by pump 104 may be in a pressure range of 500 kPag to 2000 kPag and a temperature range of 10°C to 40°C. Pump 104 is configured to increase the pressure in the range of 700 kPag to 3000 kPag and maintain a flow rate of 15 kg / sec to 25 kg / sec. In a preferred embodiment, pump 104 can supply the liquid working fluid 204 to the adiabatic injection pipe 114 of the injection well 112 at a pressure of about 1300 kPag and a temperature of about 30°C. A preferred embodiment of pump 104 is the use of a liquid pump for thermodynamic efficiency. Liquid pumps minimize parasitic energy losses in the system compared to the use of mechanical gas compressors.

[0148] In other conventional geothermal systems where the working fluid 200 comes into contact with the rock layer 320 due to the absence of a casing, or where the working fluid 200 may pick up solid foreign matter from the subsurface, the pump may need to be substantially more robust and may need to handle abrasives during operation. Furthermore, in conventional systems where the working fluid 200 is water, the pump may need to deal with the chemical properties of water that have scale-forming characteristics during operation. In contrast, in this embodiment, since the fully cased underground well loop 108 is completely sealed, cased, and pressure-tested, the working fluid 200 does not come into contact with any rock layer 320 and is physically isolated from the environment. Therefore, the working fluid 200 does not pick up any solid foreign matter and remains a clean, homogeneous fluid. This allows the pump 104 to have a long service life with minimal maintenance, thus saving procurement and operating costs and potentially allowing the use of less durable or standard pump designs.

[0149] In a preferred embodiment, pump 104 may be a positive displacement pump equipped with a variable speed drive controller. Positive displacement pump types typically have high overall thermal efficiency and can maintain a desired outlet head when paired with a variable speed drive. Types of positive displacement pumps include plunger, gear, or rotary vane pumps. However, as will be apparent to those skilled in the art, pump 104 may also be any type of pump capable of handling the aforementioned pressures and temperatures. This may include, but is not limited to, centrifugal pumps or diaphragm pumps. Those skilled in the art will recognize a variety of potential pumps that can be used based on the aforementioned pressure, flow rate, and temperature specifications as well as purchase and maintenance costs.

[0150] Furthermore, above the ground, there is a turbine system 132 fluidly connected to the opening 110A of the common well segment 118. The turbine system 132 may include a turbine (not shown) having an output shaft connected to a generator (not shown).

[0151] In this embodiment, the turbine system 132 is positioned close to the opening 110A to prevent the gaseous working fluid 208 from losing heat as it moves along the insulated tube between the opening 110A and the turbine system 132. In other embodiments, the turbine system 132 may be positioned further away from the opening 110A, although this tends to be undesirable. Although the outer tube carrying the gaseous working fluid 208 to the turbine system can be insulated, heat and pressure can still be lost, and such travel distance and time are important considerations. Those skilled in the art will be familiar with the structure, configuration and operation of the turbine system 132 and associated generators, and therefore do not need to be described herein.

[0152] During operation, the turbine system 132 receives a gaseous working fluid 208 from the opening 110A of the common well segment 118, and the gaseous working fluid 208 drives a turbine connected to a shaft. The mechanical energy generated by the rotation of the turbine is transmitted to a generator, which can convert the mechanical energy into commercially marketable electricity. The electricity may then be sent to a utility-owned power grid for further distribution. In this embodiment, the turbine system 132 can generate 0.5 MW to 2 MW of electricity. In a preferred embodiment, the turbine system 132 can generate about 1 MW of electricity.

[0153] Alternatively, if power is not required by the power grid, power may be supplied to a battery, other local loads, or briefly wasted via an electrical resistance load device. By using a load device to waste power, equipment can be operated without a live connection to the power lines. This can be done for equipment testing and for short-term operational abnormalities (not shown).

[0154] In other embodiments, the turbine system 132 may include a turbine expander, a piston expander, or a scroll expander. In a preferred embodiment, a turbine expander is used, which may be radial or axial, with a radial turbine expander connected to one end of the shaft and a generator connected to the other end of the shaft. The expander output shaft may be connected to the generator directly or via a reduction gearbox. The reduction gearbox can match the high-speed (rpm) turbine wheel to the desired operating speed of the generator. The type of expander and generator determines the need for and type of gearbox. In alternative embodiments, the turbine expander may also be a positive displacement machine such as a scroll, screw, or vane expander. The preferred output of the geothermal energy generation system 100 is targeted to exceed 1 MW generated by each expander, and since positive displacement expanders are significantly more expensive for the target power output, a high-speed and compact turbo expander is a preferred embodiment.

[0155] In another embodiment, multiple expanders can be used to maximize the power generated. Using multiple expanders is beneficial when limiting the size of expanders for constructability or turndown efficiency, or when attempting to expand (flash) a particular working fluid 200 in stages, where the first stage of flashing occurs in the primary expander, but the working fluid retains energy and can be flashed again at a lower pressure or in parallel with the first stage.

[0156] If a turbo expander is included, the gaseous working fluid 208 can expand as it passes through a cone-shaped radial turbine, and thus the pressure and temperature of the gaseous working fluid 208 can be reduced while driving the turbine. Similar to the previous embodiment of the turbine system 132, the rotation of the radial turbine generates mechanical energy that is transmitted to a generator, where it is converted into commercially marketable electricity. The voltage from the generator can be increased using a power boost transformer to meet the requirements of third-party transmission lines for selling electricity to the desired market.

[0157] 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 induce the received input gaseous working fluid 208 to partially change its state to a mixture of gas and liquid.

[0158] The cooler 136 (also called the condenser 136) is positioned between the turbine system 132 and the pump 104 and is fluidly connected to them. The cooler 136 is configured to receive the low-pressure gaseous working fluid 208 output from the turbine system 132 and to cool the low-pressure gaseous working fluid 208 to a liquid working fluid 204 using a heat exchanger or mechanical chiller (not shown) that is cooled by forced air. In embodiments where the working fluid 200 coming out of the turbine system 132 and received by the cooler 136 is in a mixture of both gaseous and liquid states, the amount of energy used by the cooler 136 can be reduced because less work is required to cool the working fluid 200 to a liquid state. Alternatively, the residence time of the working fluid 200 in the cooler 136 can also be reduced. Those skilled in the art will recognize that the specifications of the cooler 136 used may also depend on the specifications of the working fluid 200, the type of turbine system 132, and the target final temperature and pressure of the liquid working fluid 204 after it leaves the cooler 136.

[0159] Since the cooler 136 is fluidly connected to the pump 104, the resulting liquid working fluid 204 output from the cooler 136 is returned to the pump 104 and sent again through the full-casing underground well loop 108. Preferably, the cooler 136 is a finned tube type with ambient air by forced draft used as a coolant. This type of condensing cooler 136 is effective and relatively inexpensive. However, other embodiments can be used, such as brazed aluminum plate type, tube type, or other heat exchangers having a working fluid cooled by a separate coolant.

[0160] The connecting pieces 168, 172, and 176 serve as additional pieces to complete a single heat exchange loop above the ground surface 316. Specifically, connecting piece 168 serves as a connector for fluidizing the opening 110A of the common well segment 118 to the inlet of the turbine system 132. Similarly, connecting piece 172 fluidizing the outlet of the turbine system 132 to the inlet of the cooler 136. Furthermore, connecting piece 176 serves as a connector for fluidizing the outlet of the cooler 136 to the inlet of the pump 104.

[0161] As described above, the fully cased underground well loop 108 is fully lined and cased to physically isolate the working fluid 200 from the rock layer 320 and the environment. In this embodiment, the connecting pieces 168, 172, and 176 may be steel pipes, but in an alternative embodiment, the connecting pieces 168, 172, and 176 may be made of other materials that do not leak and can withstand pressure and temperature changes above ground. In a preferred embodiment, the connecting piece 168 between the outlet of the opening 110A and the turbine system 132 may also be insulated to prevent heat loss before the gaseous working fluid 208 reaches the turbine system 132. However, in an alternative embodiment, all surface connecting pieces 168, 172, and 176 may also be insulated to reduce heat loss that could lead to parasitic losses. Furthermore, a single heat exchange loop of the geothermal energy generation system 100 that may include the connecting pieces 168, 172, and 176 is pressure tested to ensure that they do not leak when transporting the working fluid 200 while the working fluid 200 is subjected to pressure changes. Those skilled in the art will recall that the connecting pieces 168, 172, and 176 may be of any shape or size depending on the location and specifications of the working fluid 200, the opening 110A, the turbine system 132, the cooler 136, and the pump 104. Those skilled in the art will also recall that in embodiments where the components are combined into a single unit such as the cooler 136 and the pump 104, certain connecting pieces may not be necessary and can be omitted.

[0162] As shown in Figure 2, the geothermal energy generation system 100 may also include a storage container 188 (also referred to herein as a storage tank 188) for holding excess liquid working fluid 204 and providing a sufficient and consistent mass flow rate to the pump 104. Although not shown, other components such as valves, heat exchangers, and other equipment may be used to optimize the geothermal energy generation system 100. In an alternative embodiment, a filter or filter separator may also be added to the opening 110A upstream of the turbine system 132, however, in this embodiment, as with a single working fluid 200 in a single heat exchange loop, there is little to no solid foreign matter expected during normal operation, so a filter is not essential if all piping is clean enough to remove manufacturing lubricants, mill scale, dirt, and other contaminants before commissioning the turbine system 132.

[0163] Figure 3 shows a geothermal energy generation system 100A, which is an alternative embodiment of the embodiments shown in Figures 1 and 2. For convenience, similar elements or structures shown in Figures 2 and 3 are identified by the same reference numerals. System 100A is essentially similar to system 100, except that a reheater 184 (also referred to herein as a heat exchanger 184) is provided in geothermal energy generation system 100A. The reheater 184 is located and connected between the turbine system 132 and the cooler 136, and between the pump 104 and the adiabatic injection pipe 114. The reheater 184 is configured to minimize the cooling load on the cooler 136 and to preheat the liquid working fluid 204 before it enters the adiabatic injection pipe 114, which is done by cross-exchanging heat from the warm gaseous working fluid 208 at the outlet of the low-pressure turbine system 132 with the cooler liquid working fluid 204 from the outlet of the pump 104. As the warm low-pressure gaseous working fluid 208 leaves the turbine system 132 and moves through the reconverter 184, it can transfer its heat to the cold liquid working fluid 204, which in turn moves through the reconverter 184 from the outlet of the pump 104 to the adiabatic injection pipe 114. Thermal energy is saved and reused by transferring heat from the low-pressure gaseous working fluid 208 leaving the turbine system 132 to the cold liquid working fluid 204 moving towards the adiabatic injection pipe 114. The low-pressure gaseous working fluid 208 leaving the turbine system 132 moves towards the cooler 136 to condense and induce a phase change, and thus the time and energy required for the cooler 136 to condense the gaseous working fluid 208 into a liquid is reduced by transferring thermal energy from the low-pressure gaseous working fluid 208 before the cooler 136. Furthermore, the liquid working fluid 204, which flows through the insulated injection pipe 114, flows underground to be heated, and therefore, by preheating the liquid working fluid 204, the required underground residence time can be reduced, and thus it may be possible to shorten the lateral sections 116 and 124, or to make the lateral sections 116 and 124 shallower. Those skilled in the art will recognize the possibility of a reconverter 184 and the potential configuration of a geothermal energy generation system with a reconverter 184.

