System for generating energy from a ground heat source and method of operating and

Abstract

A system and method for generating energy from a geothermal source is described. The system includes insulated injection tubes and a common well section, injection wells and production wells, a first lateral section connected to the injection wells and a second lateral section connected to the production wells, and a multi-branch connector combining the first lateral section and the second lateral section, the insulated injection tubes coincide with the common well section, a pressure-tested loop is defined within the formation and in a heat transfer arrangement with the formation. The loop is sleeved with a steel sleeve and fixed in place through cement. The loop is to receive a working fluid capable of phase change within the downhole circulation circuit due to heat transferred from the formation. The system also includes a pump for circulating the working fluid, a turbine system for converting the flow of working fluid to electrical power, and a cooler.

Description

Technical Field

[0001] The present invention generally relates to generating energy from a geothermal source, and more specifically to a system for generating energy from a geothermal source and a method for operating and constructing the system. Background Technology

[0002] Systems used to generate energy from geothermal sources (also referred to herein as geothermal power generation systems) are designed to circulate a working fluid, or water, underground for heating, then bring the heat back to the surface to be converted into electricity. The working fluid or water is then cooled and returned to the underground heat source.

[0003] In some known geothermal power generation systems, the underground flowing working fluid is exposed to underground rock formations, allowing the initial working fluid to pick up debris, rock, and other solids as it flows underground. The picking up of debris, rock, and other solids can cause problems for any equipment with moving parts, such as pumps that need to help circulate the working fluid, or turbines used to generate electricity from the heat energy from the working fluid as it returns to the surface.

[0004] One solution to this problem is to provide a filter along the flow path of the working fluid or before the working fluid enters any machinery. Filters can help reduce the amount of debris or solids carried into the machinery by the working fluid. However, this requires changing the filter, thus increasing maintenance costs. Furthermore, the filter is an added component, and therefore introduces another potential point of failure into the system.

[0005] Another approach to addressing debris in the working fluid is to use a dual-cycle power plant. This involves two working fluids: a first working fluid is heated underground, and the heat is then transferred to an isolated second working fluid that passes through a second loop, where it is heated and used to power the turbine. While this reduces the likelihood of debris encountering the turbine, the pumps required to circulate the first working fluid underground still need to contend with debris issues. Furthermore, dual-cycle power plants are not efficient because they have high parasitic loads and can lose significant amounts of heat when transferring heat from the first to the second working fluid.

[0006] Furthermore, the working fluid circulating underground can also begin to erode the rock surface along its flow path. Erosion of the rock surface can destabilize the underground pathways and may also cause environmental damage. Therefore, to prevent erosion, the flow rate of the working fluid must be minimized to protect the integrity of the rock strata. This will result in an increased residence time of the working fluid underground.

[0007] When the working fluid flows underground, it can also leak into the surrounding environment through gaps in the underground rock strata, causing underground pollution. Therefore, for it to be environmentally friendly, the working fluid needs to be an environmentally friendly fluid, such as water. Even so, if the initial working fluid absorbs any non-environmentally friendly substances (such as absorbing oil while flowing through the pump) as it flows along its path, it may still leak into the external environment.

[0008] In other known geothermal power systems, chemical layers, chemical treatment layers, or polymer coatings are provided to prevent erosion, environmental leaks, and to prevent debris from being contained in the working fluid along the underground loop. The polymer coating is applied to the rock formation and seals it, isolating it from the circulating fluid. However, some inherent drawbacks of polymer coatings include the inability to pressure test underground loops with polymer coatings. Without pressure testing of the underground loop, there is no guarantee that the polymer coating will remain at depths where the working fluid is subjected to high pressure, or that the polymer coating will react with different working fluids, and therefore, leaks, including underground contamination, are possible.

[0009] Furthermore, the polymer coating itself is susceptible to erosion, and once eroded, it can lead to the erosion of the rock strata. This results in contamination of the primary working fluid. To prevent this, the polymer coating may need to be applied in multiple layers and may require continuous replacement, leading to high maintenance costs, additional downtime, and lost production time. Even after the polymer coating is applied, it is difficult to verify that the entire rock strata and the path / loop of the primary working fluid have been covered, let alone ensure the thickness or integrity of the polymer coating.

[0010] In other prior art (e.g., U.S. Patent Application Publication No. 2018 / 0291880 and International Patent Application Publication No. WO 2022029699), a casing is provided; however, this casing is not cemented, which may lead to instability. Furthermore, this casing has not undergone pressure testing, which may become unstable at depths with high pressure or with working fluids at high or varying flow rates underground. This instability can lead to poor operational performance and potential underground contamination, especially since the working fluids provided in the aforementioned patent applications, which use two different working fluids, are not water. Underground contamination can occur due to leakage of the working fluid into fissures in the rock formation. These fissures can be pre-existing, unknown fractures, or fractures created during the construction of the geothermal power system due to drilling. If any leakage of the working fluid occurs, the fluid can be transported through these fissures and into sensitive resources such as groundwater.

[0011] In other prior art (e.g., U.S. Patent Application Publication No. 2011 / 0048005), a single cemented continuous pipe is used, running through two connected wells and extending the length of both wells, specifically from the injection wellhead of one well, down into a near-horizontal underground pipe, and up back to the production wellhead. This allows the working fluid to be transported underground, undergoing a phase change due to heat from the surrounding underground rock, and then transported back to the surface for use in a power plant. Only a single underground horizontal pipe connection exists between the injection and production wellheads. In this type of system, the distance between the single underground horizontal pipe and the injection and production wellheads tends to be quite long to allow for sufficient heat transfer between the rock formation and the production fluid. This large distance between the injection and production wellheads tends to result in a large footprint both above and below ground. This increases the overall cost of the system because an additional length of pipe is required above the surface between the injection wellhead and the production wellhead, for which there is an additional volume of working fluid, and potentially increased parasitic loads due to heat loss from the extra time the production fluid spends above the surface. Furthermore, the construction technique described in U.S. Patent Application Publication No. 2011 / 0048005 does not allow for pressurized connections between the two sections.

[0012] Thus, it is advantageous to obtain a solution in which the geothermal power generation system may have an underground loop that includes barriers capable of pressure testing and poses minimal risk of erosion, debris ingress, and leakage into the surrounding rock and environment. Furthermore, solutions with minimal maintenance, cost savings, minimized downtime, and fewer points of failure within the system are also beneficial. Summary of the Invention

[0013] According to a broad aspect of the invention, a system for generating energy from a geothermal source is provided. The system includes a common well section extending underground into a rock formation. The common well section has an upper end and a lower end. The system also includes an insulated injection pipe extending underground into the rock formation. A portion of the insulated injection pipe is co-located with the common well section. The insulated injection pipe is also fluidly isolated from the common well section. The system also includes an injection well extending deeper underground from the lower end of the common well section. The injection well also has an upper end and a lower end, wherein the upper end of the injection well is fluidly connected to the insulated injection pipe. Furthermore, the system includes a production well extending deeper underground from the lower end of the common well section. The production well also has an upper end and a lower end, wherein the upper end of the production well is fluidly connected to the common well section. The system also includes a first lateral section connected to a location along the injection well and extending away from that location. The system also includes a second lateral section connected to a location along the production well and extending away from that location. The system also includes a multi-branch connector combining the first and second lateral sections. The common section, injection well, production well, first lateral section, and second lateral section are encased in steel casing and cemented in place within the rock formation. Furthermore, the insulated injection pipe, injection well, first lateral section, multi-branch connector, second lateral section, production well, and common section cooperate with each other to define a pressure-tested downhole circulation loop within the rock formation and are arranged in a heat-transfer configuration with the rock formation. The pressure-tested downhole circulation loop is configured to receive working fluid capable of undergoing a phase change between liquid and gaseous states within the pressure-tested downhole circulation loop due to heat transferred from the rock formation. The system also includes a pump fluidly connected to the insulated injection pipe, wherein the pump circulates the working fluid through the pressure-tested downhole circulation loop. The system also includes a turbine system fluidly connected to the common section, wherein the turbine system is operable to convert the mechanical energy generated by the flow of the working fluid into electrical energy. Additionally, the system includes a cooler fluidly connected between the pump and the turbine system for cooling the working fluid.

[0014] In one feature, the system may include a surface casing with an opening around the common well section. The surface casing may be partially above the surface and may prevent the working fluid from escaping into the rock formation.

[0015] In another feature, the system can have 30100m 2 The surface area above ground.

[0016] In another feature, the working fluid can be a homogeneous working fluid.

[0017] In another feature, the working fluid can be a non-homogeneous working fluid.

[0018] Another feature is that the common well section can have a depth of approximately 650 m.

[0019] Preferably, the first lateral section extends away from the injection well at a depth between 1000 m and 3500 m.

[0020] Preferably, the second lateral section extends away from the production well at a depth between 1,000 m and 3,500 m.

[0021] Preferably, the length of the first lateral segment is between 2000 m and 4000 m.

[0022] Preferably, the second lateral segment has a length between 2000 m and 4000 m.

[0023] Optionally, the depth of the first lateral segment is greater than the depth of the second lateral segment.

[0024] Optionally, the second lateral segment may be deeper than the first lateral segment.

[0025] Alternatively, the first lateral segment may be at the same depth as the second lateral segment, and the first lateral segment may be spaced apart from the second lateral segment.

[0026] In one feature, during operation, the pressure-tested downhole circulation loop can receive fluids at pressures between 7 MPa and 31 MPa.

[0027] Another feature is that the pressure-tested downhole circulation loop can withstand pressures of at least 7 MPa.

[0028] In one feature, the pump can be a positive displacement pump with a variable speed drive controller.

[0029] In another feature, the positive displacement pump can be selected from the group consisting of: plunger pumps, gear pumps and rotary vane pumps.

[0030] In another feature, the turbine system may include an expansion turbine.

[0031] Another feature is that the turbine system is capable of generating output power between 0.5 MW and 2 MW.

[0032] In one feature, the cooler can use ambient air as a coolant.

[0033] 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.

[0034] In one feature, the working fluid can be a refrigerant, a hydrocarbon-based fluid, ammonia, carbon dioxide, or water.

[0035] Optionally, when the working fluid is a hydrocarbon-based working fluid, the working fluid may be propane, ethane, pentane, butane, or a mixture of hydrocarbons.

[0036] Preferably, the working fluid is propane.

[0037] In one embodiment, the system may include a co-current heat exchanger having a first flow channel connecting the turbine system and the cooler, and a second flow channel connecting the pump and the insulated injection pipe. The co-current heat exchanger can transfer heat from the first flow channel to the second flow channel.

[0038] In another feature, the insulation injection pipe can be a steel pipe coated with an insulating compound.

[0039] In another feature, a portion of the insulated injection pipe can extend along the central axis of the common well section.

[0040] In another feature, the upper end of the injection well may include a downwardly angled section, and the lower end of the injection well may include a vertical section.

[0041] Preferably, the majority of the injection well is separated from the production well.

[0042] More preferably, the majority of the injection well is separated from the production well by a lateral distance of at least 80 m.

[0043] In one feature, the system may further include a geothermal isolation joint positioned along the lower portion of the common well section. An insulated injection pipe can be connected to the injection well via the geothermal isolation joint. The system may also include an isolation packer positioned along the upper portion of the production well. Furthermore, the system may include an insulated production pipe fluidly connecting the production well and the common well section. A portion of the insulated production pipe may extend between the isolation packer and the geothermal isolation joint. The geothermal isolation joint isolates the working fluid in the insulated injection pipe from the working fluid in the insulated production pipe.

[0044] In one feature, a portion of the insulated injection pipe is co-located concentrically with the common well section.

[0045] Alternatively, a portion of the insulated injection pipe is positioned eccentrically with the common well section.

[0046] In one feature, the system may include an access well with lateral sections. A multi-branch connector may be positioned within the lateral section of the access well.

[0047] In another feature, where the common well section is a first common well section, the insulated injection pipe is a first insulated injection pipe, the injection well is a first injection well, the production well is a first production well, the multi-branch connector is a first multi-branch connector, the pressure-tested downhole circulation loop is a first pressure-tested downhole circulation loop, and the pump is a first pump, the system may include a second common well section extending underground into the rock formation. The second common well section may have an upper end and a lower end. The system may also include a second insulated injection pipe extending underground into the rock formation. A portion of the second insulated injection pipe is co-located with the second common well section. The second insulated injection pipe is fluidly isolated from the second common well section. The system also includes a second injection well extending deeper underground from the lower end of the second common well section. The second injection well has an upper end and a lower end. The upper end of the second injection well is fluidly connected to the second insulated injection pipe. The system also includes a second production well extending deeper underground from the lower end of the second common well section. The second production well has an upper end and a lower end. The upper end of the second production well is fluidly connected to the common well section. The system also includes a third lateral section connected to and extending away from a location along the second injection well. The system also includes a fourth lateral section connected to and extending away from a location along the second production well. Furthermore, the system includes a second multi-branch connector combining the third and fourth lateral sections. Each of the second common well section, the second injection well, the second production well, the third lateral section, and the fourth lateral section is fitted with a steel casing and cemented in place within the rock formation. 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 section, which cooperate to define a second pressure-tested downhole circulation loop within the rock formation and are arranged in a heat-transferring manner with the rock formation. Furthermore, the second pressure-tested downhole circulation loop can receive working fluid that can undergo a phase change between liquid and gaseous states within the second pressure-tested downhole circulation loop due to heat transferred from the rock formation. The system also includes a second pump fluidly connected to a second insulated injection pipe. The second pump circulates the working fluid through a pressure-tested downhole circulation loop. Additionally, a second common well section is fluidly connected to a turbine system. This turbine system receives working fluid from a first production well in the first pressure-tested downhole circulation loop and a second production well in the second pressure-tested downhole circulation loop. Furthermore, a cooler is fluidly connected to both the first pump connected to the first insulated injection pipe and the second pump connected to the second insulated injection pipe.

[0048] In one feature, the second multi-branch connector of the second pressure-tested downhole circulation loop is positioned at a location spaced apart from the first multi-branch connector within the lateral section entering the well.

[0049] Alternatively, the lateral section of the well access is a first lateral section, and a second multi-branch connector of a second pressure-tested downhole circulation loop is located within the second lateral section of the well access. This second lateral section of the well access may be spaced apart from the first lateral section of the well access.

[0050] In another feature, the depth of the first lateral segment differs from the depth of the second lateral segment.

[0051] In yet another characteristic, the system has 30100 m 2 The surface area above ground.