[0164] In alternative embodiments, the geothermal energy generation system 100 may be used for purposes other than power generation. For example, the work generated by the geothermal energy generation system 100 may be used to perform other mechanical work. Alternatively, the work generated by the geothermal energy generation system 100 may be used for hydrogen production.

[0165] Referring to Figure 4, a flowchart is shown illustrating the steps of a method 400 for operating a geothermal energy generation system 100 according to one embodiment of the present invention. The operation of the geothermal energy generation system 100 is performed after the system has been primed and started up, and follows a Rankine cycle (preferably an organic Rankine cycle in which an organic carbon-based working fluid is used). An example of priming the geothermal energy generation system 100 includes slowly circulating the working fluid 200 through the adiabatic injection pipe 114 and injection well 112, and allowing any residual liquid or gas (from either the construction process of the geothermal energy generation system 100 or a previous operation) to be discharged into a storage container for collection. Once all residual liquid or gas has been removed, the working fluid 200 can continue to circulate through the geothermal energy generation system 100 as part of its normal operation. As can be seen, method 400 is a loop. For ease of understanding, the process can be described as starting in step 405 and ending in step 440 before starting the process again in step 405.

[0166] As described above, the geothermal energy generation system 100 is a single heat exchange loop having a fully cased underground well loop 108. Once the fully cased underground well loop 108 is fully cased and pressure tested, the working fluid 200 can be a variety of liquids, gases, or plasmas. In an alternative embodiment, the working fluid 200 may be a commercially available carbon-based environmentally friendly refrigerant, or a mixture of refrigerants such as 90% propane with 10% mole fraction ethane. Alternatively, the working fluid 200 may be either a composition of hydrocarbons, carbon dioxide, or ammonia (heterogeneous working fluid 200) or a single entity (homogeneous working fluid 200). In a preferred embodiment where the geothermal energy generation system 100 is an organic Rankine cycle, the working fluid 200 may be propane. With propane, the maximum temperature achievable by the propane working fluid 200 is about 140°C at a depth of 2000m and a temperature of about 160°C in the rock layer 320. Furthermore, the propane working fluid 200 can condense into a liquid working fluid 208 on hot summer days without substantially cooling using ambient air forced across the finned tube cooler 136. While propane is the selected working fluid 200, other organic substances (carbon-based), such as hydrocarbons or hydrocarbon blends, may be used. Using hydrocarbon blends, the return pressure of the working fluid 200 can be maximized. Hydrocarbon blends allow the working fluid 200 to be tailored to specific depth and temperature conditions. For example, adding ethane to a predominantly propane working fluid 200 allows the well to flash earlier at a particular rock layer 320 temperature. Early flashing allows for increased flow of the working fluid 200, and therefore increased power generation. Another example is blending hydrocarbons with butane to increase the heat-carrying capacity of the working fluid. By blending heavier hydrocarbons, the flash point / vaporization point along the fully cased underground well loop 108 can be adjusted according to the temperature of the surrounding rock layer 320.For example, the vaporization point can be adjusted along the upper lateral section 124 or production well 128 based on the temperature of the surrounding rock layer 320 to maximize the velocity of the working fluid 200 and minimize friction of the working fluid 200 along the remainder of the pipe before it exits the fully cased underground well loop 108. Those skilled in the art will recognize the potential combinations of the temperature of the rock layer 320 and various variations of the hydrocarbon blend to adjust the location of the vaporization point along the fully cased underground well loop 108. The working fluid 200 may be water, but it is preferably one of the fluids described above because the substances described above have lower boiling points and shorter underground residence times than water. Furthermore, the fluids described above can have advantageous heat capacities and different phase transition points, enabling a more efficient system and allowing for shorter underground residence times within the fully cased underground well loop 108.

[0167] The following steps illustrate an embodiment in which the working fluid 200 is propane. In step 405, the propane liquid working fluid 204 is transported underground by causing it to flow down the adiabatic injection pipe 114 through the injection well 112 along the upper lateral section 116, the multi-branch connector 120 and the lower lateral section 124. The liquid working fluid 204 is pumped using a pump 104 to reach the adiabatic injection pipe 114 and the injection well 112. In practice, the working fluid 200 is circulated through a single heat exchange loop of the complete casing using the pump 104. To ensure proper circulation, the pump 104 increases the pressure of the liquid working fluid 204 from 1080 kPag to 1300 kPag and supplies it to the adiabatic injection pipe 114. In this embodiment, where the working fluid 200 is propane after leaving the pump 104 and before being received by the adiabatic injection pipe 114, the liquid working fluid 204 can have an approximate temperature range of about 10°C to about 40°C, a preferred temperature of about 20°C, and an approximate pressure range of about 1000kPag to about 2000kPag, a preferred pressure of about 1300kPag. After leaving the pump 104, the liquid working fluid 204 flows downward through the adiabatic injection pipe 114 and then flows along the injection well 112.

[0168] When the working fluid 204 reaches the curved connector 160, the direction of flow of the working fluid 204 changes from vertical to lateral, and then continues along the upper lateral section 116. The working fluid 204 then reaches the multi-branch connector 120, where it changes direction and flows into the lower lateral section 124, continuing to flow to the curved connector 164 adjacent to the lower end 198 of the production well 128.

[0169] Towards the lower end 196 of the injection well 112, and at the depth where the upper lateral section 116, the multi-branch connector 120, and the lower lateral section 124 are located, the surrounding environment and the rock layer 320 naturally conduct heat from the surrounding rock layer 320. As the working fluid 204 flows downward along the injection well 112, heat is transferred to the working fluid 204 from the surrounding environment or the rock layer 320 when the working fluid 204 reaches a certain depth where the temperature of the rock layer 320 exceeds the temperature of the working fluid 204 (step 405). Heat transfer may occur while the working fluid 204 is still flowing downward through the injection well 112, and may continue to occur while the working fluid 204 is flowing through the connecting piece 160 and the upper lateral section 116. This heat may be conductively transferred from the surrounding environment to the working fluid 204 through the cement backing 152 and the steel casing 156. The depth threshold at which the working fluid 204 begins to absorb heat and thus raises its temperature is the point where the ambient temperature is higher than the temperature of the working fluid 204. This depth threshold depends on the geothermal gradient and working fluid reinjection temperature at the site. Heat continues to be transferred to the working fluid 204 as it flows through the multi-branch connector 120 and the lower lateral section 124, thereby raising the temperature of the working fluid 204 as it flows through the components.

[0170] Furthermore, as the working fluid 204 flows downward through the injection well 112, the pressure exerted on the working fluid 204 increases as a result of the hydrostatic pressure head (in step 415). As the working fluid 204 reaches the connecting piece 160 and the upper lateral section 116, the pressure of the working fluid 204 continues to increase as the fluid absorbs thermal energy. Although there may be a slight decrease in pressure due to flow friction losses in the well, the pressure of the working fluid 204 increases net. The approximate pressure of the working fluid 204 when it reaches the lower end 196 of the injection well 112 / connecting piece 160 is about 10,000 kPag at a depth of about 2,000 m, as provided in this embodiment. While the pressure increase occurs during the change in depth, the rate of heat transfer, and therefore the rate at which the temperature of the working fluid 204 rises, depends on the depth, the thermal conductivity of the rock, the residence time, and the temperature of the rock layer 320. Thus, the temperature continues to rise as the liquid working fluid 204 flows downward within the injection well 112, laterally along the upper lateral section 116, and through the multi-branch connector 120. Both the heat transfer and the increase in pressure action are demonstrated by step 415.

[0171] In step 420, at some point while the liquid working fluid 204 is flowing through the upper lateral section 116, connecting piece 160, multi-branch connector 120, connecting piece 164, and lower lateral section 124, the liquid working fluid 204 undergoes a phase change from liquid to gas (in step 415) as the liquid working fluid 204 reaches its boiling point due to heat and increased pressure. More specifically, the rate of temperature increase increases until the liquid working fluid 204 begins to vaporize, at which point the temperature remains constant until all of the liquid working fluid 204 has changed to a gaseous state (gas working fluid 208), and then the temperature rises again as the vapor or gaseous working fluid 208 superheats. It will be recognizable to those skilled in the art that the temperature and pressure required to vaporize the liquid working fluid 204 will vary depending on the specifications of the working fluid 200. In the present embodiment, where the working fluid 200 is propane, it is vaporized at a temperature of about 140°C and a pressure of about 6250 kPag. In a preferred embodiment, a phase change occurs within the lower lateral section 124 or production well 128 to minimize friction between the working fluid 200 and the remaining length of the casing and thus maximize the velocity of the working fluid 200 before the working fluid 200 exits the complete casing underground well loop 108, although it will be conjured to those skilled in the art that the phase change of the working fluid 200 can occur anywhere underground within the complete casing underground well loop 108. It will be conjured to those skilled in the art that the location along the flow path of the working fluid within the complete casing underground well loop 108 varies depending on the configuration of the complete casing underground well loop 108, the length and depth of the components within the complete casing underground well loop 108, the flow rate of the working fluid 200, and the boiling point of the working fluid 200, as well as the temperature of the rock layer 320, the conduction rate from the rock to the working fluid 200 through the steel casing 156 and cement 152.

[0172] In step 425, the gaseous working fluid 208 rises to the surface 316 through the production well 128, the insulated production pipe 166, and the common well segment 118, and exits the fully cased underground well loop 108 at opening 110A. As the gaseous working fluid 208 rises to the surface 316, the pressure and temperature decrease slightly due to the change in depth, but the temperature of the working fluid 200 is high enough to maintain the gaseous state of the working fluid 208. The approximate temperature and pressure of the gaseous working fluid 208 at the outlet of opening 110A are about 90°C to about 110°C, with a preferred temperature of about 106°C and a preferred pressure of about 3000kPag to about 4000kPag. The gaseous working fluid 208 is then transported along the connecting piece 168 toward the turbine system 132.

[0173] Thus, in this embodiment, the temperature of the liquid working fluid 204 is approximately 30°C and 1080 kPag at the inlet of the opening 110A, and the temperature of the gaseous working fluid 208 is approximately 106°C and 3500 kPag at the outlet of the opening 110A. Therefore, the movement of the working fluid 200 through the fully cased underground well loop 108 increased its temperature by approximately 76°C and its pressure by approximately 2170 kPag. Furthermore, in this embodiment, the residence time of the working fluid 200 from the time it enters the inlet of the opening 110A until it exits the outlet of the opening 110A is approximately 30 minutes. Those skilled in the art will recognize that the temperature difference and residence time are influenced by several factors, including, but not limited to, the composition, depth and length of the components of the fully cased underground well loop 108, as well as the temperature of the rock layer 320, the thermal conductivity of the rock, the conductivity from the rock through the casing 156 and cement 152 to the working fluid 200, and the flow rate of the working fluid 200.

[0174] In this embodiment, where the working fluid 200 is propane, the temperature of the propane can range from the ambient temperature when it enters the fully cased underground well loop 108 at the inlet of opening 110A to 185°C when it exits the fully cased underground well loop 108 at the outlet of opening 110A. The ambient temperature may vary depending on the environment in which the geothermal energy generation system 100 is located, and may be in the range of -43°C to 45°C.

[0175] In this embodiment, the turbine system 132 is a turbo expander. In step 430, the turbine system 132 receives a gaseous working fluid 208, which drives a turbine (also referred to herein as a turbine wheel) and thereby generates mechanical energy. Once the turbine wheel is connected to a shaft connected to a generator, the mechanical energy is transmitted to the generator, which then, in step 435, converts the mechanical energy into electrical energy. In this embodiment, the gaseous working fluid 208 is expanded by the shape of an expander / valve, and the pressure and temperature of the gaseous working fluid 208 also decrease, in which case the radial turbine connector to the shaft rotates. The approximate pressure and temperature of the propane gaseous working fluid 208 exiting the turbine system 132 are in the range of about 1500 kPag and about 63°C to about 700 kPag and about 16°C. In a preferred embodiment, the ambient air temperature via the cooler 136 can easily condense the approximate pressure and temperature of the gaseous working fluid 208, converting the gaseous working fluid 208 into a liquid working fluid 204. The electrical energy generated by the generator in step 435 is approximately 1 MW and may vary depending on the condensation pressure of the cooler under ambient conditions. Thus, a reduction in the load required for the cooler 136 to condense the gaseous working fluid 208 increases the net electrical energy generated by the generator. Those skilled in the art will recognize that reducing the need to use energy to cool parasitic loads, such as the gaseous working fluid 200, increases the amount of electrical energy generated and thus increases the efficiency of the geothermal energy generation system 100. In certain embodiments, it will be recognizable to those skilled in the art that, depending on the efficiency of the turbine system 132 and the specifications of the working fluid 200, the working fluid 200 exiting the turbine system 132 may be in a mixture of both gaseous and liquid states.

[0176] In step 440, the gaseous working fluid 208 exiting the turbine system 132 may travel along the connecting piece 172 and be received by the cooler 136. The cooler 136 can condense the gaseous working fluid 208 into a liquid state. At the outlet of the cooler 136, the temperature and pressure of the propane liquid working fluid 204 may be 30°C and 1080 kPag, but may vary depending on the temperature and pressure of the ambient air.

[0177] Once it leaves the cooler 136, the liquid working fluid 204 can return to the pump 104 via the connecting piece 176, where it is circulated again as can be seen in step 405.

[0178] Referring to Figure 5, a flowchart is shown illustrating the steps of Method 400A for operating a geothermal energy generation system 100A according to one embodiment of the present invention. For convenience, similar reference numerals are used in Figures 4 and 5 to indicate similar steps. Method 400A is essentially similar to Method 400, except that it includes additional steps 437 and 432 relating to the reconverter 184.

[0179] Steps 405, 415, 420, 425, 430, and 435 are performed as described above in the context of method 400 shown in Figure 4. Step 437 is performed after step 435, in which the gaseous working fluid 208 transfers heat to a parallel tube containing the liquid working fluid 204 (which is received by the liquid working fluid 204, as detailed below in step 442). By transferring heat through the reconverter 184, the temperature of the gaseous working fluid 208 decreases so that less energy is required in the cooler 136 to condense the gaseous working fluid 208 in the subsequent step 440. The temperature of the gaseous working fluid 208 after leaving the reconverter 184 and before being received in the cooler 136 decreases by approximately 15°C.

[0180] Subsequently, step 440 is performed as described above in the context of method 400 shown in Figure 4, namely, the gaseous working fluid is condensed to become a liquid working fluid. Following step 440, in step 442, the liquid working fluid 204 enters the reconverter 184 and receives heat from it. More specifically, the reconverter 184 interacts with the working fluid 200 at two locations along a single heat exchange loop, specifically, after the turbine system 132 as the gaseous working fluid 208, and after the pump 104 as the liquid working fluid 204. The two tubes carrying the working fluid 200 are in close proximity while inside the reconverter 184, allowing heat transfer 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 (which is transferred from the gaseous working fluid 208 in step 437), thereby raising the temperature of the liquid working fluid 204 before proceeding to the adiabatic injection tube 114. In this embodiment, the temperature of the liquid working fluid 204 can be raised by as much as 10°C after it leaves the reconverter 184 and before it reaches the insulated injection pipe 114.

[0181] Those skilled in the art will recall that the approximate temperature and pressure ranges provided above may vary depending on the configuration of the geothermal energy 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 while the approximate temperature and pressure ranges are provided in the above embodiments where the preferred working fluid 200 is a commercially available, environmentally friendly carbon-based refrigerant, the geothermal energy generation system 100 will continue to operate even if the preferred working fluid 200 is outside the approximate temperature and pressure ranges.

[0182] Referring to Figure 6A, an embodiment of geothermal energy generation system 100-1 is shown, comprising two fully cased underground well loops 108A and 108-2, both of which are connected to a single connecting well 140. As will be further discussed below, this simplifies construction because only a single connecting well 140 needs to be drilled. Furthermore, the use of a single connecting well 140 further minimizes the installation area of ​​the geothermal energy generation system. Those skilled in the art will recognize that the geothermal energy generation system 100-1 is not limited to two fully cased underground well loops, but may be any number of fully cased underground well loops.

[0183] In an embodiment of geothermal energy generation system 100-1, two fully cased underground well loops 108-1 and 108-2 each have their own multi-branch connectors 120-1 and 120-2. As can be seen from the arrangement of multi-branch connectors 120-1 and 120-2, an extension of the lateral section from the connecting well 140 allows for the further arrangement of additional multi-branch connectors 120. The lateral section of the connecting well 140 can be further extended to increase the number of multi-branch connectors 120 to be arranged, and assuming there is space, allows for the arrangement of additional fully cased underground well loops 108. In an alternative embodiment, the additional multi-branch connectors 120 may be arranged at different depths along the connecting well 140, or in lateral sections that may be at different depths. Furthermore, the additional multi-branch connectors 120 can also be arranged at different locations along the circumference of the connecting well 140, or in lateral sections that branch off from the connecting well 140 at different locations along the circumference of the connecting well 140. Those skilled in the art will recognize various potential configurations and arrangements of the multiple multi-branch connectors 120 for the connecting well 140.

[0184] Referring to Figure 6B, the components of the two fully cased underground well loops 108-1 and 108-2 can be seen. The two fully cased underground well loops 108-1 and 108-2 have components similar to those of fully cased underground well loop 108, which was previously referenced in Figures 1, 2, and 3. Therefore, the internal components of each of these two fully cased underground well loops 108-1 and 108-2 are numbered similarly to the components of fully cased underground well loop 108, with either -1 or -2 appended to the end to indicate the first or second fully cased underground well loop 108-1 or 108-2. Assuming the components are similar, the components will not be described further.

[0185] In Embodiment 100-1, the two fully cased underground well loops 108-1 and 108-2 operate in the same manner as in the previous embodiment of the fully cased underground well loop 108, but after exiting their respective openings 110A-1 and 110A-2, the two flows of gaseous working fluid 208 can merge into a single flow received by a single turbine system 132. Thus, the merging connector 168-1 can be configured to enable the merging of the two flows of gaseous working fluid 208. Furthermore, a single cooler 136 can receive the gaseous working fluid 208 exiting the turbine system 132 and condense the gaseous working fluid 208 into a liquid working fluid 204. Next, the liquid working fluid 204 may be split into two flows using a splitter connector 176-1 so that they are received by pumps 104-1 and 104-2, with pump 104-1 increasing the pressure of the liquid working fluid 204 being injected into the insulated injection pipe 114-1, and pump 104-2 increasing the pressure of the liquid working fluid 204 being injected into the insulated injection pipe 114-2.

[0186] When using Embodiment 100-1, the turbine system 132 and cooler 136 can be shared between the fully cased underground loops 108-1 and 108-2, thus minimizing the amount of components or equipment required. This further minimizes costs. Furthermore, in contrast to the turbine system 132 and cooler 136 in each fully cased underground well loop 108-1 and 108-2, there is only a single turbine system 132 and cooler 136 above ground, thus minimizing the installation area and above-ground surface area. In this embodiment, the above-ground surface area is approximately 30,100 m². 2 This is also possible. Furthermore, as will be discussed later, scalability and economies of scale are inherent to the design of Embodiment 100-1.

[0187] Those skilled in the art will recognize the modularity of the turbine system 132, the cooler 136, and the pump 104. Specifically, those skilled in the art will recognize that any number of fully cased underground well loops 108 can be connected to a single turbine system 132, a single cooler 136, and a single pump 104. Alternatively, any number of fully cased underground well loops can be connected to multiple turbine systems 132, a single cooler 136, and a single pump 104. Similarly, any number of fully cased underground well 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. Thus, those skilled in the art will recognize different combinations and variations of the fully cased underground well loops 108, the turbine system 132, the cooler 136, and the pump 104.

[0188] Furthermore, as previously mentioned, the geothermal energy generation system 100-1 may consist of any number of fully cased well loops 108 connected to a single connecting well 140. There are several different possible arrangements of any number of fully cased well loops 108 associated with a single connecting well, and it will be recognizable to those skilled in the art that some arrangements may allow for a smaller installation area with a smaller surface area used. Figure 6C provides an exemplary arrangement of five fully cased well loops (provided in reference numbers 108-1, 108-2, 108-3, 108-4, and 108-5, respectively) connected to a single connecting well 140. A lateral section 140A extends away from the connecting well 140 and provides an area for arranging a multi-branch connector 120 for each of the five fully cased underground well loops. In a preferred embodiment, there may be isolation packers 330 between each multi-branch connector 120, isolating each multi-branch connector 120 of each fully cased underground well loop 108 from one another. As can be seen from Figure 6C, each of the five fully cased underground well loops includes first and second lateral segments extending from wells located in the same location. In the embodiment shown, the five fully cased underground well loops are equidistant from each other, but this can be changed depending on the surrounding rock formation. The trajectory of the lateral sections 140A is not limited and may vary. Furthermore, the lateral sections 140A are not limited to being linear and may include a combination of inclined and straight sections. The lateral sections 140A are also not limited to having five fully cased underground well loops 108, and may have additional or fewer fully cased underground well loops 108 within each lateral section 140A. Furthermore, there may be two or more lateral sections 140A extending away from the connecting well 140. For example (not shown), there may be two lateral sections 140A extending in opposite directions from the connecting well 140, providing 10 fully cased underground well loops. Those skilled in the art will recognize various potential layouts, arrangements, and configurations of a fully cased underground well loop 108 associated with a connecting well 140.