[0052] According to another aspect of the invention, a system for generating energy from a geothermal source is provided. The system includes a common well section extending underground into a rock formation. The common well section has an upper end and a lower end. The system also includes an insulated production pipe extending underground into the rock formation. A portion of the insulated production pipe is co-located with the common well section. The insulated production pipe is fluidly isolated from the common well section. The system also includes an injection well extending deeper underground from the lower end of the common well section. 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 section. The system also includes a production well extending deeper underground from the lower end of the common well section. 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 that location. The system also includes a second lateral section connected to a location along the production well and extending away from that location. The system also includes a multi-branch connector combining the first and second lateral sections. Each of the common section, injection well, production well, and first and second lateral sections is casing a steel tube and cemented in place within the rock formation. The common section, 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 downhole circulation loop within the rock formation and are arranged in a heat-transferring manner with the rock formation. The pressure-tested downhole circulation loop receives working fluid that undergoes a phase change between liquid and gaseous states within the pressure-tested downhole circulation loop due to heat transferred from the rock formation. The system includes a pump fluidly connected to the common section. This pump circulates the working fluid through the pressure-tested downhole circulation loop. The system also includes a turbine system fluidly connected to the insulated production pipe. The turbine system is operable to convert the mechanical energy generated by the flow of the working fluid into electrical energy. The system also includes a cooler fluidly connected between the pump and the turbine system for cooling the working fluid.

[0053] According to another aspect of the invention, a method for generating energy from a geothermal source is provided. The method includes providing a pressure-tested downhole circulation loop extending underground into rock formations. The pressure-tested downhole circulation 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 combining the first and second lateral sections, and a common well section. A portion of the insulated injection pipe is co-located with the common well section. Each of the injection well, production well, first and second lateral sections, and common well section is sleeved with a steel casing and cemented in place within the rock formation. The method also includes delivering a working fluid through the pressure-tested downhole circulation loop. The working fluid is received in a liquid state by the insulated injection pipe. Simultaneously with delivering the working fluid through the pressure-tested downhole circulation loop, the method further includes transferring heat from the surrounding rock formations to the liquid working fluid and applying pressure to the liquid working fluid. In addition to delivering the working fluid through a pressure-tested downhole circulation loop, the method also includes inducing a phase change in the working fluid from a liquid to a gaseous state. The working fluid leaves the common well section in a gaseous state. The method includes converting the mechanical energy generated by the flow of the gaseous working fluid into electrical energy. The method also includes cooling the working fluid and inducing a phase change back to a liquid state. The method further includes returning the working fluid to the insulated injection pipe.

[0054] In one feature, delivering the working fluid through a pressure-tested downhole circulation loop includes pumping the working fluid.

[0055] In another feature, applying pressure to the liquid working fluid includes applying a pressure between 7 MPa and 31 MPa to the liquid working fluid.

[0056] In another feature, the output power generated by the step of converting the mechanical energy generated by the flow of the gaseous working fluid into electrical energy is between 0.5 MW and 2 MW.

[0057] In another feature, the step of cooling the working fluid and initiating a phase change in the working fluid is achieved by using a cooler.

[0058] Optionally, the method may include storing excess working fluid in a storage tank.

[0059] In one characteristic, the working fluid is a homogeneous working fluid.

[0060] Alternatively, the working fluid may be a non-homogeneous working fluid.

[0061] In one feature, the working fluid can be a refrigerant, a hydrocarbon-based fluid, ammonia, carbon dioxide, or water.

[0062] When the working fluid is a hydrocarbon-based working fluid, the working fluid can be propane, ethane, pentane, butane, or a mixture of hydrocarbons.

[0063] Alternatively, the working fluid is propane.

[0064] In one feature, the propane received by the insulated injection pipe can have a temperature of 10°C to 40°C and a pressure of 1000 kPag to 2000 kPag.

[0065] Alternatively, the propane received by the insulated injection pipe can have a temperature of 20°C and a pressure of 1300 kPag.

[0066] In one feature, propane undergoes a phase transition from a liquid to a gaseous state when it reaches a temperature of 140°C and a pressure of 6250 kPag.

[0067] In another feature, the phase transition of propane from a liquid to a gaseous state occurs in the second lateral section, the production well, or the common well section.

[0068] In one feature, propane leaving the common well section in a gaseous state can have a temperature between 90°C and 110°C and a pressure between 3000 kPag and 4000 kPag.

[0069] Alternatively, propane leaving the common well section in a gaseous state can have a temperature of 106°C and a pressure of 3500 kPag.

[0070] In one feature, when the working fluid is delivered through a pressure-tested downhole circulation loop, the temperature of propane increases by 76°C and the pressure of propane increases by 2170 kPag.

[0071] In another feature, propane can have a temperature between 16°C and 63°C and a pressure between 700 kPag and 1500 kPag after the mechanical energy generated by the flow of the gaseous working fluid is converted into electrical energy.

[0072] In another feature, the cooling working fluid cools propane to a temperature of 30°C and a pressure of 1080 kPag.

[0073] In one embodiment, the method includes using a co-current heat exchanger to transfer heat from the working fluid in a first region to the working fluid in a second region. The working fluid in the first region occurs between the step of converting the mechanical energy generated by the flow of the gaseous working fluid and the step of cooling the working fluid. The working fluid in the second region occurs between the step of delivering the working fluid through a pressure-tested downhole circulation loop and the step of receiving the working fluid in a liquid state by an insulated injection pipe.

[0074] According to another aspect of the invention, a method is provided for constructing a pressure-tested downhole circulation loop for a system to generate energy from a geothermal source. The pressure-tested downhole circulation loop transfers heat from surrounding rock formations to a working fluid flowing within the pressure-tested downhole circulation loop, causing a phase change in the working fluid from liquid to gaseous. The method includes providing an entry well extending underground into the rock formations. The method also includes drilling a common well section into the underground rock formations. The common well section has an upper end and a lower end. The method further includes installing a first steel casing for the common well section. The method also includes cementing the first steel casing for the common well section in place within the rock formations. The method further includes drilling a production well further underground from the lower end of the common well section to a first intended intersection point. The method includes drilling a first lateral section from along the entry well to the first intended intersection point. The method also includes connecting the first lateral section to the production well at the first intended intersection point. The method further includes installing a second steel casing for the production well and the first lateral section. The method further includes cementing a second steel casing for the production well and the first lateral section in place within the rock formation. The method includes drilling an injection well further underground from the lower end of the common well section to a second intended intersection point. The injection well has an upper end and a lower end. The method also includes drilling a second lateral section from along the entry well to the second intended intersection point. The first lateral section and the second lateral section are adjacent to each other along the entry well, with the first lateral section and the second lateral section adjacent to each other along the entry well. The method further includes connecting the second lateral section and the injection well at the second intended intersection point. The method also includes installing a third steel casing for the second lateral section and the injection well. The method further includes cementing the third steel casing for the second lateral section and the injection well in place within the rock formation. The method includes providing a multi-branch connector through the entry well and installing the multi-branch connector at the connection point between the first lateral section and the second lateral section. The method also includes providing a thermally insulated injection pipe with fluid connection to the upper end of the injection well. A portion of the thermally insulated injection pipe is co-located with the common well section. The method also includes a pressure test downhole circulation loop, wherein the downhole circulation loop includes an insulated injection pipe, an injection well, a first lateral section, a multi-branch connector, a second lateral section, a production well, and a common well section.

[0075] According to another aspect of the invention, a system for generating energy from a geothermal source is provided. The system includes a first common well section and a second common well section extending underground into a rock formation. The first and second common well sections each have an upper end and a lower end. The system also includes a first insulated injection pipe and a second insulated injection pipe extending underground into the rock formation. A portion of the first insulated injection pipe is co-located with the first common well section. Furthermore, a portion of the second insulated injection pipe is co-located with the second common well section. The first and second insulated injection pipes each have an upper end and a lower end. The system also includes a first injection well extending deeper underground from the lower end of the first common well section. The system also includes a second injection well extending deeper underground from the lower end of the second common well section. The first and second injection wells each have an upper end and a lower end. The upper end of the first injection well is fluidly connected to the first insulated injection pipe. Furthermore, the upper end of the second injection well is fluidly connected to the second insulated injection pipe. The system also includes a first production well extending deeper underground from the lower end of the first common well section. The system also includes a second production well extending deeper underground from the lower end of the second common well section. The first and second production wells each have an upper and a lower end. The upper end of the first production well is fluidly connected to a first common well section. The upper end of the second production well is fluidly connected to a second common well section. The system also includes a first lateral section connected to and extending away from a location along the first injection well. The system also includes a second lateral section connected to and extending away from a location along the first production well. The system also includes a third lateral section connected to and extending away from a location along the second injection well. The system also includes a fourth lateral section connected to and extending away from a location along the second production well. The system includes a first multi-branch connector that combines the first and second lateral sections. The system also includes a second multi-branch connector that combines the third and fourth lateral sections. Each of the first and second common well sections, the first and second injection wells, the first and second production wells, the first lateral section, the second lateral section, the third lateral section, and the fourth lateral section is fitted with a steel casing and cemented in place within the rock formation. 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 section, which cooperate to define a first pressure-tested downhole circulation loop within the rock formation. 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 section, which cooperate to define a second pressure-tested downhole circulation loop within the rock formation. Both the first and second pressure-tested downhole circulation loops are arranged for heat transfer with the rock formation.Each of the first and second pressure-tested downhole circulation loops receives working fluid capable of undergoing a phase change between liquid and gaseous states due to heat transfer from the rock formation. The system includes a first pump fluidly connected to a first insulated injection pipe. The first pump circulates the working fluid through the first pressure-tested downhole circulation loop. The system also includes a second pump fluidly connected to the second insulated injection pipe. The second pump circulates the working fluid through the second pressure-tested downhole circulation loop. The system includes a turbine system fluidly connected to a first and second common well section, which converts the mechanical energy generated by the working fluid flow into electrical energy. The system also includes a cooler fluidly connected between the first and second pumps and the turbine system, 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 downhole circulation loops are adjacent to each other.

[0076] A system for generating energy from a geothermal source. The system includes a common well section extending underground into rock formations. The common well section has an upper end and a lower end. The system also includes an insulated injection pipe extending underground into rock formations. A portion of the insulated injection pipe is co-located with the common well section. The insulated injection pipe is fluidly isolated from the common well section. The system also includes an injection well extending deeper underground from the lower end of the common well section. The injection well has an upper end and a lower end. The upper end of the injection well is fluidly connected to the insulated injection pipe. The system also includes a production well extending deeper underground from the lower end of the common well section. The production well has an upper end and a lower end. The upper end of the production well is fluidly connected to the common well section. The system also includes a first lateral section connected to a location along the injection well and extending away from that location. The system also includes a second lateral section connected to a location along the production well and extending away from that location. The system includes a multi-branch connector combining the first and second lateral sections. Each of the common well section, injection well, production well, first lateral section, and second lateral section is casing a steel tube and cemented in place within the rock formation. The system also includes an insulated injection pipe, injection well, first lateral section, multi-branch connector, second lateral section, production well, and common well section, which cooperate to define a pressure-tested downhole circulation loop within the rock formation and are arranged in a heat-transferring manner with the rock formation. The pressure-tested downhole circulation loop withstands a pressure of at least 7 MPa and receives a working fluid capable of undergoing a phase change from liquid to gas within the pressure-tested downhole circulation loop due to heat transfer from the rock formation. The system also includes a pump fluidly connected to the insulated injection pipe. This pump circulates the working fluid through the pressure-tested downhole circulation loop. Furthermore, the system includes a turbine system fluidly connected to the common well section. The turbine system converts the mechanical energy generated from the flow of the working fluid into electrical energy. The system also includes a cooler fluidly connected between the pump and the turbine system for cooling the working fluid. Attached Figure Description

[0077] The embodiments of the present invention will be described in detail below with reference to the accompanying drawings, so as to provide a clearer understanding of the embodiments of the present invention, wherein: Figure 1 A schematic diagram illustrating a system for generating energy from a geothermal source according to an embodiment; Figure 2 for Figure 1 The diagram shown is a conceptual illustration of a system for generating energy from a geothermal source. Figure 3 It is based on Figure 2 Another conceptual schematic diagram of an alternative implementation of a system for generating energy from a geothermal source is shown; Figure 4 It is an explanation of the basis Figure 2The flowchart shown illustrates the steps of a method for generating energy from a geothermal source according to an embodiment. Figure 5 It is an explanation of the basis Figure 3 The flowchart illustrates the steps of an alternative method for generating energy from a geothermal source in the illustrated embodiment. Figure 6A This is a schematic cross-sectional view illustrating an alternative embodiment of a system for generating energy from a geothermal source, which has two full-casing downhole circulation loops connected to a single inlet well. Figure 6B yes Figure 6A A conceptual schematic diagram of an implementation of a system for generating energy from a geothermal source, wherein two full-casing downhole circulation loops are fluidly connected to a single turbine system and a single cooler, and wherein the working fluid is propane; Figure 6C It is a schematic top view of five complete casing downhole circulation loops and a single connecting well; Figure 7A This describes the construction according to an embodiment of the present invention. Figure 1 A first flowchart illustrating the steps of a method for generating energy from a geothermal source; Figure 7B It is immediately following Figure 7A The second flowchart of the steps of a method for constructing a system for generating energy from a geothermal source; Figure 8 It is a descriptive structure used to describe the structure from Figure 1 The schematic cross-sectional view of the initial steps of the geothermal energy generation system shown illustrates the drilled connecting well and common well section; Figure 9 It is a description of structure Figure 1 The schematic cross-sectional view shown is of the second step of the system for generating energy from a geothermal source, illustrating the drilled production well and the first lateral section, wherein the production well and the first lateral section intersect. Figure 10 It is a description of structure Figure 1 The schematic cross-sectional view shown is of the third step of a system for generating energy from a geothermal source. It shows a casing installed along the production well and through a portion of the first lateral section, and also shows a first isolation packer and a first-stage cementing tool installed along the first lateral section near the production well, and a second isolation packer installed along the well between the common section and the production well, with cementing performed between the casing and the wall of the production well and a portion of the first lateral section. Figure 11 It is a description of structure Figure 1The schematic cross-sectional view shown is of the fourth step of the system for generating energy from a geothermal source, showing a first two-part skewing device installed near the first isolation packer, a first opening of the first sleeve window near the first two-part skewing device, a second two-part skewing device installed near the second isolation packer, and a second opening of the second sleeve window near the second two-part skewing device. Figure 12 It is a description of structure Figure 1 The schematic cross-sectional view shown is of the fifth step of the system for generating energy from a geothermal source, illustrating the drilled injection well and the second lateral section; Figure 13 It is a description of structure Figure 1 The schematic cross-sectional view shown is of the sixth step of the system for generating energy from a geothermal source, illustrating the casing installed along the injection well and through the second lateral section; Figure 14 It is a description of structure Figure 1 The schematic cross-sectional view shown is of the seventh step of the system for generating energy from a geothermal source, showing the installation of a third isolation packer and a second-stage cementing tool along the second lateral section near the production well, and a fourth isolation packer along the injection well near the common section, with cementing between the casing and the wall of the injection well and the second lateral section. Figure 15 It is a description of structure Figure 1 The schematic cross-sectional view shown is of the eighth step of the system for generating energy from a geothermal source, illustrating the removal of the cores of the first two-part directional drilling unit and the second two-part directional drilling unit, leaving a first window guide installed between the two lateral connection sections and a second window guide installed between the common section and the production well. Figure 16 It is a description of structure Figure 1 The schematic cross-sectional view shown is of the ninth step of a system for generating energy from a geothermal source, illustrating the installation of a multi-branch connector between two lateral sections along a first window guide, and the connection of the injection well and the production well via the two lateral connection sections and the multi-branch connector; and Figure 17 It is a description of structure Figure 1 The schematic cross-sectional view shown is of the tenth step of the system for generating energy from a geothermal source. It illustrates the installation of a geothermal isolation joint along a second window guide, wherein the first leg of the geothermal isolation joint connects the common section to the production well, and the second leg of the geothermal isolation joint connects the surface to the injection well via an insulated injection pipe. The installation of the geothermal isolation joint provides circulation flow for the working fluid to enable a closed-loop downhole circulation circuit. Detailed Implementation

[0078] The following description and the embodiments described therein are provided by way of illustrating examples of the principles and aspects of the invention or examples of specific embodiments. These examples are provided to illustrate, rather than limit, those principles of the invention. Throughout the following description and drawings, the same parts are labeled with the same corresponding reference numerals.