[0189] When numerous well loops produce power during commercial operation and sell it to the power transmission line via sales meters, it is desirable to control the power generated. For example, if 25 MW needs to be delivered to the grid, 25 fully cased underground well loops 108 can be used. An on / off power control scheme is used to supply the optimal amount of power to the grid on an hourly basis. The system can electronically monitor grid capacity and power demand and then provide feedback to the facility process logic controller (PLC). In an embodiment where there is a single turbine system 132 connected to the 25 fully cased underground well loops 108, the PLC automatically turns off the pumps 104 and other rotating equipment and quickly "turns off" individual geothermal well loops by closing electronically operated well head valves. This on / off control system allows the facility to change the power output from 0 MW to 25 MW in 1 MW increments. Alternatively, in an embodiment where there are 25 turbine systems 132 connected to 25 fully cased underground well loops 108, the PLC can turn off the pumps 104 and turbine systems 132 in each fully cased underground well loop 108, allowing the facility to provide power outputs from 0MW to 25MW in 1MW increments.

[0190] This control scheme can also be used on a predetermined schedule. The advantages of the on / off control system are that it is relatively easy to design and operate and provides good power output control. This control scheme can be used for a single closed-loop system, such as the one shown in Figure 6B, where the working fluid interacts with the subsurface reservoir only by conduction. The reservoir fluid does not enter the geothermal loop, and the well working fluid 200 does not enter the reservoir. All well heating is done by conductive heat transfer. For this reason, power generation can be quickly changed by cutting off the flow of the working fluid 200 to the insulated injection pipe 114 and injection well 112, thereby stopping the power generation of that well. Also, when the well is turned off, the subsurface rock can be "recharged" by conductive heating, and the fully cased subsurface well loop 108 can generate increased power (compared to steady-state operation) when it is turned on again. Those skilled in the art will recognize the ability of the above control scheme to control any number of fully cased subsurface loops 108 and turbine systems 132.

[0191] Referring to Figure 7, a flowchart is shown illustrating the steps of Method 700 for constructing a fully cased underground well loop 108 of a geothermal energy generation system 100 according to one embodiment of the present invention. More specifically, the steps of Method 700 follow the embodiment of system 100 shown in Figure 1. The construction of the fully cased underground well loop 108 involves drilling and connecting a connecting well 140 with well 174, which includes a common well segment 118 and a production well 128, using a drilling rig, and further drilling an injection well 112 that branches off from the common well segment 118 at connection point 122. As will become apparent in Method 700, the initial drilling connecting the connecting well 140 with the common well segment 118 of well 174 may require at least one large drilling rig to land the heavy intermediate casing. Alternatively, two larger drilling rigs could be used: one to drill the connecting well 140 and to land the heavy intermediate casing in the connecting well 140, and the other to drill the common well segment 118 of well 174 and to land the heavy intermediate casing in well 174.

[0192] Step 705 includes drilling the connecting well 140 and the common well segment 118. In the present embodiment described below, it will be apparent to those skilled in the art that the connecting well 140 may be drilled first, the common well segment 118 may be drilled first, or the connecting well 140 and the common well segment 118 may be drilled simultaneously. It will also be apparent to those skilled in the art that the connecting well 140 may be an existing well that is being reused for use as the connecting well 140. For example, the connecting well 140 may be an existing well used for oil drilling, or an existing well that already has a pre-configured surface casing or intermediate casing.

[0193] Returning to the current embodiment in which both the connecting well 140 and the common well segment 118 are drilled, the two drilling rigs can be moved and fixed to separate surface positions. Referring to Figure 8, these are positions 304 and 308. Positions 304 and 308 are at least a predetermined distance from the length of the lateral sections 116 and 124 (as shown in Figure 1) and at any offset distance required for the well track construction angle. The positioning of the two drilling rigs in this case is based on an embodiment of a fully cased underground well loop 108 in which the common well segment 118, injection well 112, production well 128, lateral sections 116 and 124, and multi-branch connector 120 are aligned in the same vertical plane, and it will be apparent to those skilled in the art that the positioning of the two drilling rigs can be adjusted based on the position and configuration of the components of the fully cased underground well loop 108.

[0194] A first drilling rig, positioned at location 304 above the planned connecting well 140, is capable of drilling boreholes with a diameter of 7 7 / 8 inches to 12 1 / 4 inches and a depth of 650 m to 2000 m. In a preferred embodiment, a borehole with a diameter of 440 mm (17 1 / 4 inches) and a depth of approximately 650 m is drilled. The drilling mud / fluid used may be an environmentally friendly freshwater gel system. Examples of drilling mud include, but are not limited to, bentonite clay as a gel, along with additives such as barium sulfate (barite), calcium carbonate (chalk), or hematite. Those skilled in the art will recognize the different drilling muds that may be used in connection with the drilling rig.

[0195] After the borehole is drilled, the surface casing 212 can be set in place. The surface casing 212 may be set in place to a depth corresponding to the drilled borehole. In a preferred embodiment, the surface casing 212 is set in place with a diameter of 340 mm (13 3 / 8 inches) and extends to a depth of approximately 650 m. The entire length and circumference of the surface casing 212 are fixed to the ground surface 316 with cement. The surface casing 212 is important for securely fixing the planned connecting well 140 in place, preventing shallow formations from collapsing into the well, and providing a base for a Class 5 blowout arrester, which will be described later.

[0196] A second rig positioned at position 308 of the planned well 174 and common well segment 118 can drill a second hole in the surface casing 144. The drilled hole may have a diameter of 12 1 / 4 inches to 17 1 / 2 inches and a depth of 300 m to 650 m. In a preferred embodiment, the drilled hole may have a diameter of 12 1 / 4 inches and 17 1 / 2 inches and a depth of approximately 650 m. Similar to drilling by the first rig positioned at position 304, the drilling mud of the second rig may be an environmentally friendly freshwater gel system.

[0197] After the second borehole is drilled, the surface casing 144 may be set in place. The surface casing 144 may have a diameter of 9 5 / 8 inches to 13 3 / 8 inches and be set in place at a depth of 300 m to 650 m. In a preferred embodiment, the surface casing 144 is set in place with diameters of 9 5 / 8 inches and 13 3 / 8 inches and extends to a depth of approximately 650 m. The entire length and circumference of the surface casing 144 are cemented to the ground surface 316. Similar to the surface casing 212, the purpose of the surface casing 144 is to securely fix the planned injection well 112 in place, prevent shallow formations from collapsing into the well, and provide a base for a Class 5 blowout arrester, which will be described later. Furthermore, the surface casing 144 is intended to prevent the working fluid 200 from leaking into the surrounding environment.

[0198] The cement casing used for both surface casings 144 and 212 is preferably 1860 kg / m³, with a 50% surplus in the total calculated pore volume. 3 It has a heat-resistant cement compound (total cement mass is approximately 80 tons). Next, the cement casing is 2.5 m 3 It can then undergo a first pre-flush with freshwater. Subsequently, the cement casing is subjected to a 1200 kg / m³ treatment. 3 5m weighted 3 A second pre-flush of thickening water can be performed. An example of thickening water is Optiflush®. Those skilled in the art will recognize other forms or variations of thickening water. The cement plug can then be dropped and replaced with fresh water.

[0199] A Class 5 blowout arrester (not shown) may be installed on or near the surface casings 144 and 212. The Class 5 blowout arrester is used to seal, control, and monitor well 174 and connecting well 140 to prevent blowouts. In this embodiment, the Class 5 blowout arrester is pressure-tested up to a low pressure of 1,400 kPa and a high pressure of 35,000 kPa, with each pressure tested for a duration of at least 10 minutes. The Class 5 blowout arrester may also be pressure-tested depending on the forming pressure and any applicable regulatory requirements. Those skilled in the art will recognize the different pressures and durations for which the Class 5 blowout arrester may be tested.

[0200] The drilling of the boreholes for the common well segment 118 and the connecting well 140 is directionally controlled by a directionally controlled drilling assembly that performs measurements while drilling ("MWD") to maintain target accuracy. Specifically, a first drilling rig at position 304 drills a borehole with a diameter of 7 7 / 8 inches to 12 1 / 4 inches through the surface casing 212 to a predetermined depth. In a preferred embodiment, the first drilling rig drills an intermediate borehole (not shown) with a diameter of 311 mm (12 1 / 4 inches) through the surface casing to a predetermined depth. The connecting well 140 is first drilled vertically and then directionally drilled to achieve a 90-degree inclination at a landing site 228 adjacent to the lower end 216 of the connecting well 140. This landing site 228 is located within a geothermal target layer at a depth of target temperature. In this embodiment, the connecting well 140 is drilled with an oil-based mud system to minimize runoff and protect the integrity of the well. However, the drilling mud system used may depend on the region and its past drilling problems. Those skilled in the art will recognize the various potential drilling mud systems that can be used.

[0201] Subsequently, the intermediate heat casing 236 extends over the full depth of the access shaft 140, and the intermediate heat casing 236 can be cemented to the surface of the surrounding rock formation 320. In a preferred embodiment, the intermediate casing 236 has a diameter of 244 mm (9 5 / 8 inches), although in other embodiments, the intermediate casing 236 may have a diameter of 7 inches to 9 5 / 8 inches. Then, the intermediate heat casing 236 can receive a first preflush of 5 m 3 of thickened water, and the thickened water is weighted to provide a well pressure / hydrostatic pressure higher than that of the formation pressure to maintain an overbalanced well. Then, the intermediate heat casing 236 can receive a second preflush of 5 m 3 of scavenger weighted at 1450 kg / m 3 or more. The overbalanced well prevents formation gas or fluid from entering the well and rising to the surface. Then, cement is filled / supplied into the intermediate heat casing 236 with thermolite cement having a 20% surplus (about 75 t) of the total calculated pore volume. Then, 20% (about 45 t) of airtight cement is supplied to the tail segment. Then, the inner diameter of the cement is replaced with fresh water to form a hollow well, and the outer diameter remains cemented to the rock formation 320.

[0202] The volume and blend of the cement can be adjusted according to past well data, formation pressure, and regional regulatory isolation requirements for a particular formation to prevent cross-flow contamination.

[0203] The intermediate thermal casing 236 can be secured to the wellhead / inlet 232 using a speedhead or an additional wellhead section to set up a slip. The slip (also referred to herein as an anchor) may be set to the intermediate thermal casing 236 with full tension to hold the intermediate thermal casing 236 inside the surface casing 212. In certain embodiments, the Class 5 blowout arrester on the surface casing 212 may have to be disassembled to set up the slip. Once reassembled, the Class 5 blowout arrester may be pressure-tested again at the same pressure and specifications to verify the integrity of the Class 5 blowout arrester after reassembly, but the intermediate thermal casing 236 is located within the connecting well 140. The Class 5 blowout arrester may also be pressure-tested again against the pressure and / or regulatory requirements of the expected rock mass 320.

[0204] The gyroscope wired surveying tool can be deployed to the connecting well 140. The gyroscope wired surveying tool enables continuous surveying from vertical to horizontal and to the reach limit. The gyroscope wired surveying tool provides the geometric shape of the well with very high precision and gives the precise coordinates of the connecting well 140 to assist in intersecting with well 174 or other future intersections.

[0205] With respect to the common well segment 118, the second rig drills a bore (also referred to herein as an intermediate bore) to a predetermined depth through the surface casing 144 at position 308. The intermediate bore can have a diameter of 7 7 / 8 inches to 12 1 / 4 inches. In a preferred embodiment, the intermediate bore has a diameter of 222 mm (8 3 / 4 inches). The predetermined depth may vary depending on the preferred temperature or geothermal target layer. In a preferred embodiment, the predetermined depth is 1000 m to 3500 m. Similar to the first drilling rig drilling the main bore of the connecting well 140, the drilling of the main bore of the common well segment 118 can be done with an oil-based mud system. The drilling assembly can then be removed from the well. A gyroscope wired surveying tool can then be deployed into the common well segment 118 to provide coordinates of the common well segment 118 to assist in intersecting with the connecting well 140. A new directional drilling assembly equipped with magnetic tools (such as the aforementioned Lodestone(trademark) package) is lowered into the well.

[0206] Next, a second intermediate thermal casing 238 extends across the entire depth of the common well segment 118, and the intermediate thermal casing 238 can be cemented to the surface of the surrounding rock layer 320. In a preferred embodiment, the intermediate casing 238 has a diameter of 9 5 / 8 inches, but in other embodiments, the intermediate casing 238 may have a diameter of 7 inches to 9 5 / 8 inches. Similar to the intermediate thermal casing 236 of the connecting well 140, the intermediate thermal casing 238 then extends 5 m 3 The borehole can receive a first pre-flush of thickened water, which is weighted to provide a borehole pressure / hydrostatic pressure higher than the formation pressure to maintain an overbalanced borehole. The intermediate thermal casing 238 is then weighted at 1450 kg / m³ to maintain an overbalanced borehole. 3 The above weighted 5m 3The well can undergo a second pre-flush from the scavenger. The overbalanced well prevents gases or fluids from the formation from entering the well and rising to the surface. The intermediate thermal casing 238 is then filled / supplied with thermolite cement, with a 20% surplus (approximately 75 tons) of the total calculated well volume. Next, 20% (approximately 45 tons) of airtight cement is supplied to the tail cement. The inner diameter of the cement is then replaced with fresh water to form a hollow well, leaving the outer diameter cemented to the rock formation 320.

[0207] Similar to the intermediate thermal casing 236, the volume and blend of cement packed into the intermediate thermal casing 238 can be adjusted according to historical well data, formation pressure, and local regulatory isolation requirements for specific formations to prevent transverse flow contamination.

[0208] The intermediate thermal casing 238 can be secured to the opening 110A using a speedhead or an additional wellhead section to set up a slip. The slip (also referred to herein as an anchor) may be set to the intermediate thermal casing 238 with full tension to hold it inside the surface casing 144. In certain embodiments, a Class 5 blowout arrester on the surface casing 144 may have to be disassembled to set up the slip. Once reassembled, the Class 5 blowout arrester may be pressure-tested again at the same pressure and specifications to verify the integrity of the Class 5 blowout arrester after reassembly, but the intermediate thermal casing 238 is present in the common well segment 118. The Class 5 blowout arrester may also be pressure-tested again against the pressure and / or regulatory requirements of the expected rock layer 320.

[0209] Step 710 involves drilling both intermediate thermal casings 236 and 238 and intersecting the two boreholes using ranging techniques. Step 710 uses at least two drilling rigs, and the first drilling rig at position 304 and the second drilling rig at position 308 may be repositioned for use in Step 710. Alternatively, depending on the size of the lateral segments, connecting well 140 and common well segment 118, smaller drilling rigs may be used compared to those initially located at positions 304 and 308. Using smaller drilling rigs can further save costs and / or capital. Those skilled in the art will recognize the various situations surrounding the use of drilling rigs of different sizes.

[0210] The first drilling rig can be positioned within the connecting well 140 and drill laterally from the drilling position 282 near the landing site 228 through the intermediate casing 236 of the connecting well 140 to begin construction of the lower lateral section 124. The lateral section can be drilled with an oil-based mud system to minimize runoff and protect the integrity of the well. However, the drilling mud system used may depend on the region and its past drilling problems. Those skilled in the art will recognize the various potential drilling mud systems that may be used.

[0211] After the lateral borehole is drilled, the directional drilling assembly can be removed from the well. A magnetic tool is then lowered into the well to the end of the lateral borehole. An example of a magnetic tool is Lodestone™, provided by Scientific Drilling. The magnetic tool is an active ranging system built for intentional well crossings. It can be used in conjunction with all MWD systems. The sensor of the magnetic tool can be deployed in the connecting well 140, and a magnetic sub-sensor can be deployed in the directional drilling assembly of the common well segment 118. The resulting magnetic field provides accurate ranging of the intersection between the connecting well 140 side and the well 174 side, and also provides planning for the planned intersection 240. In a preferred embodiment, the potential landing point 224 between the proposed lower lateral section 116 and the bottom of the production well 128 may be the planned intersection 240. Those skilled in the art will recognize that the planned intersection 240 may be at any location along the lower lateral section 116 and the production well 128, but for the purposes of the construction method described below, an embodiment in which the planned intersection 240 is the landing point 224 will be described.

[0212] Simultaneously, a second drilling rig can be positioned within well 174, drilling laterally from a drilling position 286 adjacent to the landing point 224, intersecting with the first drilling rig, and drilling laterally along the same lower lateral section 124. Similar to that of the first drilling rig drilling laterally from the connecting well 140, the lateral section can be drilled with an oil-based mud system to minimize washout and protect the integrity of the well. Furthermore, the drilling mud system used may depend on the region and its past drilling problems. Those skilled in the art will recognize the various potential drilling mud systems that may be used.

[0213] A drilling assembly, including magnetic sensors such as those found in the Lodestone® package, can descend into the common well segment 118, drill downward toward the proposed landing point 224, and merge with the lower lateral section 124 from the connecting well 140. More specifically, a second drilling rig with a drilling assembly drills downward toward the landing point 224, while the first drilling rig also drills laterally toward the landing point 224. Magnetic tools and magnetic sensors help facilitate the intersection of the holes drilled at the landing point 224. Once both the lower lateral section 124 and the production well 128 intersect, both directional drilling assemblies can be removed from the lateral section. Figure 9 shows the intersection of both lateral sections.

[0214] Step 710 describes intersecting the production well 128 with the lower lateral section 124, but a person skilled in the art will recognize that drilling of the production well 128 may still occur if the production well 128 is not drilled along the same downward axis as the common well segment 118, and that a drilling assembly having magnetic tools and magnetic sensors can facilitate different intersections 240 depending on the intended path and trajectory of the well, which may depend on the specifications of the rock formation 320.

[0215] In step 715 (shown in Figure 7), the production steel casing 156 is installed in the lower lateral section 124 between the connecting well 140 and the drilling locations 282 and 286 of the common well segment 118. Referring to Figure 10, the production steel casing 156 (also referred to herein as the production liner 156) covers the open portion at drilling locations 282 and 286 leading to the common well segment 118 and the connecting well 140, extending into the inner diameter of both the intermediate casings 236 and 238. The production steel casing 156 installed along the lower lateral section 124 can have a diameter of 4 1 / 2 inches to 7 inches. In a preferred embodiment, the production steel casing 156 can have a diameter of 5 1 / 2 inches. Each end of the production steel casing 156 has a connection and / or seal assembly. The connection / seal assembly can be used to make a pressure test connection with the multi-branch connector 120 and the geothermal isolation joint 170. In a preferred embodiment, the connection / seal assembly may be a polished bore receptacle. The polished bore receptacle is completed with Baker's concentrated / reversed seal bore extension and anchor seal assembly latch profile (not shown).

[0216] A custom-made steel centralizer (not shown) can also be attached to the outside of the casing 156 before cementing. The centralizer is typically designed to lift the casing 156 from the bottom of the lower lateral section 124, thus allowing the cement to completely enclose the casing 156. A custom-made elongated centralizer can also be used to directly increase the conductivity between the geological heat and the steel body of the casing 156 via the cement 152 (because it is made of steel). As previously mentioned, hematite may be added to the cement 152 to optimize conductivity.

[0217] In step 720 (shown in Figure 7), the production steel casing 156 is cemented into place. The isolation packer 252 and cementing stage tool 256 are installed close to the drilling location 282. A calculated amount of hot cement can be pumped and moved. A second isolation packer 254 may be installed close to the drilling location 286. The common well segment 118 is separated from the production steel casing 156. Excess hot cement is recycled along the well 174 to the surface 316 and discarded.

[0218] The isolation packers 252 and 254 are rubber elements that can be expanded to form an impermeable seal between the outer diameter of the production steel casing 156 and the inner diameter of the intermediate heat casing 236. This prevents cement from entering the remaining intermediate casing and causing blockage in either the connecting well 140 or the common well segment 118. In a preferred embodiment, two isolation packers 252 and 254 at each drilling location 282 and 286 can be used to enhance the integrity of the seal packer (not shown).

[0219] The cementing stage tool 256 is opened (which also forms an inner diameter plug at the end of the production steel casing 156 to prevent cement from entering the connecting well 140). The production steel casing 156 can then be cemented into place. Cementing the production steel casing 156 involves first circulating the lower lateral section 124 and the production well 128 between drilling positions 282 and 286 to remove all drilling debris. The isolation packers 252 and 254 are then inflated, and the cementing stage tool 256 is opened, allowing the first darts to be placed in the lower lateral section 124 and the production well 128 to circulate cement around the outer diameter of the production steel casing 156. The lower lateral section 124 and the production well are then cemented to 5m 3 The first pre-flush of thickened water is then performed, and as with previous flushes, the thickened water is weighted to maintain an overbalanced well. The lower lateral section 124 and production well 128 are then filled to 5m3 After the scavenger receives its second pre-flush, the scavenger maintains an overbalance of 1450 kg / m² within the lower lateral section 124. 3 It is weighted accordingly. The cement is then filled / supplied into the intermediate thermal casing 236 with thermolite cement having a 20% surplus (approximately 62 t) of the total calculated well volume. Next, the tail cement is supplied with a 20% surplus (approximately 98 t) of airtight cement. The cement is then replaced with fresh water. Those skilled in the art will recognize that, as with the drilling procedure described above for the connecting well 140, the volume, blend and spacing of the cement and pre-flushing can be adjusted based on the geographical location and historical data of the formation, the formation pressure and local regulatory isolation requirements for the specific formation to prevent transverse flow contamination. A second dart is also placed in the lower lateral section 124 and the production well 128 and lands on a cementing stage tool 256 (which functions as a check valve) to close the cementing port and effectively prevent cement from rising into either the connecting well 140 or the common well segment 118.