[0079] As a general overview, a system is provided that generates energy from a geothermal source 100 (also referred to herein as a geothermal power generation system 100) using a single heat exchange loop, wherein system 100 includes a fully cased, pressure-tested, and cemented downhole circulation loop 108 (also referred herein as a fully cased downhole well loop 108) for isolating and circulating a single fluid 200 (also referred to as working fluid 200) over an extended length underground to achieve heat exchange between the working fluid 200 and heat emitted / radiated from the earth (i.e., the underground heat source). System 100 employs a closed-loop direct turbine expansion cycle, similar to an organic Rankine cycle, to convert the energy stored in the heated working fluid 200 into mechanical energy, which is then used to generate electrical energy.

[0080] Those skilled in the art will recognize that, in a Rankine cycle, working fluid 200 can undergo a phase change. For clarity, in the following description, regardless of the state of matter, it will be generally referred to as working fluid 200. Liquid working fluid 200 will be referred to as liquid working fluid 204, and gaseous working fluid 200 will be referred to as gaseous working fluid 208.

[0081] The geothermal power generation system 100 includes a complete casing downhole circulation loop 108 underground, having a well assembly 110 extending into the surface. The well assembly 110 has a common well section 118, a lower portion of an insulated injection conduit or pipe 154, an injection well 112, and a production well 128. The injection well 112 and the production well 128 branch off from the common well section 118 at a junction 122 to extend deeper into the surface. A first upper lateral section 116 and a second lower lateral section 124 also form part of the downhole circulation loop 108; the first upper lateral section connects to the injection well 112 and extends away from it, and the second lower lateral section connects to the production well 128 and extends away from it. The first lateral section 116 and the second lateral section 124 converge at a junction where a multilateral connector 120 is installed. Above ground, the geothermal power generation system 100 includes a pump 104 fluidly connected to the upper portion of an insulated injection conduit or pipe 142, configured to transport liquid working fluid 204 downwards to the lower portion 154 of the insulated injection conduit 114 below ground, through a common well section 118 and away from the surface 316 into an injection well 112, through a first upper lateral section 116, a multi-branch connector 120, and a second lower lateral section 124, and then upwards along a production well 128, through an insulated production pipe 166, and through the common well section 118 back towards the surface 316. The liquid working fluid 204 undergoes a phase change underground and returns to the surface 316 as gaseous working fluid 208 through the production well 128 and the common well section 118. This gaseous working fluid flows into a turbine system 132 for power generation. Within the turbine system 132, the gaseous working fluid 208 rotates the turbine, which in turn rotates the shaft and generates mechanical energy. The mechanical energy is converted into electricity via a shaft-driven generator (not shown). A cooler 136 is also provided with fluid connection to the turbine system 132. The cooler 136 condenses the low-pressure gaseous working fluid 208 after it leaves the turbine system 132, thereby returning it to its original liquid state, where it can be pumped down to the common section 118, circulated through the injection well 112, and through the full casing downhole circulation loop 108.

[0082] As those skilled in the art will understand, and as will be apparent from the description below, the illustrated geothermal power generation system 100 tends to address the challenges identified above. More specifically, the use of the full-casing downhole circulation loop 108 eliminates any risk of cross-contamination between the working fluid 200 flowing through the full-casing downhole circulation loop 108 and any rock formation 320 or formation fluids, and any risk that the working fluid 200 will erode the rock formation 320, because the working fluid 200 never comes into contact with the rock formation 320. The velocity of the working fluid 200 can also be greater within the full-casing downhole circulation loop 108, as it will not erode the rock formation 320 due to the lack of contact. In addition to preventing wellbore wall erosion, the addition of casing also eliminates the risk of wellbore instability and rock quality failure due to in-situ and induced stresses around the wellbore. In prior art systems, to achieve minimal cross-contamination, the velocity of the working fluid must be carefully managed and monitored to ensure minimal erosion in any wellbore or subsurface section. Not only from an environmental protection perspective, but also to avoid instability in the rock stratum 320 that could lead to earthquakes or other potential consequences, it is important to ensure minimal or no erosion. Furthermore, because the working fluid 200 is isolated from the rock stratum 320, there is no risk of dissolving minerals or other substances that could alter the composition of the working fluid 200. In other existing technologies where the working fluid 200 can come into contact with the surrounding rock stratum 320, there is a risk of dissolving minerals or other substances accessible to the working fluid 200, especially when the working fluid 200 erodes at the surface of the rock stratum 320 and undergoes thermal changes. When the working fluid 200 cools, the dissolution of minerals can also lead to mineral deposits in the pipes or other components of the geothermal power generation system 100, causing blockages and increasing the maintenance requirements of the system 100.

[0083] The full-casing downhole circulation loop 108 is pressure tested and cemented underground to the surrounding rock formation 320. Due to its construction, the possibility of any working fluid leaving the full-casing downhole circulation loop 108 is greatly minimized. Therefore, especially when the working fluid 200 experiences significant temperature and pressure changes, the risk of any working fluid 200 leaking or leaving the full-casing downhole circulation loop 108 and potentially causing pollution or other environmental problems is greatly minimized. Conversely, other existing technology systems may suffer fluid loss due to leakage into the formation, and / or fluid contamination from formation fluid inflows due to the working fluid not being completely isolated from the rock formation 320. Effective pressure testing would not be successfully achieved without casing. Therefore, the full-casing downhole circulation loop 108 can use unconventional working fluids 200 with different heat capacities and phase transition points, thus allowing potentially more energy-efficient systems, better power generation capabilities, and geothermal power generation systems with smaller coverage areas, while reducing environmental pollution problems. Furthermore, parasitic power losses are minimized. Those skilled in the art will recognize that parasitic losses can be described as the absorbed power being the energy required to operate pumps, cooler fans, and other loads, thereby reducing the net energy output of the system. Those skilled in the art will also recognize that net energy is the power generated minus the power used to operate the system.

[0084] The casing material used for the full-casing downhole circulation loop 108 can be steel. Unlike other existing technologies that may use chemical linings, steel, as a hardening and inert material, can withstand high pressure along with the cement support. Furthermore, steel carries a lower risk of chemical interaction with the working fluid 200, allowing for a better selection of the working fluid 200 for the geothermal power generation system 100. Moreover, steel casing is substantially safer to construct and apply than chemically lined casing when ensuring there is no leakage within the full-casing downhole circulation loop 108.

[0085] In contrast to two loops utilizing two working fluids, parasitic energy loss is significantly reduced by using a single heat exchange loop utilizing a single working fluid 200, because heat is retained in the single working fluid 200 and is not lost to the environment in any heat transfer when multiple working fluids are present.

[0086] Furthermore, since the working fluid 200 is entirely contained within the geothermal power generation system 100, it can be easily changed if environmental conditions change. For example, if the underground temperature changes, the working fluid 200 can be easily replaced by another working fluid 200 with a lower boiling point. This allows the geothermal power generation system 100 to continue operating without requiring structural modifications, such as adjusting the depth of lateral sections to obtain the desired heat.

[0087] The flow path that allows the working fluid 200 to flow downwards into the casing downhole circulation loop 108 and the flow path that allows the working fluid 200 to exit upwards from the casing downhole circulation loop 108 are both located through a single opening 110A and along a single common well section 118, allowing the geothermal power generation system 100 to occupy a smaller coverage area compared to other prior art systems, with a smaller footprint both underground and above ground. A smaller coverage area reduces capital and operating costs. For example, U.S. Patent Application Publication No. 2011 / 0048005 has a single horizontal pipeline with two shafts, each with two wellheads on the surface: an injection wellhead and a production wellhead. This results in the injection and production wellheads being significantly further apart and thus occupying a larger coverage area than the embodiments described below. A larger coverage area can lead to inefficient heat transfer and significant construction costs. Furthermore, prior art systems with two shafts and two wellheads require additional drilling and foundations. For example, in the case of a second shaft and a second wellhead, a second surface casing may be required to prevent leakage of working fluids into the environment near the second wellhead. The construction of additional boreholes and additional surface casing represents increased financial costs.

[0088] See Figure 1 and Figure 2 This diagram illustrates an embodiment of a geothermal power generation system 100. The main components of the geothermal power generation system 100 include a complete casing downhole circulation loop 108, and more specifically, a common well section 118, a lower portion 154 of an insulated injection pipe 114, an injection well 112, a first upper lateral section 116, a multi-branch connector 120 (also referred to herein as a cross-connector 120, or multi-branch joint 120), a second lower lateral section 124, a production well 128, and an insulated production pipe 166. The geothermal power generation system 100 also includes a pump 104 and a turbine system 132 fluidly connected to the complete casing downhole circulation loop 108. More specifically, the pump 104 is connected to the upper portion 142 of the insulated injection pipe 114 and the injection well 112, and the turbine system 132 is connected to the common well section 118 and the production well 128. A cooler 136 is fluidly connected between the turbine system 132 and the pump 104, thereby closing the loop for a single heat exchange loop.

[0089] like Figure 1 As shown, an additional wellbore 140 is provided adjacent to the full casing downhole circulation loop 108. This wellbore 140 (also referred to herein as connecting wellbore 140, access wellbore 140, or sacrificial wellbore 140) is drilled to help construct the full casing downhole circulation loop 108 and does not contribute to the normal operation of the geothermal power generation system 100. The wellbore 140 will be further described below with respect to the construction of the geothermal power generation system 100.

[0090] like Figure 1As can be seen, the flow direction of the liquid working fluid 204 is depicted by a solid arrow, and the flow direction of the gaseous working fluid 208 is depicted by a dashed arrow. Further details regarding the operation and phase change of the working fluid 200 will be described below.

[0091] When the complete casing downhole circulation loop 108 is in the surrounding rock strata 320 and underground, there is an entry point for the complete casing downhole circulation loop 108 located on the surface 316, more specifically, an opening 110A located at the upper end 180 of the common well section 108 of the well assembly 110. The opening 110A is configured as the entry and exit point for the working fluid 204 on the surface 316. More specifically, the entry point for the flow of liquid working fluid 204 traveling to the injection well 112 below the surface via the insulated injection pipe 114 and the exit point for the flow of gaseous working fluid 208 traveling towards the surface from the production well 128, the insulated production pipe 166, and the common well section 118 are co-located at the opening 110A. The opening 110A is surrounded by the surface casing 144. A surface casing 144 is provided to isolate the upper end 180 of the common well section 118 from fresh groundwater and to prevent the working fluid 200 from escaping or migrating into the groundwater and / or environment. Details relating to the construction of the surface casing 144 are provided below. Those skilled in the art will appreciate that references to rock formation 320 are not limited to rock, but may include any underground geological structure or combination of geological structures.

[0092] The common well section 118 co-locates the flow of liquid working fluid 204 from the surface through the lower portion 154 of the insulated injection pipe 114 to the injection well 112, and the flow of gaseous working fluid 208 from the production well 128 and the insulated production pipe 166 to the surface. Although the gaseous working fluid 208 from the production well flows around the lower portion 154 of the insulated injection pipe 114 through which the liquid working fluid 204 flows, 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 section 118. By providing the common well section 118 and a single opening 110A on the surface, the geothermal power generation system 100 can occupy a smaller coverage area on the surface 316 than other systems with different, spaced-apart injection and production wells accessible from the surface. In a preferred embodiment, the size of the coverage area of ​​the geothermal power generation system 100 on the surface is 30-100 m². 2 .

[0093] Furthermore, the use of common well section 118 enables savings in labor and construction costs. Compared to other systems with spaced-apart 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. Moreover, the use of common well section 118 reduces environmental harm to the area; specifically, having common well section 118, opposite to injection and production wells at the surface, means only a single opening on the surface, thus minimizing environmental damage to the surface. Additionally, the use of common well section 118 reduces carbon emissions.

[0094] Having a common well section 118 allows for the arrangement of more full-casing downhole circulation loops 108 within a specific area compared to other systems. More specifically, the density of the full-casing downhole circulation loops 108, and correspondingly the density of geothermal power generation systems 100 within the specific area, can be greater than the density of other systems. When constructing a specific number of geothermal power generation systems 100, the surface coverage area of ​​the multiple geothermal power generation systems 100 will be smaller or more compact than the surface coverage area of ​​constructing the same number of prior art systems. Furthermore, geothermal power generation systems using a common well section tend to use fewer components on the surface compared to prior art systems. More specifically, due to the presence of a single opening 110A opposite the two wellheads (inlet and outlet), there is one less component above the surface. The arrangement and configuration of the geothermal power generation systems 100 and the full-casing downhole circulation loops 108 will be discussed further below.

[0095] The entire casing downhole circulation loop 108, which is in physical contact with the rock formation 320, is lined with cement 152 and the casing is made of steel 156. In the current embodiment, the steel pipe is cemented within the wellbore of the common section 118, injection well 112, and production well 128. Furthermore, the steel pipe is also cemented as part of both the upper lateral section 116 and the lower lateral section 124, and as part of any connection between the multi-branch connector 120 and these components.