[0220] The production steel casing 156 is tensioned by an automatic slip within the casing bowl, and the casing bowl allows the production steel casing 156 to be bolted to a Class 5 blowout prevention device.

[0221] In step 725 (shown in Figure 7), the two-part whipstock 260 and 262 are installed and the casing windows 264 and 266 are milled. Referring to Figure 11, the two-part whipstock 260 (also referred to herein as whipstock 260) is installed between landing site 228 and isolation packer 252, in the lower lateral section 124, close to isolation packer 252. The whipstock 260 includes an upper section (spoon) which forces a pineapple mill (not shown) to cut through the intermediate casing into diamond-shaped windows 264 (also referred to herein as milled windows 264 and bridging holes 264).

[0222] The second two-part whipstock 262 is installed along well 174 at approximately 700 m below the surface 316 at the connection point 122 between the common well segment 118 and the production well 128. The whipstock 262 may also include an upper section (spoon) that forces a pineapple mill (not shown) to cut the window 266 along the vertical section of well 174. In a preferred embodiment, the whipstocks 260 and 262 are installed simultaneously, and the casing windows 264 and 266 are milled simultaneously. However, it will be noted to those skilled in the art that the whipstock 260 may be installed first, or the whipstock 262 may be installed first. Similarly, the casing window 264 may be milled first, or the casing window 266 may be milled first. Those skilled in the art will recognize various potential sequences in which the whipstocks 260 and 262 can be installed and the casing windows 264 and 266 can be milled.

[0223] Whipstocks 260 and 262 also include a lower portion (not shown) which includes a guide and anchor (not shown) that may be permanently installed in the intermediate casing. The guide allows for the forced extrusion of the drilling and finishing assembly through a smaller diameter hole passing through the center of the guide, in addition to allowing the finishing assembly to be rerouted to the lower portion of the well. Those skilled in the art will recognize the use of whipstocks and their use in creating well joints.

[0224] The whip stock 262 and milling window 266 also allow the inclined section 126 and vertical section 138 of the injection well 112 to be drilled. Furthermore, the whip stock 260 and milling window 264 allow the upper lateral section 116 to be connected to a multi-branch connector 120 to be installed in the future.

[0225] In step 730 (shown in Figure 7), the upper lateral section 116 and the injection well 112 are drilled, and the milling windows 264 and 266 are connected. Referring to Figure 12, the first drilling rig can drill the upper lateral section 116 while drilling toward well 174, starting from the milling window 264. In a preferred embodiment, the upper lateral section 116 is drilled with an oil-based mud system to minimize washout and protect the integrity of the well. However, the drilling mud system used may depend on the region and its past drilling problems. Those skilled in the art will recognize the various potential drilling mud systems that may be used.

[0226] Similar to the drilling of the lower lateral section 124, the directional drilling assembly may be removed from the well. The magnetic tool is then lowered into the connecting well 140 to the casing window 264. The magnetic tool may be an active ranging system that can be used with the MWD system. More specifically, a magnetic sensor may be deployed in the upper lateral section 116, and a magnetic sub-unit may be deployed in the injection well 112, which will be further described below. The magnetic sensor and magnetic sub-unit enable accurate ranging at the intersection of the upper lateral section 116 and the injection well 112.

[0227] Simultaneously, a second drilling rig can drill the injection well 112, starting from the milling window 266. Specifically, the inclined section 126 may be drilled by the second drilling rig in the milling window 266. After drilling an inclined section 126 of a predetermined length, a vertical section 138 can be drilled. The inclined section 126 and vertical section 138 of the injection well 112 may be drilled with an oil-based mast system to minimize runoff and protect the integrity of the well. However, the drilling mud system used may depend on the region and its past drilling problems. Those skilled in the art will recognize the various potential drilling mud systems that may be used.

[0228] A drilling assembly can be used to drill the inclined section 126 and the vertical section 138. In a preferred embodiment, the drilling assembly may include a magnetic sensor. The magnetic sensor may be part of a Lodestone® package. The drilling assembly can be lowered through a common well segment 118 for access to drill the injection well 112. A drilling assembly with a magnetic sensor and magnetic tools in the upper lateral section 116 facilitates the intersection of the two wells. Specifically, the drilling assembly facilitates the intersection of the vertical section 138 of the injection well 112 and the upper lateral section 116. In a preferred embodiment, the injection well 112 and the upper lateral section 116 intersect at an intersection 290. However, those skilled in the art will recognize that the intersection 290 may be along any point in the upper lateral section 116 or at any point along the injection well 112. Once the injection well 112 and the upper lateral section 116 intersect, both drilling assemblies can be removed from the first and second drilling rigs.

[0229] In step 735 (shown in Figure 7), the production steel casing 156 is installed in the upper lateral section 116 and the injection well 112. As seen in Figure 13, the production steel casing 156 extends over the length of the upper lateral section 116 and the injection well 112, but does not enter the casing windows 264 and 266. Specifically, the production steel casing 156 can be installed up to within 50 feet of the casing windows 264 and 266. The production steel casing 156 further covers the opening portion / access from the lower lateral section 124 and well 174 to the upper lateral section 116. Connection / seal assemblies are installed at each end of the production steel casing 156, specifically in the casing windows 264 and 266. In a preferred embodiment, the connection / seal assemblies are polished bore receptacles. The polished bore receptacle is completed with Baker's centralized / reversed seal bore extension and anchor seal assembly latch profile (not shown). A polished bore receptacle facing the lower lateral section 124 is also prepared for connection to the multi-branch connector 120, which will be described further below.

[0230] In step 740 (shown in Figure 7), isolation packers 294 and 298 are installed and inflated. The cementing stage tool 300 is also installed and opened. As seen in Figure 14, once the isolation packers 294 and 298 are inflated and the cementing stage tool 300 is opened, the calculated amount of hot cement can be pumped into the borehole, and the borehole is separated from the production steel casing 156. Excess hot cement can be recycled to the surface through the common well segment 118.

[0231] In step 745 (shown in Figure 7), the upper portions of the whip stocks 260 and 262 are removed within the intermediate heat casing 236 on both wells, leaving the lower portions of the whip stocks 260 and 262. This can be seen in Figure 15. The lower portions of the whip stocks 260 and 262 include guides and anchors, allowing the casing or drilling assembly to be routed through the window guides of the whip stocks 260 and 262 into the lower lateral section 124. Furthermore, the window guides have predetermined holes passing through the centers of the whip stocks 260 and 262, allowing access to the production steel casing 156 below the whip stock holes. Specifically, the whip stock holes allow a tool or splitter having an outer diameter smaller than the diameter of the predetermined hole to be lowered below the whip stocks 260 and 262 and connected to the production steel casing 156. After drilling is complete, the outer diameter of the finishing assembly, or any tool extending into the production steel casing 156, can be adjusted to ensure that the appropriate assembly enters the correct well.

[0232] In step 750 (shown in Figure 7), a multi-branch connector 120 is installed and connected between the upper lateral section 116 and the lower lateral section 124. The fully cased underground well loop 108 is then pressure tested. Referring to Figure 16, two dummy trips are performed to both well 174 and the connecting well 140. The first trip is performed using a polished bore locator seal assembly without a latch and with an outer diameter larger than the whipstock guides of whipstocks 260 and 262, and tags the receptacle of the lower lateral section 124 to verify the exact depth of the gap. The second trip is performed using a polished bore locator seal assembly without a latch and with an outer diameter smaller than the whipstock guides of whipstocks 260 and 262, and tags the receptacle of the upper lateral section 116 to verify the exact depth of the gap. This process allows for precise depth measurement and spacing between the access well 140, the lower lateral section 124, and the upper lateral section 116. A multi-branch connector 120 can then be constructed at appropriate intervals to connect the lower lateral section 124 and the upper lateral section 116. Simultaneously, the geothermal isolation joint 170 may also be constructed at appropriate intervals to connect both lateral sections simultaneously, as will be further described below.

[0233] The multi-branch connector 120 can be lowered into the connecting well 140 (using the drilling pipe for landing) to connect the upper lateral section 116 and the lower lateral section 124. The multi-branch connector 120 consists of two different "legs," each designed to ensure and facilitate entry into a specific well (either the upper lateral section 116 or the lower lateral section 124) and to form a pressure-tested connection with the production steel casing 156 in each of the upper lateral section 116 and the lower lateral section 124. One leg 292 includes a polished bore locator seal assembly with a concentrated shear protective shroud having an outer diameter smaller than the whip stock guide of the whip stock 260. This allows the polished bore location seal assembly to be lowered through the window guide and connected to the polished bore receptacle of the production steel casing on the lower lateral section 124. The second leg 296 of the multi-branch connector 120 is of the same design, except that its outer diameter is larger than that of the whipstock guide of the whipstock 260, and it pushes out a polished bore locator seal assembly with a concentrated shear protective shroud from the casing window 264 and connects to the production steel casing 156 via a polished bore receptacle on the upper lateral section 116. The second leg 296 may also include a pin / shear actuated sleeve to protect the seal from friction damage through the window 280 and the opening portion.

[0234] The multi-branch connector 120 provides complete mechanical and hydraulic isolation support for the joint area with re-entry functionality. The multi-branch connector 120 is designed to accommodate re-entry tie-ins in steam-assisted gravity drainage applications. This is typically performed using a full-length liner on one attachment, with a second attachment providing a pressure-tested seal by the existing lateral section. The multi-branch connector 120 helps provide a joint between the upper lateral section 116 and the lower lateral section 124, utilizing the connecting well 140 as the inlet and / or access point.

[0235] In step 755 (shown in Figure 7), the geothermal isolation joint 170 can be installed. As shown in Figure 17, the geothermal isolation joint 170 can descend through well 174 and connect to the inclined section 126 of injection well 112 and to production well 128. The geothermal isolation joint 170 includes a first leg 306 and a second leg 310. The first leg 306 includes a polished bore locator seal assembly with a concentrated shear protective shroud having an outer diameter smaller than the whip stock guide of the whip stock 262. Having an outer diameter smaller than the whip stock guide of the whip stock 262 allows the polished bore locator seal assembly to descend through the window guide of the whip stock 262 and connect to the polished bore receptacle of production well 128. The second leg 310 (also known as the insulated production pipe 166) is of the same design and also includes a polished bore locator seal assembly with a concentrated shear protective shroud. However, the polished bore locator seal assembly has a larger outer diameter than the whip stock guide of the whip stock 262 and pushes the polished bore locator seal assembly with the concentrated shear protective shroud out of the casing window 266 and connects to the production steel casing 156 of the inclined section 126 of the injection well 112. The second leg 310 may also include a pin or shear-actuated sleeve to protect the seal from friction damage through the casing window 266 and the opening portion between the inclined section 126 of the injection well 112 and the well 174. The geothermal isolation joint 170 also serves as the joint point for both the injection well 112 and the production well 128, enabling isolated input and output flow paths.