[0096] In the current implementation, such as Figure 1As shown, the insulated injection pipe 114 includes: a first upper portion 142 of the insulated injection pipe 114 fluidly connected to the pump 104 above ground; and a second lower portion 154 of the insulated injection pipe 114 extending below ground parallel to and not in physical contact with the central axis of the common well section 118. More specifically, the insulated injection pipe 114 is co-located with the common well section 118, wherein the insulated injection pipe 114 and the common well section 118 occupy the same space. The insulated injection pipe 114 may be co-located with the common well section 118 in a concentric manner, wherein a portion of the insulated injection pipe 114 extends along the central axis of the common well section 118. In other embodiments, the insulated injection pipe 114 may be co-located with the common well section 118 in an eccentric manner, wherein this portion of the insulated injection pipe extends parallel to, but not precisely along, the central axis of the common well section 118. Those skilled in the art will recognize the different potential arrangements in which the insulated injection pipe 114 is co-located with the common well section 118. The insulated injection pipe 114 may be a steel pipe 158 coated with a non-thermally conductive compound 162. The non-thermally conductive compound 162 (also referred to herein as the non-thermally conductive layer 162) minimizes the amount of heat transfer between the liquid working fluid 204 flowing to the injection well 112 and the gaseous working fluid returning from the production well 128 to the surface 316. Examples of the non-thermally conductive compound 162 surrounding the steel pipe 158 include, but are not limited to, insulating sprayed foam. Those skilled in the art will appreciate that in other embodiments, the insulated injection pipe 114 may be made of materials other than the steel pipe 158. Furthermore, those skilled in the art will recognize that the materials of the insulated injection pipe 114 and the non-thermally conductive layer 162 have different available arrangements and configurations. Those skilled in the art will also recognize that a single material or multiple materials may be used for the insulated injection pipe 114 to physically and thermally isolate the liquid working fluid 204 flowing to the injection well 112 from the gaseous working fluid 208 returning from the production well 128 to the surface.

[0097] In an alternative embodiment (not shown), the lower portion 154 of the insulated injection pipe 114 may extend along the periphery of the common well section 118. When extending along the periphery of the common well section 118, the lower portion 154 of the insulated injection pipe 114 may also contact the wall of the common well section 118. Those skilled in the art will recognize that different configurations and arrangements of the lower portion 154 of the insulated injection pipe 114 within the common well section 118 are possible.

[0098] A pressure test is performed on the entire casing downhole circulation loop 108 to ensure there are no leaks. The pressure test may be limited to a hydraulic pressure test, wherein the continuously connected steel casing 156 is subjected to a minimum downhole pressure associated with the maximum pressure that the casing downhole circulation loop 108 can withstand. The maximum pressure that the casing downhole circulation loop 108 can withstand may be a point along the casing downhole circulation loop 108 with the maximum depth, and possibly along the lower lateral section 124. In some embodiments, the following formula can be used to determine the total downhole pressure used for the pressure test: Surface pressure + hydrostatic pressure The hydrostatic pressure can be calculated as (maximum depth × specific gravity of water).

[0099] For example, if the deepest point along the full casing downhole circulation loop 108 is at a depth of 2500 m along the lower lateral section 124 and the pressure applied at the surface is 2 MPa, where the specific gravity of water is 10 kPa / m, then the total downhole pressure can be calculated by adding the surface and hydrostatic pressures, which in this example is exactly 2 MPa. + (2500) × 10 / ) = 21 .

[0100] Using water for pressure testing ensures that, in the event of any leakage due to high pressure, the leaked water will not cause any pollution to the surrounding environment. When the specific gravity of water is greater than that of the working fluid 200, the above formula using the hydrostatic pressure of water can be applied to the working fluid 200. For example, propane has a lower specific gravity than water, and therefore the above formula provides a higher pressure test than that required for propane as the working fluid 200, thereby ensuring the safe operation of the complete casing downhole circulation loop 108. Those skilled in the art will recognize that if the specific gravity of the working fluid 200 is greater than that of water, the above formula can compensate by providing the specific gravity of the working fluid 200, and then accordingly, the complete casing downhole circulation loop 108 can be pressure tested with water. Furthermore, in some embodiments, the calculated total downhole pressure used for the above pressure test can be increased to provide a safety factor, thus testing the complete casing downhole circulation loop 108 at a pressure higher than the operating limit for safety reasons. The pressure that the complete casing downhole circulation loop 108 is designed to withstand and pressure tested to withstand is a pressure that cannot be achieved in existing systems used to generate energy from geothermal sources. This is due to the fact that the operating pressure of the working fluid in existing systems tends to be much lower than the operating pressure when the working fluid 200 flows through the full casing downhole circulation loop 108.

[0101] The pressure-tested full casing downhole circulation loop 108 is capable of receiving and delivering working fluid 200 at pressures between 7 MPa and 31 MPa. In embodiments where the working fluid 200 is pentane, the pressure-tested full casing downhole circulation loop 108 can receive and deliver working fluid 200 at pressures between 7 MPa and 22 MPa. In a preferred embodiment, when the working fluid 200 is propane, the pressure-tested full casing downhole circulation loop 108 can receive and deliver propane working fluid 200 at pressures between 7 MPa and 20 MPa.

[0102] During its operation, the full casing downhole circulation loop 108 can withstand a pressure of at least 7 MPa. In other embodiments, pressure testing of the full casing downhole circulation loop 108 may include a pressure test of up to 31 MPa, and it may be designed to burst or fail at a maximum of 39 MPa.

[0103] Cement 152 is used to structurally secure the steel 156 sleeve to the surrounding rock strata 320. However, in alternative embodiments, cement 152 can be mixed with other substances, such as adding hematite, to adjust the thermal conductivity of cement 152. Although cement 152 and steel 156 are used in the current embodiment, those skilled in the art will appreciate that any other material can be used as a barrier, provided that it can physically isolate the working fluid 200 from the external environment / rock strata 320, withstand the pressure requirements of both expansion and contraction of the working fluid 200 undergoing a phase change, and that heat can be conducted through the material.

[0104] A common well section 118 extends downwards from an opening 110A at the surface 316 to a predetermined depth until a junction point 122, where the common well section branches into an injection well 112 and a production well 128. The predetermined depth can be determined on a site-by-site basis based on the geothermal gradient, rock thermal properties, geology, and geological composition of the target area. In the current embodiment, the common well section 118 is vertical, such that the depth and length of the common well section are the same. However, in other embodiments, the common well section 118 can be angled. Therefore, the length of the common well section 118 can be determined by the predetermined depth of the common well section 118 and the slope or angle of the common well section 118. Alternatively, the depth or slope of the common well section 118 can be based on a predetermined length, wherein the length of the common well section 118 can be determined based on the type of working fluid 200, the potential heat transfer between the liquid working fluid 204 in the lower 154 of the insulated injection pipe 114 and the gaseous working fluid 208 flowing along the common well section 118 through the annular cylindrical space surrounding the lower 154 of the insulated injection pipe 114. Although having a single well with a single opening 110A leading to the surface 316 saves on construction costs compared to other systems with multiple wells, it will be understood that the greater the length of the common well section 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 section 118 is vertical, and the depth and length of the common well section 118 are approximately 650 meters. Those skilled in the art will also recognize that in other embodiments, the common well section 118 may extend at an angle or be a combination of any number of vertical, skewed, or horizontal sections, and in such embodiments, length rather than depth must be considered in relation to heat transfer.

[0105] The lower portion 154 of the insulated injection pipe 114 extends parallel to the central axis of the common well section 118, and is fixed parallel to the central axis between the pump 104 above the surface 316 and the injection well 112 and the common well section at a connection point 122 (also referred to herein as branch point 122) to allow the flow of liquid working fluid 204 between the pump 104 on the surface 316 and the injection well 112. In the current embodiment, the lower portion 154 of the insulated injection pipe 114 is connected to the injection well 112 at the connection point 122 via a bent connector 134. The lower portion 154 of the insulated injection pipe 114 extends along the entire length of the common well section 118. Although the insulated injection pipe 114 is not cemented, it undergoes the same pressure testing as the remainder of the full casing downhole circulation loop 108.

[0106] The injection well 112 includes a first angled section 126 and a second vertical section 138. At the junction 122, the injection well 112 branches off from the common well section 118 along the angled section 126, extending a predetermined length at a downward angle. The downward angle of the angled section 126 can be between 5 degrees and 20 degrees and has a build-up rate of 6 degrees / 30 m relative to the plane of the surface 316. The downward angle can be determined based on the flow rate of the liquid working fluid 204. It should be understood that the steeper the downward angle, the faster the flow rate of the liquid working fluid 204. In a preferred embodiment, the angled section 126 angles downward at a build-up / rotation rate of 6 degrees / 30 m. The predetermined length of the angled section 126 depends on the downward angle of the angled section 126 and the interval 130 between the vertical section 138 and the production well 128. Interval 130 is measured and defined as the distance between the nearest points on the lateral plane between the central axis of vertical section 138 and production well 128. Interval 130 is determined by the distance required to ensure thermal separation between vertical section 138 of injection well 112 and production well 128, ensuring that thermal interference between gaseous working fluid 208 in production well 128 and liquid working fluid 204 in vertical section 138 of injection well 112 is minimized. Interval 130 may be influenced by geothermal gradients, rock thermal properties, geology, and geological composition of the target area or rock formation 320 surrounding injection well 112 and production well 128. In a preferred embodiment, interval 130 is 80 m. Furthermore, in a preferred embodiment, angled section 126 has a steel casing 156 with an inner diameter of approximately 139 mm. However, in other embodiments, section 126 may have different dimensions. Those skilled in the art will recognize that, based on the foregoing factors, different configurations of the downward tilt angle, predetermined distance, and interval 130 of the angled segment 126 may be used.

[0107] The vertical section 138 of the injection well 112 extends vertically downwards from the end of the angled section 126 by a predetermined distance (or depth). This predetermined distance (or depth) can be determined location-by-location based on the geothermal gradient, rock thermal properties, geology, and geological composition of the target area. The geothermal gradient and rock thermal properties are variables to be considered to determine the depth and residence time at that 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 high rock temperatures while minimizing drilling costs, which increase with many factors, including the depth of the rock formation 320 and its geological composition. In the current embodiment, the vertical section 138 is connected at its lower end 196 to the upper lateral section 116 via a bent connector 160. However, the upper lateral section 116 may be connected to the vertical section 138 and extend away from the vertical section 138 at any point along the vertical section 138. The vertical section 138 can extend over a distance from approximately 0 m to 2850 m. More specifically, the vertical section 138 can begin at a depth of approximately 650 m and extend to a depth of approximately 3500 m. In a preferred embodiment, based on a preferred working fluid temperature of 140°C, the vertical section 138 can have a steel production casing 156 with an inner diameter of approximately 139 mm. However, where adaptation to a specific application is required, the vertical section 138 can have different sizes (i.e., be drilled to different depths, whether at greater or shallower depths, and have different diameters, whether larger or smaller). Figure 1 In the illustrated embodiment, the first segment 138 is shown extending vertically downwards into the ground. It should be understood that this is not the case in every embodiment. In some embodiments, the first segment may extend downwards into the ground at an angle relative to the vertical direction.

[0108] In a preferred embodiment, the upper lateral section 116 is seen to be perpendicular to the vertical section 138 of the injection well 112 and extends laterally toward the XC connector 120. Furthermore, the upper lateral section 116 has a length of approximately 2000m to 4000m and the steel production sleeve 156 has an inner diameter of approximately 139mm. In other embodiments, the upper lateral section 116 does not need to be laterally positioned relative to the vertical section 138 of the injection well 112 and can extend away from the vertical section 138 of the injection well 112 at an angle relative to the lateral direction. It can also have different dimensions.

[0109] Connecting the upper lateral section 116 to the lower lateral section 124 is a multi-branch connector 120. The multi-branch connector 120 may include an XC separator or other similar connection device, which connects between the upper lateral section 116 and the lower lateral section 124 in a manner that ensures the complete casing downhole circulation loop 108 can withstand pressure testing and operate under pressure. For example, a SAGD (Steam Assisted Gravity Drainage) XC separator multi-branch system manufactured by Baker Hughes Company. The multi-branch connector provides complete mechanical and hydraulic isolation support to the connection area and has reentry capability. The multi-branch connector is designed specifically for reentry connections 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.

[0110] In the current embodiment, the lower lateral section 124 extends laterally away from the multi-branch connector 120 to connect to the lower end 198 of the production well 128 via the bent connector 164. However, the lower lateral section 124 can be joined to the production well 128 at any location along the production well 128. The lower lateral section 124 is arranged perpendicular to the production well 128. Furthermore, the lower lateral section 124 has a length of approximately 2000 m to 4000 m and the steel production casing 156 has an inner diameter of approximately 139 mm. In other embodiments, the lower lateral section 124 does not need to be arranged laterally relative to the production well 128 and can extend toward the production well 128 at an angle relative to the lateral direction. It can also have different dimensions.

[0111] In an embodiment where the upper lateral section 116 is arranged laterally relative to the vertical section 138 of the injection well 112 and the lower lateral section 124 is arranged laterally relative to the production well 128, the two lateral sections 116 and 124 may be in the same vertical plane. However, those skilled in the art will appreciate that, in alternative configurations, the lateral sections 116 and 124 may be offset from each other in the vertical plane.

[0112] In the current embodiment, the length of the upper lateral section 116 is shorter than the length of the lower lateral section 124. The length of each of the lower lateral section 116 and the upper lateral section 124 is selected based on the amount of time (i.e., residence time) that the working fluid 200 needs to remain in contact with the heated rock layer 320 underground and the flow rate of the working fluid 200. For example, if the working fluid 200 requires a longer time to be heated to undergo a phase change, whether due to the thermal conductivity of the surrounding rock layer 320, the well casing, and the linings of the lateral sections 116 and 124, or due to the characteristics of the type of working fluid 200 used, then the two lateral sections 116 and 124 may need to be longer to accommodate the time required for the working fluid 200 to be heated to induce a phase change. Flow rate is another variable that needs to be considered, as a lower flow rate means a shorter distance traveled over time, and this allows for further adjustment of the lengths of the lateral sections 116 and 124.

[0113] In a preferred embodiment, the lower lateral segment 124 extends deeper than the upper lateral segment 116. Having two lateral segments 116 and 124 at different depths can enhance heat absorption from the surrounding rock formation 320 because thermal interference between wells 112 and 128 is less. However, the full casing downhole circulation loop 108 is not limited to this configuration. In an alternative embodiment (not shown), the lateral segment returning to the production well 128 can be positioned shallower than the lateral segment connected to the injection well 112. Furthermore, in an alternative embodiment (not shown), the two lateral segments 116 and 124 can be at the same depth but can be angled relative to each other, wherein the multi-branch connector 120 connects the two lateral segments 116 and 124 from different angles. Alternatively, the two lateral segments 116 and 124 can be at the same depth and most of the length of the lateral segments 116 and 124 can extend parallel to each other, wherein the angled connector (not shown) can accommodate an initial offset angle from the multi-branch connector 120. In embodiments where the two lateral sections 116 and 124 extend parallel to each other for most of their length, the spacing between the lateral sections 116 and 124 is intended to ensure heat absorption from the surrounding rock formation 320, and that there is no thermal interference or heat transfer between the lateral sections 116 and 124. Those skilled in the art will recognize the various potential configurations and lengths that can be used for the two lateral sections 116 and 124, and the various potential configurations for the entire casing downhole circulation loop 108.

[0114] exist Figure 1In the embodiment depicted, production well 128 is vertical and aligned with the same vertical trajectory as common well section 118. However, the configuration of production well 128 is not limited to vertical. Production well 128 may be angled, or it may be divided into angled and vertical sections, similar to injection well 112 (not shown). In embodiments where production well 128 includes angled and vertical sections, an interval 130 may be measured between the vertical section 138 of injection well 112 and the vertical section of production well 128. Those skilled in the art will recognize the different potential configurations of production well 128.

[0115] In the current embodiment, production well 128 is fluidly connected to insulated production pipe 166, which begins along any section of production well 128 and rises to a depth just above connection point 122, where it can be fluidly connected to common well section 118. Insulated production pipe 166 can be held in place by an isolation packer 254 at the lower end of the insulated production pipe along production well 128, and can also be held in place by a geothermal isolation joint 170 directly above connection point 122. The addition of insulated production pipe 166, fluidly connected to common well section 118 above connection point 122, prevents gaseous working fluid 208 from leaking into the angled section 126 of injection well 112. Isolation packer 254 along production well 128 also prevents gaseous working fluid 208 from leaking below into the space surrounding connection point 122 and directs gaseous working fluid 208 from production well 128 into insulated production pipe 166. The geothermal isolation joint 170 is located above and adjacent to the connection point 122 and includes passageways for the insulated injection pipe 114 and the insulated production pipe 166. The geothermal isolation joint 170 also forms a seal between the walls of the insulated injection pipe 114, the insulated production pipe 116, and the common well section 118 to prevent any 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 section 118 from flowing downwards back into the space surrounding the connection point 122. The combination of the isolation packer 254, the geothermal isolation joint 170, and the isolation packer 298 effectively creates and defines a sealed space around the connection point 122 at the intersection between the angled section 126 and the common well section 108, thereby preventing any liquid working fluid 204 from flowing downwards along the production well 128 and preventing any working fluid 208 from flowing downwards along the injection well 112. In addition, although the insulated injection pipe 114, the angled section 126 and the bent connector 134 are sealed and pressure tested to ensure that the liquid working fluid 204 does not leak into the surrounding common section 118 or rock formation 320, the addition of the insulated production pipe provides additional precautions to prevent the gaseous working fluid 208 from mixing with the liquid working fluid 204.

[0116] The insulated production pipe 166 may be made of a material similar to that of the insulated injection pipe 114. In the current embodiment, the insulated production pipe 166 may be a steel pipe 158 coated with a non-thermally conductive compound 162 to minimize heat transfer between the liquid working fluid 204 and the gaseous working fluid 208. However, those skilled in the art will recognize that, similar to the insulated injection pipe 114, the insulated production pipe 166 may be made of any material or combination or layer of materials that is non-thermally conductive and allows the insulated production pipe 166 to withstand and withstand the pressures required by the downhole circulation loop 108 under all conditions. In a preferred embodiment, the insulated production pipe 166 may extend to a length between 0 m and 100 m 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 to allow the flow of the liquid working fluid 208 to bypass any area that may enter the injection well 112 and the milled window 266. By extending the insulated production pipe 166 at least along the length between the geothermal isolation joint 170 and the isolation packer 254, any possible exposed sections are isolated and avoided.

[0117] The geothermal isolation joint 170 may also be made of a non-thermally conductive material to minimize any heat transfer between the insulated injection pipe 114 and the insulated production pipe 166. In another alternative embodiment (not shown), the complete casing downhole circulation loop 108 may not include the insulated production pipe 166, the isolation packer 254, and the geothermal isolation joint 170. The production well 128 may be fluidly connected to a common well section 118, allowing gaseous working fluid 208 to flow from the production well 128 along the common well section 118 into the cylindrical annular space 118 surrounding the insulated injection pipe 114. In this embodiment, the isolation packer 298 serves as a seal and prevents the gaseous working fluid 208 from mixing with the liquid working fluid 204. The isolation packer 298 also prevents the gaseous working fluid 208 from flowing into the angled legs 126 of the injection well 112.

[0118] In another alternative embodiment (not shown), the common well section 118 may include: a lower portion 154 of an insulated injection pipe 114 extending along the length of the common well section 118 to allow liquid working fluid 204 to flow downward into the injection well 112; and a lower portion of another insulated pipe extending along the length of the common well section 118 to allow gaseous working fluid 208 to flow upward from the production well 128 toward the surface. The lower portion 154 of the insulated injection pipe 114 and the lower portion of the insulated pipe connected to the production well may extend parallel to each other and may be spaced apart, thereby allowing the spacer to act as additional insulation to prevent heat transfer.

[0119] Those skilled in the art will now recognize that the insulated production pipe can extend to the surface from anywhere along the production well 128. Furthermore, those skilled in the art will also recognize that, due to the arrangement of the insulated production pipe, the insulated injection pipe 114 is unnecessary, and the liquid working fluid 204 can flow toward the injection well 112 in the cylindrical annular region surrounding the lower part of the insulated production pipe within the common well section 118. Moreover, those skilled in the art will recognize that the arrangement of the isolation pipe and the flow of the working fluid 200 within the common well section 118 can have different combinations and variations while ensuring thermal and physical isolation between the flow of the liquid working fluid 204 and the flow of the gaseous working fluid 208.

[0120] In another alternative embodiment (not shown), the flow of working fluid 200 may differ in the full casing downhole circulation loop 108. Specifically, in this embodiment, injection well 112 may be fluidly connected to common well section 118, and production well 128 may be connected to turbine system 132 via an insulated pipe, the lower portion of which extends along the length of common well section 118. Liquid working fluid 204 may flow downward from pump 104 along common well section 108 in the space surrounding the lower portion of the insulated pipe, through lower lateral section 124, through multi-branch connector 120, and then subsequently through upper lateral section 116. As it flows through upper lateral section 116, liquid working fluid 204 may undergo a phase transition to gaseous working fluid 208. The gaseous working fluid 208 can flow through the remainder of the upper lateral section 116, and then through the vertical and angled sections of the production well 128 to the surface, and then subsequently through an insulated pipe to the turbine system 132, wherein the insulated pipe is in material and structure similar to... Figure 1 The insulated injection pipe 114 is similar to the embodiment described herein.

[0121] Furthermore, in another alternative embodiment (not shown), the injection well 112 may also be a single vertical shaft and may not have the angled section 126 and the vertical section 138. Therefore, those skilled in the art will appreciate that at least four possible configurations exist for the injection well 112 and the production well 128 in the presence of the common well section 118. Specifically, to maintain the gap 130 to ensure no heat transfer between the injection well 112 and the production well 128, the injection well 112 may include the angled section 126 and the vertical section 138, and the production well 128 may be vertical and without the angled and vertical sections. Alternatively, the injection well 112 may be vertical and without the angled section 126 and the vertical section 138, and the production well 128 may include the angled and vertical sections. Alternatively, each of the injection well 112 and the production well 128 may also include its own angled and vertical sections. Alternatively, both injection well 112 and production well 128 may be angled or inclined along their entire length without any angled or vertical sections, thereby ensuring a minimum spacing 130 over most of the distance between injection well 112 and production well 128. Those skilled in the art will now recognize the possible different configurations of injection well 112 and production well 128.

[0122] return Figure 1 In the illustrated embodiment, because the lower lateral section 124 extends to a greater depth 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 connection point 122 and ends at a depth of approximately 3500 m. However, the connection point 122 can be at any depth, and thus, the production well 128 can begin and end at any depth reasonably appropriate to the characteristics of the rock formation 320. The size of the production well can vary (i.e., it can be drilled to different depths, whether greater or less, and has different diameters, whether greater or less) if required to suit a particular application. It will be apparent to those skilled in the art that in the current embodiment, where the production well 128 is aligned with the same vertical trajectory as the common well section 118, the diameter of the production well 128 will be the same as the diameter of the common well section 118. However, in other embodiments where the production well 128 is not aligned with the common well section 118, or where the production well 128 may include angled and vertical sections, the production well 128 may have a diameter different from that of the common well section 118.

[0123] like Figure 2 and Figure 2As shown, located on the surface 316, pump 104 is fluidly connected to insulated injection pipe 114. Pump 104 is operable to circulate working fluid 200 through the downhole circulation loop 108 of the entire casing via the upper part 142 of insulated injection pipe 114, and underground into the lower part 154 of insulated injection pipe 114 and into injection well 112.

[0124] Pump 104 is also configured to maintain the flow of liquid working fluid 204 through the entire single heat exchange loop by maintaining an appropriate flow rate of working fluid 200. The flow rate (and corresponding residence time) is determined by the underground well ring to conduct sufficient heat energy to convert the working fluid from liquid to gas with a sufficient temperature. In the current embodiment, the liquid working fluid 204 received by pump 104 can be in the pressure range of 500 kPag to 2000 kPag and the temperature range of 10°C to 40°C. Pump 104 is configured to increase the pressure to the range of 700 kPag to 3000 kPag and maintain a flow rate of 15 kg / s to 25 kg / s. In a preferred embodiment, pump 104 is capable of supplying liquid working fluid 204 to the insulated injection pipe 114 of injection well 112 at a pressure of about 1300 kPag and a temperature of about 30°C. A preferred embodiment of pump 104 is a liquid pump for thermodynamic efficiency. Compared to using mechanical gas compressors, liquid pumps minimize parasitic energy losses in the system.

[0125] In other prior art geothermal systems where the working fluid 200 is in contact with the rock formation 320 due to the lack of casing, or where the working fluid 200 may pick up debris underground, the pump may need to be substantially more robust and may need to handle abrasive materials during operation. Furthermore, in prior art systems where the working fluid 200 is water, the pump may need to handle the water's chemical characteristics, which are prone to scaling, during operation. Conversely, in the current embodiment, when the full-casing downhole circulation loop 108 is completely sealed, enclosed, and pressure-tested, the working fluid 200 does not come into contact with any rock formation 320 and is physically isolated from the environment. Thus, the working fluid 200 does not pick up any debris and remains a clean, homogeneous fluid. This allows the pump 104 to have a long service life and minimal maintenance, thus saving on procurement and operating costs, and potentially allowing the use of less robust or standard pump designs.

[0126] In a preferred embodiment, pump 104 may be a positive displacement pump with a variable speed drive controller. Positive displacement pumps typically have high overall thermal efficiency and are able to maintain the desired outlet head when paired with a variable speed drive. Positive displacement pump types 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 the various possible pumps that may be used based on the aforementioned pressure, flow rate, and temperature specifications, as well as purchase and maintenance costs.

[0127] Turbine system 132 is also above ground level and is fluidly connected to opening 110A of common well section 118. Turbine system 132 may include a turbine (not shown) having an output shaft connected to a generator (not shown).

[0128] In the current embodiment, the turbine system 132 is located immediately adjacent to the opening 110A to prevent heat loss of the gaseous working fluid 208 as it travels along the insulated conduit 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, but this is generally not preferred. Although the external surface conduit for transporting the gaseous working fluid 208 to the turbine system can be isolated, heat and pressure losses may still occur, and such travel distances and times are important considerations. Those skilled in the art will be familiar with the structure, configuration, and operation of the turbine system 132 and the associated generator, so they need not be described herein.

[0129] In operation, turbine system 132 receives gaseous working fluid 208 from opening 110A of common well section 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 transferred to a generator, which converts the mechanical energy into commercially marketable electricity. The electricity can then be routed to a utility-owned power grid for further distribution. In the current embodiment, turbine system 132 can generate 0.5 MW to 2 MW of power. In a preferred embodiment, turbine system 132 can generate approximately 1 MW of power.

[0130] Alternatively, if the power grid does not require power, then power can be routed to batteries, other local loads, or wasted only for short periods through an electrical resistive load bank. Using a load bank to waste power allows equipment to operate without a real-time connection to the power transmission line. This can cope with equipment testing and short-term operational disturbances (not shown).

[0131] In other embodiments, turbine system 132 may include an expansion turbine, a piston expander, or a vortex expander. In a preferred embodiment, one or more expansion turbines are used, which may be radial or axial, wherein the radial expansion turbine is connected to one end of a shaft and a generator is connected to the other end of the shaft. The expander output power shaft may be connected to the generator directly or via a reduction gearbox. The reduction gearbox allows the high-speed (rpm) turbine impeller to be matched with the desired operating speed of the generator. The type of expander and generator will indicate whether a gearbox is required and the type of gearbox. In alternative embodiments, the expansion turbine may also be a bulky machine, such as a volute, screw, or bladed expander. The desired output of the geothermal power generation system 100 is more than 1 MW per expander, which makes high-speed and compact expansion turbines a preferred embodiment, as bulky expanders become large and expensive for the target power output.

[0132] In another implementation, multiple expanders can be used to maximize the generated power. Using multiple expanders is advantageous when the size of the expanders is limited for constructability or efficiency, or when certain working fluids are allowed to expand in 200 stages (flash), where the first stage flashing occurs in the main expander, but the energy is present in the working fluids, which can then be flashed again to lower pressures or in parallel with that first stage flashing. When an expansion turbine is included, the gaseous working fluid 208 can expand as it passes through the included conical radial turbine, thus reducing the pressure and temperature of the gaseous working fluid 208 while driving the turbine. Similar to a previous embodiment of turbine system 132, the rotation of the radial turbine generates mechanical energy, which is transferred to a generator, where it is converted into commercially marketable electricity. The voltage from the generator can be increased using a power step-up transformer to match the requirements of a third-party power transmission line for electricity sales to a desired market.

[0133] Low-pressure gaseous working fluid 208 is output from turbine system 132. In an alternative embodiment, depending on the characteristics of the working fluid 200 used, turbine system 132 may partially change the state of the received input gaseous working fluid 208 into a mixture of gaseous and liquid states.