[0236] In step 760 (shown in Figure 7), the cement stage tool 300 can be milled using a drilling rig. In an alternative embodiment, the cement stage tool 300 can be milled using a joined drilling pipe or a coiled pipe unit. Any solid foreign matter can also be removed from the milled cement stage tool 300.

[0237] In step 765 (shown in Figure 7), a pressure test can be performed. Once the milling of the cement stage tool 300 is complete, the flow path for the entire loop of the complete casing underground well loop 108 is completed. Once circulation can be established, a pressure test (known to those skilled in the art) can be performed on the entire complete casing underground well loop 108.

[0238] If the test is successfully performed, the geothermal energy generation system 100 will be ready to operate according to the method steps shown in Figures 4 and 5.

[0239] The construction of the geothermal energy generation system 100 utilizes known technologies and methods in well construction in the oil and gas sector, but applies these technologies and methods in novel and progressive ways for the generation and production of energy from geothermal sources.

[0240] The foregoing description and accompanying drawings are for specific preferred embodiments of the invention as currently envisioned by the inventors, but it will 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 sources, A common well segment extending into a bedrock layer underground, comprising a common well segment having an upper end and a lower end, An insulated injection pipe extending underground into the rock layer, wherein a portion of the insulated injection pipe is located in the same place as the common well segment, and the insulated injection pipe is fluidly isolated from the common well segment, and An injection well extending further underground from the lower end of the common well segment, having an upper end and a lower end, the upper end of the injection well being fluidly connected to the adiabatic injection pipe, A production well extending further underground from the lower end of the common well segment, having an upper end and a lower end, the upper end of the production well being fluidly connected to the common well segment, A first lateral section connected to a position along the injection well and extending away from there, A second lateral section connected to a position along the aforementioned production well and extending away from it, The device comprises a multi-branch connector that joins the first lateral section and the second lateral section, Each of the common well segment, the injection well, the production well, and the first and second lateral sections is cased with steel and fixed in place with cement within the rock layer. The insulated injection pipe, the injection well, the first lateral section, the multi-branch connector, the second lateral section, the production well, and the common well segment cooperate to define a pressure-tested underground well loop within the rock formation and to configure heat transfer with it, the pressure-tested underground well loop being configured to receive a working fluid that can undergo a phase change between liquid and gas within the pressure-tested underground well loop as a result of heat transferred from the rock formation, and the system is, A pump fluid-connected to the insulated injection pipe, configured to circulate the working fluid through the pressure-tested underground well loop, A turbine system, which is fluidly connected to the common well segment and is capable of operating to convert mechanical energy generated from the flow of working fluid into electricity, A cooler is fluid-connected between the pump and the turbine system to cool the working fluid, A system equipped with these features.

2. The system according to claim 1, further comprising a surface casing surrounding the opening of the common well segment, wherein the surface casing is partially above the ground surface and is configured to prevent leakage of the working fluid into the rock layer.

3. 30,100m ２ The system according to claim 1 or claim 2, having a ground surface area.

4. The system according to any one of claims 1 to 3, wherein the working fluid is a homogeneous working fluid.

5. The system according to any one of claims 1 to 3, wherein the working fluid is a heterogeneous working fluid.

6. The system according to any one of claims 1 to 5, wherein the common well segment has a depth of approximately 650 m.

7. The system according to any one of claims 1 to 6, wherein the first lateral section extends away from the injection well at a depth of 1,000 m to 3,500 m.

8. The system according to any one of claims 1 to 7, wherein the second lateral section extends away from the production well at a depth of 1,000 m to 3,500 m.

9. The system according to any one of claims 1 to 8, wherein the first lateral section has a length of 2,000 m to 4,000 m.

10. The system according to any one of claims 1 to 9, wherein the second lateral section has a length of 2,000 m to 4,000 m.

11. The system according to any one of claims 1 to 10, wherein the first lateral section is located at a depth lower than the depth of the second lateral section.

12. The system according to any one of claims 1 to 10, wherein the second lateral section is located at a depth lower than the depth of the first lateral section.

13. The system according to any one of claims 1 to 10, wherein the first lateral section is at the same depth as the second lateral section, and the first lateral section is spaced apart from the second lateral section.

14. The system according to any one of claims 1 to 13, wherein during operation, the pressure-tested underground well loop is configured to receive a fluid pressurized to 7 MPa to 31 MPa.

15. The system according to any one of claims 1 to 13, wherein the pressure-tested underground well loop can withstand a pressure of at least 7 MPa.

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

17. The positive displacement pump is selected from the group consisting of plunger type pumps, gear type pumps, and rotary vane type pumps, according to claim 16.

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

19. The turbine system according to any one of claims 1 to 18, wherein the turbine system is capable of generating an 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, the storage tank being 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 fluid, ammonia, carbon dioxide, and water.

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

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 reheater having a first flow path connected between the turbine system and the cooler, and a second flow path connected between the pump and the insulated injection pipe, wherein the reheater is configured to transfer heat from the first flow path to the second flow path.

26. The system according to any one of claims 1 to 25, wherein the insulated injection pipe is a steel pipe having an insulating compound that coats the steel pipe.

27. The system according to any one of claims 1 to 26, wherein the portion of the insulated injection pipe extends along the central axis of the common well segment.

28. The system according to any one of claims 1 to 27, wherein the upper end of the injection well includes a downward sloping section, and the lower end of the injection well includes a vertical section.

29. The system according to any one of claims 1 to 28, wherein most of the injection wells are spaced apart from the production wells.

30. The system according to claim 29, wherein the majority of the injection well is spaced at least 80 m laterally from the production well.

31. A geothermal isolation joint located along the lower part of the common well segment, wherein the insulated injection pipe is fluidly connected to the injection well through the geothermal isolation joint, An isolation packer positioned along the upper part of the aforementioned production well, An insulated production pipe for fluidly connecting the production well and the common well segment, wherein a portion of the insulated production pipe extends between the isolation packer and the geothermal isolation joint, further comprising: The geothermal isolation joint isolates the working fluid in the insulated injection pipe from the working fluid in the insulated production pipe. The system according to any one of claims 1 to 30.

32. The system according to any one of claims 1 to 28, wherein the portion of the insulated injection pipe is arranged concentrically with the common well segment.

33. The system according to any one of claims 1 to 28, wherein the portion of the insulated injection pipe is arranged eccentrically with the common well segment in the same location.

34. The system according to any one of claims 1 to 34, further comprising an access well having a lateral segment, wherein the multi-branch connector is located within the lateral segment of the access well.

35. The common well segment is the first common well segment, the insulated injection pipe is the first insulated injection pipe, the injection well is the first injection well, the production well is the first production well, the multi-branch connector is the first multi-branch connector, the pressure-tested underground well loop is the first pressure-tested underground well loop, and the pump is the first pump. A second common well segment extending underground into the bedrock layer, comprising a second common well segment having an upper end and a lower end, A second insulated injection pipe extending underground into a bedrock layer, wherein a portion of the second insulated injection pipe is located in the same place as the second common well segment, and the second insulated injection pipe is fluidly isolated from the second common well segment, A second injection well extending further underground from the lower end of the second common well segment, having an upper end and a lower end, the upper end of the second injection well being fluidly connected to the second insulated injection pipe, A second production well extending further underground from the lower end of the second common well segment, having an upper end and a lower end, the upper end of the second production well being fluidly connected to the common well segment, A third lateral section connected to and extending away from the second injection well, A fourth lateral section connected to a position along the second production well and extending away from there, The present invention further comprises a second multi-branch connector that joins the third lateral section and the fourth lateral section, Each of the second common well segment, the second injection well, the second production well, and the third and fourth lateral sections is cased with steel and fixed in place with cement within the rock layer. The second insulated injection pipe, the second injection well, the third lateral section, the second multi-branch connector, the fourth lateral section, the second production well, and the second common well segment cooperate with each other to define a second pressure-tested underground well loop within the rock formation and are in a heat transfer configuration with it, the second pressure-tested underground well loop being configured to receive a working fluid that can undergo a phase change between liquid and gas within the second pressure-tested underground well loop as a result of heat transferred from the rock formation, and the system is, A second pump, fluidly connected to the second insulated injection pipe, further comprising a second pump configured to circulate the working fluid through the pressure-tested underground well loop, The second common well segment is fluidly connected to the turbine system, which is configured to receive the working fluid from the first production well of the first pressure-tested underground well loop and the second production well of the second pressure-tested underground well loop. The cooler is fluid-connected to both the first pump connected to the first insulated injection pipe and the second pump connected to the second insulated injection pipe. The system according to claim 34.

36. The system according to claim 35, wherein the second multi-branch connector of the second pressure-tested underground well loop is located within the lateral segment of the access well at a position spaced apart from the first multi-branch connector.

37. The system according to claim 35 or 36, wherein the lateral segment of the access well is a first lateral segment, the second multi-branch connector of the second pressure-tested underground well loop is located within the second lateral segment of the access well, and the second lateral segment of the access well is spaced apart from the first lateral segment of the access well.

38. The system according to claim 37, wherein the first lateral segment is located at a different depth from the second lateral segment.

39. The aforementioned system is 30,100m ２ The system according to any one of claims 35 to 38, having a ground surface area.

40. A system for generating energy from geothermal sources, A common well segment extending into a bedrock layer underground, comprising a common well segment having an upper end and a lower end, An insulated production pipe extending underground into a bedrock layer, wherein a portion of the insulated production pipe is located in the same place as the common well segment, and the insulated production pipe is fluidly isolated from the common well segment, and An injection well extending further underground from the lower end of the common well segment, having an upper end and a lower end, the upper end of the injection well being fluidly connected to the common well segment, A production well extending further underground from the lower end of a common well segment, having an upper end and a lower end, the upper end of the production well being fluidly connected to the insulated production pipe, and A first lateral section connected to a position along the injection well and extending away from there, A second lateral section connected to a position along the aforementioned production well and extending away from it, The device comprises a multi-branch connector that joins the first lateral section and the second lateral section, Each of the common well segment, the injection well, the production well, and the first and second lateral sections is cased with steel and fixed in place with cement within the rock layer. The common well segment, the injection well, the first lateral section, the multi-branch connector, the second lateral section, the production well, and the insulated production pipe cooperate to define a pressure-tested underground well loop within the rock formation and to configure heat transfer with it, the pressure-tested underground well loop being configured to receive a working fluid that can undergo a phase change between liquid and gas within the pressure-tested underground well loop as a result of heat transferred from the rock formation, and the system is A pump fluid-connected to the common well segment, configured to circulate the working fluid through a pressure-tested underground well loop, A turbine system fluidly connected to the aforementioned insulated production pipe, the turbine system being capable of operating to convert mechanical energy generated from the flow of a working fluid into electricity, A cooler is fluid-connected between the pump and the turbine system to cool the working fluid, A system equipped with these features.