[0134] Cooler 136 (also referred to as condenser 136) is arranged between turbine system 132 and pump 104 and is fluidly connected to both turbine system and pump. Cooler 136 is configured to receive low-pressure gaseous working fluid 208 output from turbine system 132 and to cool and condense the low-pressure gaseous working fluid 208 into liquid working fluid 204 by using a heat exchanger cooled by forced draft air or by a mechanical cooler (not shown). In embodiments where the working fluid 200 leaving turbine system 132 and received by cooler 136 is in a mixed state of gaseous and liquid, the amount of energy used by cooler 136 can be reduced because less work may be required to cool the working fluid 200 to a liquid state. Alternatively, the residence time of working fluid 200 within cooler 136 can also be reduced. Those skilled in the art will recognize that the specifications of the cooler 136 used may 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.

[0135] When cooler 136 is fluidly connected to pump 104, the liquid working fluid 204 output from cooler 136 returns to pump 104 to be re-delivered through the full-casing downhole circulation loop 108. Preferably, cooler 136 is a finned tube type with forced-draft ambient air as the coolant. This type of condenser cooler 136 is efficient and relatively inexpensive. However, other embodiments can be used, such as brazed aluminum plate type, tubular type, or other heat exchangers with working fluid cooled by an isolating coolant.

[0136] Connectors 168, 172, and 176 serve as attachments to complete the portion of the single heat exchange loop above the surface 316. Specifically, connector 168 serves as a connector to connect the fluid of the opening 110A of the common well section 118 to the inlet of the turbine system 132. Similarly, connector 172 connects the fluid of the turbine system 132 to the inlet of the cooler 136. Furthermore, connector 176 serves as a connector to connect the outlet of the cooler 136 to the inlet of the pump 104.

[0137] As described above, the entire casing downhole circulation loop 108 is lined and casing-equipped to physically isolate the working fluid 200 from the rock formation 320 and the environment. In the current embodiment, connectors 168, 172, and 176 may be steel pipes; however, in alternative embodiments, connectors 168, 172, and 176 may be made of other leak-proof materials that can withstand pressure and temperature variations above the surface. In a preferred embodiment, connector 168 between the outlet of opening 110A and turbine system 132 may also be insulated to prevent heat loss before the gaseous working fluid 208 reaches turbine system 132. However, in alternative embodiments, all surface connectors 168, 172, and 176 may also be insulated to reduce heat loss, which could lead to parasitic losses. Furthermore, individual heat exchange loops of the geothermal power generation system 100 (which may include connectors 168, 172, and 176) will be pressure tested to ensure no leakage while the working fluid 200 is being delivered under pressure variations. Those skilled in the art will appreciate that the connectors 168, 172, and 176 can have any shape or size, depending on the location and specifications of the working fluid 200, opening 110A, turbine system 132, cooler 136, and pump 104. Those skilled in the art will also appreciate that in embodiments where components (e.g., cooler 136 and pump 104) are combined into a single unit, certain connectors may be unnecessary and can be omitted.

[0138] like Figure 3 As shown, the geothermal power generation system 100 may also include a storage container 188 (also referred to herein as storage tank 188) to store excess liquid working fluid 204 and provide a sufficient and stable mass flow to pump 104. Although not shown, other components (such as valves, heat exchangers, and other instruments) may be used to optimize the geothermal power generation system 100. In an alternative embodiment, a filter or filter separator may also be added to the opening 110A upstream of the turbine system 132; however, in the current embodiment, a filter is not necessary if all pipes are sufficiently cleaned and free of manufacturing lubricants, chips, dirt, and other contaminants before commissioning of the turbine system 132, since the individual working fluid 200 in the individual heat exchange loop is virtually free of debris or foreign particles during normal operation.

[0139] Figure 1 A geothermal power generation system 100A is described, which is Figure 2 and 2 The diagram shows an alternative implementation of the geothermal power generation system. For convenience, Figure 3 and Figure 4Similar elements or structures shown are identified by the same reference numerals. System 100A is similar to System 100 in all material respects, except that in Geothermal Power Generation System 100A, a co-current heat exchanger 184 (also referred to herein as heat exchanger 184) is provided. Co-current heat exchanger 184 is arranged between and connected to turbine system 132 and cooler 136, and is also arranged between and connected to pump 104 and insulated injection pipe 114. Co-current heat exchanger 184 is configured to minimize the cooling load on cooler 136 and to preheat liquid working fluid 204 before entering insulated injection pipe 114 by exchanging heat between gaseous working fluid 208 from the outlet of warm low-pressure turbine system 132 and cold liquid working fluid 204 from the outlet of pump 104. As the low-pressure gaseous working fluid 208 exits the turbine system 132 and travels through the co-current heat exchanger 184, it can transfer its heat to the cold liquid working fluid 204, which also travels through the co-current heat exchanger 184 from the outlet of the pump 104 to the insulated injection pipe 114. By providing the heat from the low-pressure gaseous working fluid 208 exiting the turbine system 132 to the cold liquid working fluid 204 traveling toward the insulated injection pipe 114, thermal energy is saved and reused. The low-pressure gaseous working fluid 208 exiting the turbine system 132 travels toward the cooler 136 to condense and cause a phase change, and thus, the thermal energy from the low-pressure gaseous working fluid 208 is transferred before reaching the cooler 136, reducing the time and energy required for the cooler 136 to condense the gaseous working fluid 208 into a liquid. Furthermore, the liquid working fluid 204 traveling through the insulated injection pipe 114 flows underground to be heated, and therefore, preheating the liquid working fluid 204 can reduce the required underground residence time, thus potentially allowing for shorter lateral sections 116 and 124 or allowing lateral sections 116 and 124 to be at shallower depths. Those skilled in the art will recognize the possibility of the co-current heat exchanger 184 and the possible configurations of geothermal power generation systems having the co-current heat exchanger 184.

[0140] In an alternative embodiment, the geothermal power generation system 100 can be used for purposes other than power generation. For example, the energy generated from the geothermal power generation system 100 can be used to influence the operation of other machinery. Alternatively, the energy generated from the geothermal power generation system 100 can be used for hydrogen production.

[0141] Reference Figure 5A flowchart illustrating the steps of a method 400 for operating a geothermal power generation system 100 according to an embodiment of the present invention is shown. Operation of the geothermal power generation system 100 occurs after the system has been prepared and started up, and after a Rankine cycle (preferably an organic Rankine cycle using an organic carbon-based working fluid). An example of preparing the geothermal power generation system 100 includes slowly circulating the working fluid 200 through the insulated injection pipe 114 and the injection well 112, allowing any residual liquid or gas (from the construction process or from previous operations of the geothermal power generation system 100) to exit into a storage container to be collected. Once all residual liquid or gas has been removed, the working fluid 200 can be continuously circulated through the geothermal power generation system 100 as part of its normal operation. It can be seen that method 400 is cyclical. For ease of understanding, the process can be described as starting at step 405 and ending at step 440 before restarting the process at step 405.

[0142] As previously described, the geothermal power generation system 100 is a single heat exchange loop with a full-casing downhole circulation loop 108. When the full-casing downhole circulation loop 108 is integrally casing and pressure tested, the working fluid 200 can be a variety of liquids, gases, or plasmas. In an alternative embodiment, the working fluid 200 can be a commercially available and environmentally friendly carbon-based refrigerant or a mixture of refrigerants, such as 90% propane and 10% molar fraction ethane. Alternatively, the working fluid 200 can be a composition of hydrocarbons, carbon dioxide, or ammonia (multiphase working fluid 200) or a single substance (homogeneous working fluid 200). In a preferred embodiment where the geothermal power generation system 100 is an organic Rankine cycle, the working fluid 200 can be propane. When using propane, at a depth of 2000 m and a rock formation temperature of approximately 160°C at 320°C, the maximum temperature achievable with the propane working fluid 200 is approximately 140°C. Furthermore, propane working fluid 200 can be condensed into liquid working fluid 208 in hot summer conditions without requiring sufficient cooling from ambient air forced through finned tube cooler 136. While propane is the chosen working fluid 200, other organic (carbon-based) fluids, such as hydrocarbons or hydrocarbon mixtures, can be used. Hydrocarbon mixtures can be used to maximize the return pressure of working fluid 200. Hydrocarbon mixtures allow working fluid 200 to adapt to specific depth and temperature conditions. For example, adding ethane to propane-based working fluid 200 will allow for earlier flashing in the wellbore at a specific formation temperature 320. Premature flashing will increase the flow rate of working fluid 200 and thus increase power generation. Another example is blending hydrocarbons with butane to increase the heat carrying capacity of the working fluid. By incorporating heavier hydrocarbons, the flash point / vaporization point along the full casing downhole circulation loop 108 can be adjusted according to the temperature of the surrounding formation 320. For example, the vaporization point can be adjusted based on the temperature of the surrounding rock formation 320 along the upper lateral section 124 or the production well 128 to maximize the velocity of the working fluid 200 and minimize friction along the remainder of the casing before it leaves the full casing downhole circulation loop 108. Those skilled in the art will recognize the potential combinations of different variations in the temperature of the rock formation 320 and the hydrocarbon mixture to adjust the location of the vaporization point along the full casing drilling loop 108. While the working fluid 200 could also be water, it is preferably one of the aforementioned fluids because these substances have lower boiling points than water and require less underground residence time. Furthermore, the aforementioned fluids can have favorable heat capacities and different phase transition points, thereby making the system more efficient and requiring less underground residence time in the full casing downhole circulation loop 108.

[0143] The following steps describe an implementation where the working fluid 200 is propane. In step 405, the propane liquid working fluid 204 is delivered underground by flowing downwards along the insulated injection pipe 114, through the injection well 112, and along the upper lateral section 116, the multi-branch connector 120, and the lower lateral section 124. To reach the insulated injection pipe 114 and the injection well 112, the liquid working fluid 204 is pumped using a pump 104. In effect, the pump 104 circulates the working fluid 200 through a single heat exchange loop throughout the entire casing. To ensure proper circulation, the pump 104 increases the pressure of the liquid working fluid 204 from 1080 kPag to 1300 kPag, which is to be received by the insulated injection pipe 114. In the current embodiment, after the propane working fluid 200 leaves the pump 104 and before being received by the insulated injection pipe 114, the liquid working fluid 204 can have a temperature range of about 10°C to about 40°C (preferred temperature about 20°C) and a pressure range of about 1000 kPag to about 2000 kPag (preferred pressure about 1300 kPag). Once the liquid working fluid 204 leaves the pump 104, it flows downward through the insulated injection pipe 114 and subsequently along the injection well 112.

[0144] When the liquid working fluid 204 reaches the curved connector 160, the flow direction of the liquid working fluid 204 changes from vertical to lateral and then continues along the upper lateral section 116. Then, the liquid working fluid 204 reaches the multi-branch connector 120, where the liquid working fluid 204 changes direction to flow into the lower lateral section 124 and continues to flow until the curved connector 164 adjacent to the lower end 198 of the production well 128.

[0145] Towards the lower end 196 of the injection well 112 and at the depths of the upper lateral section 116, the multi-branch connector 120, and the lower lateral section 124, the surrounding environment and rock strata 320 naturally conduct heat from the surrounding rock strata 320. As the liquid working fluid 204 flows downwards along the injection well 112, heat is transferred from the surrounding environment or rock strata 320 to the liquid working fluid 204 when the liquid working fluid 204 reaches a depth where the temperature of the rock strata 320 exceeds the temperature of the liquid working fluid 204 (in step 405). Heat transfer can occur while the liquid working fluid 204 continues to flow downwards through the injection well 112, and continues as the liquid working fluid 204 flows past the connector 160 and the upper lateral section 116. This heat can be conductively transferred from the surrounding environment to the liquid working fluid 204 through the cement lining 152 and the steel casing 156. The depth threshold at which the liquid working fluid 204 begins to receive heat and thus increases its temperature is the location where the ambient temperature is higher than the temperature of the liquid working fluid 204. This depth threshold depends on the geothermal gradient of the site and the re-injection temperature of the working fluid. As the liquid working fluid 204 flows through the multi-branch connector 120 and the lower lateral section 124, heat continues to be transferred to the liquid working fluid 204, causing its temperature to rise as it flows over these components.

[0146] Furthermore, as the liquid working fluid 204 flows downward in the injection well 112, the pressure exerted on the liquid working fluid 204 by the hydrostatic head increases (in step 415). As the liquid working fluid 204 reaches the connector 160 and the upper lateral section 116, the pressure of the liquid working fluid 204 continues to increase as the fluid absorbs heat. While the pressure decreases slightly due to flow velocity friction losses in the wellbore, the net pressure of the liquid working fluid 204 increases. As provided in the current embodiment, the approximate pressure of the liquid working fluid 204 upon reaching the lower end 196 / connector 160 of the injection well 112 is approximately 10,000 kPag at a depth of approximately 2,000 m. Although the pressure increases during the depth change, the rate of heat transfer, and therefore the rate of temperature rise of the liquid working fluid 204, depends on the depth, the thermal conductivity of the rock, the residence time, and the temperature of the rock formation 320. Therefore, as the liquid working fluid 204 flows downward in the injection well 112, laterally along the upper lateral section 116, and flows through the multi-branch connector 120, the temperature continues to rise. The increase in heat transfer and applied pressure is depicted in step 415.

[0147] In step 420, at some point where the liquid working fluid 204 flows through the upper lateral section 116, connector 160, multi-branch connector 120, connector 164, and lower lateral section 124, the liquid working fluid 204 will undergo a phase change from liquid to gaseous due to the liquid working fluid 204 reaching its boiling point due to heat and increased pressure (in step 415). More specifically, the rate of temperature increase increases until the liquid working fluid 204 begins to vaporize, at which point the temperature will remain constant until all the liquid working fluid 204 transforms into a gaseous state (gaseous working fluid 208), and then the temperature will rise again as the vapor or gaseous working fluid 208 superheats. Those skilled in the art will appreciate 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 current embodiment where the working fluid 200 is propane, it is vaporized at a temperature of approximately 140°C and a pressure of approximately 6250 kPag. In a preferred embodiment, the phase change will occur within the lower lateral section 124 or the production well 128 to minimize the amount of friction between the working fluid 200 and the remaining length of the casing before the working fluid 200 leaves the full casing downhole circulation loop 108, thus maximizing the velocity of the working fluid 200. However, those skilled in the art will recognize that the phase change of the working fluid 200 may occur anywhere underground within the full casing downhole circulation loop 108. Those skilled in the art will recognize that the location along the flow path of the working fluid within the full casing downhole circulation loop 108 will vary depending on the following: the configuration of the full casing downhole circulation loop 108, the length and depth of the components within the full casing downhole circulation loop 108, the flow rate of the working fluid 200, the boiling point of the working fluid 200 and the temperature of the rock formation 320, and the conduction rate from the rock through the steel casing 156 and cement 152 into the working fluid 200.