41. A method for generating energy from geothermal sources, To provide a pressure-tested underground well loop extending into a bedrock layer underground, wherein the pressure-tested underground well loop is The invention includes an insulated injection pipe, an injection well, a production well, a first lateral section connected to the injection well, a second lateral section connected to the production well, a multi-branch connector connecting the first lateral section and the second lateral section, and a common well segment, wherein a portion of the insulated injection pipe is located in the same place as the common well segment. Each of the injection wells, production wells, the first and second lateral sections, and the common well segment is cased with steel and fixed in place with cement within the rock mass. The working fluid is transported through the pressure-tested underground well loop, the working fluid being received in liquid form by the adiabatic injection pipe, While the working fluid is being transported through the pressure-tested underground well loop, Transferring heat from the surrounding bedrock layer to the liquid working fluid and applying pressure to the liquid working fluid, The process involves inducing a phase change in the working fluid from a liquid state to a gaseous state, wherein the working fluid exits the common well segment in a gaseous state. Converting the mechanical energy generated from the flow of the gaseous working fluid into electricity, To cool the working fluid and induce a phase change in the working fluid to a liquid state, Returning the working fluid to the adiabatic injection pipe, Methods that include...

42. The method according to claim 41, wherein transporting the working fluid through the pressure-tested underground well loop includes pumping the working fluid.

43. The method according to claim 41 or 42, wherein applying pressure to the liquid working fluid includes applying 7 MPa to 31 MPa to the liquid working fluid.

44. The method according to any one of claims 41 to 43, wherein the step of converting the mechanical energy generated from the flow of the gaseous working fluid into electricity generates an output power of 0.5 to 2 MW.

45. The method according to any one of claims 41 to 44, wherein the step of cooling the working fluid and causing the phase change of the working fluid is cooled using a cooler.

46. The method according to any one of claims 41 to 45, further comprising storing excess working fluid in a storage tank.

47. The method according to any one of claims 41 to 46, wherein the working fluid is a homogeneous working fluid.

48. The method according to any one of claims 41 to 46, wherein the working fluid is a heterogeneous working fluid.

49. The method according to any one of claims 41 to 48, wherein the working fluid is selected from the group consisting of refrigerants, hydrocarbon fluids, ammonia, carbon dioxide, and water.

50. The method according to claim 49, wherein the hydrocarbon working fluid is selected from the group consisting of propane, ethane, pentane, butane, and hydrocarbon blends.

51. The method according to any one of claims 41 to 50, wherein the working fluid is propane.

52. The method according to claim 51, wherein the propane received by the insulated injection pipe has a temperature of 10°C to 40°C and a pressure of 1000 kPag to 2000 kPag.

53. The method according to claim 52, wherein the propane received by the insulated injection pipe has a temperature of 20°C and a pressure of 1300 kPag.

54. The method according to any one of claims 51 to 53, wherein when the propane reaches a temperature of 140°C and a pressure of 6250 kPag, a phase change from a liquid state to a gaseous state of the propane is induced.

55. The method according to claim 54, wherein the induction of the phase change of propane from a liquid state to a gaseous state occurs in any one of the second lateral section, the production well, and the common well segment.

56. The method according to any one of claims 51 to 55, wherein the propane exiting the common well segment in a gaseous state has a temperature of 90°C to 110°C and a pressure of 3000 kPag to 4000 kPag.

57. The method according to claim 56, wherein the propane exiting the common well segment in a gaseous state has a temperature of 106°C and a pressure of 3500 kPag.

58. The method according to any one of claims 51 to 57, wherein, while the working fluid is transported through the pressure-tested underground well loop, the temperature of the propane rises by 76°C and the pressure of the propane rises by 2170 kPag.

59. The method according to any one of claims 51 to 58, wherein, after converting the mechanical energy generated from the flow of the gaseous working fluid into electricity, the propane has a temperature of 16°C to 63°C and a pressure of 700 kPag to 1500 kPag.

60. The method according to any one of claims 51 to 59, wherein the propane is cooled to a temperature of 30°C and a pressure of 1080 kPag by cooling the working fluid.

61. The method according to any one of claims 51 to 60, further comprising using a reheater to transfer heat from the working fluid in a first region to the working fluid in a second region, wherein the working fluid in the first region is generated between the step of converting the mechanical energy generated from the flow of the gaseous working fluid and the step of cooling the working fluid, and the working fluid in the second region is generated between the step of transporting the working fluid through the pressure-tested underground well loop and the step of receiving the working fluid in liquid state through the adiabatic injection pipe.

62. A method for constructing a pressure-tested underground well loop for a system for generating energy from a geothermal source, wherein the pressure-tested underground well loop is configured to transfer heat from the surrounding rock layer to a working fluid flowing within the pressure-tested underground well loop, thereby inducing a phase change of the working fluid from a liquid state to a gaseous state, and the method is To provide access wells that extend into bedrock layers underground, The common well segment is to be excavated in the aforementioned underground rock layer, wherein the common well segment has an upper end and a lower end. Installing the first steel casing for the common well segment, The first steel casing for the common well segment is fixed with cement at a predetermined position within the rock layer, Further underground drilling of a production well from the lower end of the common well segment to the first proposed intersection, The first lateral section is excavated along the access well to the first proposed intersection, Connecting the first lateral section and the production well at the first proposed intersection, Installing the production well and the second steel casing for the first lateral section, The second steel casing and the first lateral section for the production well are fixed in place in the rock layer with cement, The method involves drilling the injection well further underground from the lower end of the common well segment to the second proposed intersection, wherein the injection well has an upper end and a lower end. The method involves excavating a second lateral section along the access well to the second proposed intersection, wherein the excavation of the first lateral section along the access well and the excavation of the second lateral section along the access well begin in close proximity to each other along the access well. Connecting the second lateral section and the injection well at the second proposed intersection, Installing the second lateral section and the third steel casing for the injection well, The third steel casing for the second lateral section and the injection well are fixed in place in the rock layer with cement, To provide a multi-branch connector through the access well, and to install the multi-branch connector at the connection point between the first and second lateral sections, The present invention provides an insulated injection pipe fluidly connected to the upper end of the injection well, wherein a portion of the insulated injection pipe is located in the same place as the common well segment. The method involves pressure testing the underground well loop, wherein the underground well loop includes the insulated injection pipe, the injection well, the first lateral section, the multi-branch connector, the second lateral section, the production well, and the common well segment. Methods that include...

63. A system for generating energy from geothermal sources, A first common well segment and a second common well segment extending underground into a bedrock layer, wherein each of the first and second common well segments has an upper end and a lower end, A first insulated injection pipe and a second insulated injection pipe extending underground into a bedrock layer, wherein a portion of the first insulated injection pipe is located in the same location as the first common well segment, and a portion of the second insulated injection pipe is located in the same location as the second common well segment, and each of the first and second insulated injection pipes has an upper end and a lower end, A first injection well extending further underground from the lower end of the first common well segment, and a second injection well extending further underground from the lower end of the second common well segment, wherein each of the first and second injection wells has an upper end and a lower end, the upper end of the first injection well is fluidly connected to the first insulated injection pipe, and the upper end of the second injection well is fluidly connected to the second insulated injection pipe, the first injection well and the second injection well, A first production well extending further underground from the lower end of the first common well segment, and a second production well extending further underground from the lower end of the second common well segment, wherein each of the first and second production wells has an upper end and a lower end, the upper end of the first production well is fluidly connected to the first common well segment, and the upper end of the second production well is fluidly connected to the second common well segment, the first production well and the second production well, A first lateral section connected to and extending away from the first injection well, A second lateral section connected to a position along the first production well and extending away from there, A third lateral section connected to and extending away from the second injection well, A fourth lateral section connected to a position along the second production well and extending away from there, A first multi-branch connector that joins the first lateral section and the second lateral section, The present invention further comprises a second multi-branch connector that joins the third lateral section and the fourth lateral section, Each of the first and second common well segments, the first and second injection wells, the first and second production wells, and the first, second, third, and fourth lateral sections is cased with steel and fixed in place with cement within the rock layer. The first insulated injection pipe, the first injection well, the first lateral section, the first multi-branch connector, the second lateral section, the first production well, and the first common well segment cooperate to define a first pressure-tested underground well loop within the rock mass, and the second insulated injection pipe, the second injection well, the third lateral section, the second multi-branch connector, the fourth lateral section, the second production well, and the second common well segment cooperate to define a second pressure-tested underground well loop within the rock mass, and are in a heat transfer configuration with the rock mass, and each of the first and second pressure-tested underground well loops is configured to receive a working fluid that can undergo a phase change between liquid and gas as a result of heat transferred from the rock mass, and the system is, A first pump fluid-connected to the first insulated injection pipe, the first pump configured to circulate the working fluid through the first pressure-tested underground well loop, A second pump, fluid-connected to the second insulated injection pipe, is configured to circulate the working fluid through the second pressure-tested underground well loop, A turbine system, which is fluidly connected to the first and second common well segments and is capable of operating to convert mechanical energy generated from the flow of working fluid into electricity, A system comprising: a cooler fluidly connected between the first and second pumps and the turbine system, which is operable to cool the working fluid received from the turbine system and to supply the cooled working fluid to both the first and second pumps, wherein the first and second pressure-tested underground well loops are located in close proximity to each other.

64. A system for generating energy from geothermal sources, A common well segment extending into a bedrock layer underground, comprising a common well segment having an upper end and a lower end, An insulated injection pipe extending underground into a bedrock layer, wherein a portion of the insulated injection pipe is located in the same place as the common well segment, and the insulated injection pipe is fluidly isolated from the common well segment, and An injection well extending further underground from the lower end of the common well segment, having an upper end and a lower end, the upper end of the injection well being fluidly connected to the adiabatic injection pipe, A production well extending further underground from the lower end of the common well segment, having an upper end and a lower end, the upper end of the production well being fluidly connected to the common well segment, A first lateral section connected to a position along the injection well and extending away from there, A second lateral section connected to a position along the aforementioned production well and extending away from it, The device comprises a multi-branch connector that joins the first lateral section and the second lateral section, Each of the common well segment, the injection well, the production well, and the first and second lateral sections is cased with steel and fixed in place with cement within the rock layer. The insulated injection pipe, the injection well, the first lateral section, the multi-branch connector, the second lateral section, the production well, and the common well segment cooperate to define a pressure-tested underground well loop within the rock formation in a heat transfer configuration with respect to it, the pressure-tested underground well loop being configured to withstand a pressure of at least 7 MPa and to receive a working fluid that can undergo a phase change between liquid and gas within the pressure-tested underground well loop as a result of heat transferred from the rock formation, the system is, A pump fluid-connected to the insulated injection pipe, configured to circulate the working fluid through the pressure-tested underground well loop, A turbine system, which is fluidly connected to the common well segment and is capable of operating to convert mechanical energy generated from the flow of working fluid into electricity, A cooler is fluid-connected between the pump and the turbine system to cool the working fluid, A system equipped with these features.

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