[0148] In step 425, the gaseous working fluid 208 rises to the surface 316 via the production well 128, the insulated production pipe 166, and the common well section 118, and exits the casing downhole circulation loop 108 at opening 110A. As the gaseous working fluid 208 rises to the surface 316, its pressure and temperature will be slightly reduced due to the depth change; however, the temperature of the working fluid 208 is sufficient to maintain its gaseous state. At the outlet of opening 110A, the approximate temperature of the gaseous working fluid 208 is between approximately 90°C and approximately 110°C (preferably approximately 106°C), and the pressure is between approximately 3000 kPag and approximately 4000 kPag (preferably 3500 kPag). The gaseous working fluid 208 is then conveyed along connection 168 toward the turbine system 132.

[0149] Therefore, in the current embodiment, when the temperature of the liquid working fluid 204 at the inlet of opening 110A is about 30°C and about 1080 kPag, and the temperature of the gaseous working fluid 208 at the outlet of opening 110A is about 106°C and about 3500 kPag, the working fluid 200's temperature increases by about 76°C and its pressure increases by about 2170 kPag as it travels through the full casing downhole circulation loop 108. Furthermore, in the current embodiment, the residence time of the working fluid 200 between its entry into opening 110A and its exit from opening 110A is about 30 minutes. Those skilled in the art will recognize that the temperature difference and residence time are influenced by a number of factors, including but not limited to the construction, depth, and length of the components of the full casing downhole circulation loop 108, as well as the temperature of the rock formation 320, the thermal conductivity of the rock, the conductivity of the working fluid 200 entering the working fluid 200 from the rock through casing 156 and cement 152, and the flow rate of the working fluid 200.

[0150] In the current embodiment where the working fluid 200 is propane, the temperature of the propane can be between the approximate temperature of the surrounding environment / environment (ambient temperature) when it enters the complete casing downhole circulation loop 108 from the inlet of opening 110A and 185°C when it leaves the complete casing downhole circulation loop 108 from the outlet of opening 110A. The ambient temperature can vary depending on the environment in which the geothermal power generation system 100 is located and can vary between -43°C and 45°C.

[0151] In the current embodiment, turbine system 132 is an expansion turbine. In step 430, turbine system 132 receives gaseous working fluid 208, which drives the turbine (also referred to herein as a turbine impeller) to generate mechanical energy. This mechanical energy is transferred to the generator when the turbine impeller is connected to a shaft connected to a generator, which then converts the mechanical energy into electrical energy at step 435. In this embodiment, the gaseous working fluid 208 expands by means of the shape of the expander / valve, and the pressure and temperature of the gaseous working fluid 208 are also reduced, while simultaneously rotating the radial turbine connector connected to the shaft. The approximate pressure of the propane gaseous working fluid 208 exiting turbine system 132 is in the range of about 1500 kPag to about 700 kPag, and the approximate temperature is in the range of about 63°C to about 16°C. In a preferred embodiment, the approximate pressure and temperature of the gaseous working fluid 208 can be readily condensed from the gaseous working fluid 208 into a liquid working fluid 204 by ambient air temperature and cooler 136. The electrical energy generated by the generator at step 435 is approximately 1 MW and can fluctuate depending on the cooler condensation pressure under ambient conditions. Therefore, a reduction in the load required for cooler 136 to condense the gaseous working fluid 208 will increase the net electrical energy generated by the generator. Those skilled in the art will recognize that any reduction in parasitic load (e.g., the energy required to cool the gaseous working fluid 200) will increase the amount of electrical energy generated and increase the efficiency of the geothermal power generation system 100. Those skilled in the art will appreciate that in some embodiments, depending on the efficiency of turbine system 132 and the specifications of working fluid 200, the working fluid 200 leaving turbine system 132 can be in a mixed state of gaseous and liquid.

[0152] In step 440, the gaseous working fluid 208 leaving the turbine system 132 can travel along the connector 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 can be 30°C and 1080 kPag, but can fluctuate depending on the ambient air temperature and pressure.

[0153] Upon exiting the cooler 136, the liquid working fluid 204 can return to the pump 104 via the connector 176, whereby the liquid working fluid 204 is recirculated, as can be seen in step 405.

[0154] See Figure 4 The figure shows a flowchart illustrating the steps of a method 400A for operating a geothermal power generation system 100A according to an embodiment of the present invention. For convenience, in Figure 5 and Figure 4The same reference numerals are used to describe the same steps. Method 400A is similar to Method 400 in all respects, except for the presence of additional steps 437 and 432 related to the co-current heat exchanger 184.

[0155] Steps 405, 415, 420, 425, 430, and 435 are as described above. Figure 4 The process is performed as described in the context of the method 400 shown. Step 437 occurs after step 435, where the gaseous working fluid 208 transfers heat to a parallel conduit containing the liquid working fluid 204 (received by the liquid working fluid 204, as detailed below in step 442). By transferring heat via the co-current heat exchanger 184, the temperature of the gaseous working fluid 208 decreases, and therefore, in the subsequent step 440, the cooler 136 may require less energy to condense the gaseous working fluid 208. The temperature of the gaseous working fluid 208 decreases by approximately 15°C after leaving the co-current heat exchanger 184 and before being received by the cooler 136.

[0156] Subsequently, step 440 is as described above. Figure 6A The process described in the context of method 400 involves the condensation of a gaseous working fluid into a liquid working fluid. Following step 440, in step 442, the liquid working fluid 204 enters the co-current heat exchanger 184 and receives heat therefrom. More specifically, the co-current heat exchanger 184 interacts with the working fluid 200 at two locations along this single heat exchange loop: specifically, after the turbine system 132 as a gaseous working fluid 208, and after the pump 104 as a liquid working fluid 204. These two conduits carrying the working fluid 200 are very close together in the co-current heat exchanger 184, allowing heat to be transferred from the gaseous working fluid 208 to the liquid working fluid 204. Therefore, in step 442, the liquid working fluid 204 receives heat from the gaseous working fluid 208 (which was transferred from the gaseous working fluid 208 in step 437), thereby raising the temperature of the liquid working fluid 204 before proceeding forward to the insulated injection pipe 114. In this embodiment, the temperature of the liquid working fluid 204 can increase by up to 10°C after leaving the co-current heat exchanger 184 and before reaching the insulated injection pipe 114.

[0157] Those skilled in the art will appreciate that the approximate temperature and pressure ranges provided above can be varied depending on the configuration of the geothermal power generation system 100 or 100A, as well as the specifications of the working fluid 200 used and the ambient air temperature. Those skilled in the art will also recognize that although approximate temperature and pressure ranges are provided in the foregoing embodiments where the preferred working fluid 200 is a commercially available and environmentally friendly carbon-based refrigerant, the geothermal power generation system 100 will continue to operate even if the preferred working fluid 200 is outside these approximate temperature and pressure ranges.

[0158] refer to Figure 6B An embodiment of a geothermal power generation system 100-1 is illustrated, which includes two full-casing downhole circulation loops 108-1 and 108-2, wherein the two full-casing downhole circulation loops 108-1 and 108-2 are connected to a single connecting wellbore 140. As will be further described below, construction is simplified because only a single connecting wellbore 140 needs to be drilled. Furthermore, by using a single connecting wellbore 140, the coverage area of ​​the geothermal power generation system is further minimized. Those skilled in the art will recognize that the geothermal power generation system 100-1 is not limited to two full-casing downhole circulation loops, but can be any number of full-casing downhole circulation loops.

[0159] In an embodiment of the geothermal power generation system 100-1, the two full-casing downhole circulation 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 the multi-branch connectors 120-1 and 120-2, the lateral section of the connecting well 140 extends to allow for the further arrangement of additional multi-branch connectors 120. The lateral section of the connecting well 140 can extend deeper to increase the number of multi-branch connectors 120 arranged, and, where space permits, allow for the arrangement of additional full-casing downhole circulation loops 108. In an alternative embodiment, the additional multi-branch connectors 120 can be arranged at different depths along the connecting well 140, or even arranged at sides that can be at different depths. Furthermore, the additional multi-branch connectors 120 can also be arranged at different locations along the periphery of the connecting well 140, or at different locations along the periphery of the connecting well 140 branching off from the connecting well 140. Those skilled in the art will recognize the different possible configurations and arrangements of the multiple multi-branch connectors 120 relative to the connection well 140.

[0160] See Figure 1 Components of two complete casing downhole circulation loops, 108-1 and 108-2, can be seen. These two complete casing downhole circulation loops, 108-1 and 108-2, have similar features to those previously seen in... Figure 2 , Figure 3 and Figure 6CThe components mentioned are similar to those of the complete casing downhole circulation loop 108. Thus, the components within each of these two complete casing downhole circulation loops 108-1 and 108-2 are numbered similarly to those of complete casing downhole circulation loop 108, and are appended with a -1 or -2 suffix to indicate the first or second complete casing downhole circulation loop 108-1 or 108-2. Given the similarity of the components, no further description of the components will be provided.

[0161] In embodiment 100-1, the two full casing downhole circulation loops 108-1 and 108-2 operate in the same manner as the previously mentioned embodiment of full casing downhole circulation loop 108. However, after exiting their respective openings 110A-1 and 110A-2, the two gaseous working fluid 208 flows can be merged into a single flow to be received by a single turbine system 132. Therefore, the merging connector 168-1 can be configured to allow the two gaseous working fluid 208 flows to merge. Furthermore, a single cooler 136 can receive the gaseous working fluid 208 exiting the turbine system 132 to condense the gaseous working fluid 208 into liquid working fluid 204. The liquid working fluid 204 can then be separated into two streams using the separator connector 176-1 so that they can be received by pumps 104-1 and 104-2. Pump 104-1 can increase the pressure of the liquid working fluid 204 in the insulated injection pipe 114-1, and pump 104-2 can increase the pressure of the liquid working fluid 204 in the insulated injection pipe 114-2.

[0162] When using embodiment 100-1, the number of required components or equipment can be minimized because the turbine system 132 and cooler 136 can be shared across the full casing downhole circulation loops 108-1 and 108-2. This further minimizes costs. Furthermore, the cover area and the surface area above the ground are minimized because only a single turbine system 132 and cooler 136 exist above the ground, as opposed to having multiple turbine systems 132 and coolers 136 for each full casing downhole circulation loop 108-1 and 108-2. In the current embodiment, the surface area above the ground can be approximately 30,100 m². 2 Furthermore, scalability and economies of scale are inherent characteristics of the design of implementation method 100-1, as will be discussed below.

[0163] Those skilled in the art will recognize the modularity of the turbine system 132, cooler 136, and pump 104. Specifically, they will recognize that any number of complete casing downhole loops 108 can be connected to a single turbine system 132, a single cooler 136, and a single pump 104. Alternatively, any number of complete casing downhole loops can be connected to multiple turbine systems 132, single coolers 136, and single pumps 104. Similarly, any number of complete casing downhole loops can be connected to a single turbine system 132, multiple coolers 136, and a single pump 104. Alternatively, as can be seen from embodiment 100-1, multiple pumps 104 can be used. Thus, those skilled in the art will recognize the different combinations and variations of the complete casing downhole loops 108, turbine system 132, cooler 136, and pump 104.

[0164] Furthermore, as previously described, the geothermal power generation system 100-1 may have any number of full-casing downhole circulation loops 108 connected to a single connecting wellbore 140. Those skilled in the art will appreciate several different possible arrangements of any number of full-casing downhole circulation loops 108 associated with a single connecting wellbore, some of which may allow for smaller surface areas and coverage zones. Figure 6C An example arrangement is provided for five full casing downhole circulation loops (each provided as reference numerals 108-1, 108-2, 108-3, 108-4, and 108-5) connected to a single connecting wellbore 140. Lateral sections 140A extend away from the connecting well 140 to provide areas for arranging multi-branch connectors 120 for each of the five full casing downhole circulation loops. In a preferred embodiment, isolation packers 330 may be present between each multi-branch connector 120 to isolate each multi-branch connector 120 of each full casing downhole circulation loop 108 from each other. It can be seen that in Figure 6BIn this embodiment, each of the five full-casing downhole circulation loops includes a first lateral segment and a second lateral segment extending from the common positioning well. In the currently described embodiment, the five full-casing downhole circulation loops are equidistant from each other; however, this can vary depending on the surrounding rock formations. The trajectory of the directional section 140A is unrestricted and can vary. Furthermore, the lateral section 140A is not limited to being straight, but may include a combination of angled and straight sections. The lateral section 140A is also not limited to having five full-casing downhole circulation loops 108, and may have additional or fewer full-casing downhole circulation loops 108 in each lateral section 140A. Furthermore, more than one lateral section 140A extending away from the connecting well 140 may exist. For example (not shown), two lateral sections 140A extending away from the connecting well 140 in opposite directions may be provided, thus offering ten full-casing downhole circulation loops. Those skilled in the art will now recognize the different possible layouts, arrangements, and configurations of the full casing downhole loop 108 associated with the connecting well 140.

[0165] In commercial operation, when multiple well rings generate electricity and sell it to power transmission lines via sales meters, it is desirable to control the amount of electricity generated. For example, when 25 MW needs to be fed into the grid, twenty-five (25) full-casing downhole circulation loops 108 can be used. An on / off power control scheme is used to output 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 processing logic controller (PLC). In an embodiment where a single turbine system 132 is connected to the twenty-five (25) full-casing downhole circulation loops 108, the PLC will then automatically shut down pump 104 and other rotating equipment and close the electronically actuated wellhead valves to quickly “shut down” the individual geothermal well ring. This on / off control system allows the facility to change power output between 0 MW and 25 MW in 1 MW increments. Alternatively, in an embodiment with twenty-five (25) turbine systems 132 connected to twenty-five (25) full casing downhole circulation loops 108, the PLC can then shut down pump 104 and turbine system 132 for each full casing drilling loop 108, thereby allowing the facility to provide power output in increments of 1 MW from 0 MW to 25 MW.

[0166] This control scheme can also be used in pre-defined scheduling. The advantages of the on / off control system are its relatively simple design and operation, and it provides good power output control. This control scheme can be used because, as... Figure 1The single closed-loop system shown involves the working fluid interacting with the underground storage unit solely through conduction. No storage fluid enters the geothermal loop, and no well working fluid 200 enters the storage unit. All good heating occurs via conductive heat transfer. Therefore, by isolating the flow rate of the working fluid 200 to the insulated injection pipe 114 and the injection well 112, power generation can be rapidly altered to stop the well from generating power. Moreover, when the well is closed, it allows the underground rock to be “recharged” through conductive heating, and when the well is reopened, the full casing downhole circulation loop 108 will be able to generate increased power (compared to steady-state operation). Those skilled in the art will recognize that the above-described control scheme is capable of controlling any number of full casing downhole circulation loops 108 and turbine systems 132.

[0167] Referring to Figure 7, a flowchart is shown illustrating the steps of a method 700 for constructing a complete casing downhole loop 108 of a geothermal power generation system 100 according to an embodiment of the present invention. More specifically, the steps of method 700 are based on... Figure 8 The system 100 shown is an embodiment of this method. The construction of the full casing downhole circulation loop 108 involves drilling and connecting a connecting wellbore 140 and a wellbore 174 comprising a common section 118 and a production well 128 using a drilling rig, and further drilling an injection well 112 as a branch of the common section 118 at connection point 122. As will become apparent in method 700, the initial drilling of the common section 118 connecting wellbore 140 and wellbore 174 may require at least one large drilling rig to run heavy intermediate casing. Alternatively, two large drilling rigs can be used, one for drilling the connecting wellbore 140 and running heavy intermediate casing in the connecting wellbore 140, and a second for drilling the common section 118 of wellbore 174 and running heavy intermediate casing in wellbore 174.

[0168] Step 705 includes drilling the connecting borehole 140 and the common well section 118. In the current embodiment described below, the connecting borehole 140 may be drilled first; however, those skilled in the art will appreciate that the common well section 118 may also be drilled first, or both the connecting borehole 140 and the common well section 118 may be drilled simultaneously. Those skilled in the art will also appreciate that the connecting borehole 140 can be formed by modifying an existing well. For example, the connecting borehole 140 may be a pre-existing well for oil drilling, or a pre-existing well with a previously configured surface casing or intermediate casing.

[0169] Returning to the current implementation, both the connecting borehole 140 and the common well section 118 are to be drilled, and the two drilling rigs are movable and fixed at separate surface locations. (See reference) Figure 1These are positions 304 and 308. The predetermined distance between positions 304 and 308 is at least the length of lateral segments 116 and 124 (e.g., Figure 9 (as shown) and any offset distance required for the construction angle within the well trajectory. It will be apparent to those skilled in the art that, in this case, the positioning of the two rigs is based on an embodiment of the full casing downhole loop 108, wherein the common section 118, injection well 112, production well 128, lateral sections 116 and 124, and multi-branch connector 120 are arranged along the same vertical plane, and the positioning of the two rigs can be adjusted based on the position and configuration of the components of the full casing downhole loop 108.

[0170] The first drilling rig, located at position 304 above the planned connecting borehole 140, can drill a hole with a diameter between 7 7 / 8” and 12 1 / 4” and a depth between 650 m and 2000 m. In a preferred embodiment, a hole with a diameter of 440 mm (17 ¼”) and a depth of approximately 650 m is drilled. The drilling mud / fluid used can be an environmentally friendly freshwater gel system. Examples of drilling mud include, but are not limited to, bentonite as a gel, along with additives such as barite, calcium carbonate (chalk), or hematite. Those skilled in the art will recognize the various drilling muds that can be used in conjunction with the drilling rig.

[0171] After drilling, a surface casing 212 can be installed in place. The surface casing 212 can be installed in place and has a depth matching the drilled hole. In a preferred embodiment, the surface casing 212 is installed in place with a diameter of 340 mm (13 3 / 8") and will extend to a depth of approximately 650 m. The entire length and perimeter of the surface casing 212 will be cemented to the surface 316. The surface casing 212 is important for ensuring that the planned connection wellbore 140 is fixed in place, preventing shallow formations from collapsing into the wellbore, and providing a base for the Class 5 blowout preventer described below.

[0172] A second drilling rig located at position 308, at both planned wellbore 174 and common well section 118, can drill a second hole for surface casing 144. The drilled hole can have a diameter between 12 ¼” and 17 ½” and a depth between 300 m and 650 m. In a preferred embodiment, the drilled hole can have a diameter of 12 ¼” and 17 ½” and a depth of approximately 650 m. Similar to the drilling by the first drilling rig located at position 304, the drilling mud of the second drilling rig can be an environmentally friendly freshwater gel system.

[0173] After drilling the second borehole, the surface casing 144 can be installed. The surface casing 144 can be installed with a diameter between 9 5 / 8” and 13 3 / 8” and a depth between 300 m and 650 m. In a preferred embodiment, the surface casing 144 is installed with a diameter of 9 5 / 8” and 13 3 / 8” and will extend to a depth of approximately 650 m. The entire length and perimeter of the surface casing 144 will be cemented to the surface 316. Similar to the surface casing 212, the purpose of the surface casing 144 is to ensure that the planned injection well 112 is fixed in place, prevent shallow formations from collapsing into the borehole, and provide a base for the Class 5 blowout preventer described below. Furthermore, the surface casing 144 is used to ensure that any working fluid 200 does not leak into the surrounding environment.

[0174] The cement casing used for surface casings 144 and 212 will preferably have a total calculated borehole volume plus a 50% excess of 1860 kg / m³. 3 Hot-mixed cement (total cement mass approximately 80t). The cement casing can then withstand 2.5 m. 3 First pre-flushing with fresh water. The cement casing can then withstand a weight increase to 1200 kg / m. 3 5 m 3 The second pre-rinse with the thickening agent. Examples of thickening agents include Opiflush. TM Those skilled in the art will recognize other forms or variations of the thickening water. A cement plug can then be inserted and replaced with fresh water.

[0175] A Class 5 blowout preventer (not shown) may be installed on or near surface casings 144 and 212. The Class 5 blowout preventer is used to seal, control, and monitor wellbore 174 and connecting wellbore 140 to prevent rupture. In the current embodiment, the Class 5 blowout preventer is pressure tested at low pressures ranging from 1400 kPa to high pressures ranging from 35000 kPa, wherein the test at each pressure lasts for at least ten (10) minutes. Pressure testing of the Class 5 blowout preventer may also be performed according to formation pressures and any applicable regulatory requirements. Those skilled in the art will recognize that the Class 5 blowout preventer can be tested at different pressures and for different durations.

[0176] Drilling for the common section 118 and connecting borehole 140 will be directional controlled using a directional drilling assembly and will maintain target accuracy through measurement while drilling (“MWD”). Specifically, the first drilling rig at location 304 will drill a hole through surface casing 212 with a diameter between 7 7 / 8” and 12 ¼” to a predetermined depth. In a preferred embodiment, the first drilling rig will drill through the surface casing and a 311 mm (12 ¼") diameter intermediate hole (not shown) to a predetermined depth. Initially, the connecting borehole 140 will be drilled vertically, then directionally to achieve a 90-degree inclination at a landing point 228 near the lower end 216 of the connecting borehole 140. This landing point 228 will be located in the geothermal target formation at a depth with the target temperature. In the current embodiment, the connecting borehole 140 is drilled using an oil-based mud system to minimize flushing and protect borehole integrity. However, the drilling mud system used may depend on the region and the region's historical drilling problems. Those skilled in the art will recognize the different potential drilling mud systems that can be used.

[0177] Subsequently, the intermediate heating sleeve 236 will extend along the total depth of the connecting borehole 140, and the intermediate heating sleeve 236 can be cemented to the surface of the surrounding rock formation 320. In a preferred embodiment, the intermediate sleeve 236 has a diameter of 244 mm (9 5 / 8"), however, in other embodiments, the intermediate sleeve 236 may have a diameter of 7” to 9 5 / 8”. The intermediate heating sleeve 236 can then travel 5m. 3 The first pre-flushing with thickening water involves weighting the water to provide a borehole pressure / static pressure greater than the formation pressure, thus maintaining an overbalanced wellbore. The intermediate hot casing 236 can then withstand weighting up to 1450 kg / m. 3 or 5 m higher 3 A second pre-flushing with a cleaning agent is performed to maintain an overbalanced wellbore. An overbalanced wellbore will prevent formation gas or fluid from entering the wellbore and rising to the surface. Cement is then filled / provided into the intermediate hot casing 236; this cement is the total calculated well volume plus a 20% margin (approximately 75 t) of insulating cement. Tail cement is then applied at a 20% margin (approximately 45 t) of airtight cement. The inner diameter of the cement is then replaced with fresh water to form a hollow wellbore, while the outer diameter is cemented to the rock formation 320.

[0178] The volume and mixture of cement can be adjusted based on historical well data, formation pressure, and regional control isolation requirements for certain formations to prevent crossflow contamination.

[0179] The intermediate hot casing 236 can be secured at the wellhead / inlet 232 using a velocity head or an additional wellhead section to install slips. The slips (also referred to herein as anchors) can be configured such that the intermediate hot casing 236 is under full tension to retain it within the surface casing 212. In some embodiments, the Stage 5 blowout preventer on the surface casing 212 may need to be removed for slip installation. Once reassembled, the Stage 5 blowout preventer can be pressure tested again at the same pressure and specifications to confirm its integrity after reassembly, however, with the intermediate hot casing 236 within the connecting well 140. The Stage 5 blowout preventer can also be pressure tested again to meet the expected pressure and / or management requirements of the formation 320.

[0180] A gyroscopic wireline survey tool can be deployed in the connecting borehole 140. The gyroscopic wireline survey tool allows for continuous measurements from vertical to horizontal and from points where measurements are missed. The gyroscopic wireline survey tool provides the well geometry with extremely high level of accuracy and gives the precise coordinates of the connecting borehole 140 to aid in intersection with borehole 174 or other future intersection points.

[0181] Relative to common well section 118, at location 308, a second drilling rig will drill to a predetermined depth through a hole (also referred to herein as an intermediate hole) in surface casing 144. This intermediate hole may have a diameter between 7 7 / 8” and 12 ¼”. In a preferred embodiment, the intermediate hole will have a diameter of 222 mm (8 ¾”). The predetermined depth may vary depending on the preferred temperature or geothermal target formation. In a preferred embodiment, this predetermined depth is between 1000 m and 3500 m. Similar to the first drilling rig drilling the main borehole of connecting well 140, a borehole for the main borehole of common well section 118 can be drilled using an oil-based mud system. Drilling assemblies can then be removed from the well. A gyro-based inclinometer can then be deployed in common well section 118 to provide coordinates for intersection with connecting well 140. Magnetic tools (such as Lodestone, as previously described) will be used. TM The new directional control drilling assembly, after being encapsulated, is lowered into the wellbore.

[0182] Subsequently, the second intermediate heat casing 238 will extend along the total depth of the common well section 118, and the intermediate heat casing 238 can be cemented to the surface of the surrounding rock formation 320. In a preferred embodiment, the intermediate casing 238 has a diameter of 9 5 / 8”; however, in other embodiments, the intermediate casing 238 may have a diameter of 7” to 9 5 / 8”. Similar to the intermediate heat casing 236 connecting well 140, the intermediate heat casing 238 can then withstand 5m 3The first pre-flushing with thickening water involves weighting the water to provide a borehole pressure / static pressure greater than the formation pressure to maintain an overbalanced borehole. Then, the intermediate hot casing 238 can undergo weighting up to 1450 kg / m. 3 or 5 m higher 3 A second pre-flushing with a cleaning agent is performed to maintain an overbalanced wellbore. An overbalanced wellbore prevents formation gas or fluid from entering the wellbore and rising to the surface. Cement is then filled / provided into the intermediate hot casing 238; this cement is the total calculated well volume plus a 20% margin (approximately 75 t) of insulating cement. Tail cement is then supplied at 20% capacity (approximately 45 t) of airtight cement. The inner diameter of the cement is then replaced with fresh water to form a hollow wellbore, while the outer diameter is cemented to the rock formation 320.

[0183] Similar to intermediate heat jacket 236, the volume and mixture of cement filled into intermediate heat jacket 238 can be adjusted according to historical well data, formation pressure, and regional control isolation requirements of certain formations to prevent crossflow contamination.

[0184] The intermediate hot casing 238 can be secured at the opening 110A using a velocity head or an additional wellhead section to install slips. The slips (also referred to herein as anchors) can be configured such that the intermediate hot casing 238 is under full tension to retain it within the surface casing 144. In some embodiments, the Stage 5 blowout preventer on the surface casing 144 may need to be removed for slip installation. Once reassembled, the Stage 5 blowout preventer can be pressure tested again at the same pressure and specifications to confirm its integrity after reassembly; however, the intermediate hot casing 238 remains in the common section 118. The Stage 5 blowout preventer can also be pressure tested again to meet the expected pressure and / or management requirements of the formation 320.

[0185] Step 710 includes drilling intermediate hot casings 236 and 238 and using a ranging technique to make the two holes intersect. Step 710 will use at least two drilling rigs, and the first drilling rig at location 304 and the second drilling rig at location 308 can be repositioned for use in step 710. Alternatively, depending on the dimensions of the lateral section, connecting well 140, and common well section 118, a smaller drilling rig than the one initially used at locations 304 and 308 can be used. Using a smaller drilling rig can result in additional cost and / or financial savings. Those skilled in the art will recognize the use of different sized drilling rigs for different surrounding environments.

[0186] The first drilling rig can be positioned within the connecting borehole 140 and will laterally drill from a drilling position 282 near the landing point 228 through the intermediate casing 236 of the connecting borehole 140 to begin constructing the lower lateral section 124. This lateral section can be drilled using an oil-based mud system to minimize flushing and protect borehole integrity. However, the drilling mud system used may depend on the area and the historical drilling problems in that area. Those skilled in the art will recognize that different possible drilling mud systems can be used.

[0187] After the lateral borehole has been drilled, the directional control drilling assembly can be removed from the well. The magnetic tool is then lowered into the wellbore to the end of the lateral borehole. An example of the magnetic tool is provided by Lodestone Scientific Drilling. TM This magnetic tool is an active ranging system specifically designed for intentional wellbore intersections. It can be used in conjunction with all MWD systems. The magnetic tool's sensor can be positioned in the connecting wellbore 140, and the magnetic component can be positioned on the directional control drilling assembly in the common well section 118. The generated magnetic field provides accurate ranging for the intersection point between the connecting wellbore 140 side and the wellbore 174 side, and also provides planning for the planned intersection point 240. In a preferred embodiment, the likely landing point 224 at the bottom of the anticipated lower lateral section 116 and the production well 128 can be the planned intersection point 240. Those skilled in the art will recognize that the planned intersection point 240 can be located anywhere along the lower lateral section 116 and the production well 128; however, for the purposes of the following construction method, the embodiment where the planned intersection point 240 is the landing point 224 is described.

[0188] Simultaneously, a second drilling rig can be positioned within borehole 174 and will laterally drill from drilling position 286 near landing point 224 to intersect with the first drilling rig, which is also laterally drilling along the same lower side 124. Similar to the first drilling rig drilling laterally from connecting borehole 140, this side can be drilled using an oil-based mud system to minimize flushing and protect borehole integrity. Furthermore, the drilling mud system used may depend on the region and the region's historical drilling problems. Those skilled in the art will recognize the various possible drilling mud systems that can be used.

[0189] Including magnetic sensors (such as Lodestone) TMA drilling assembly (part of the package) can be lowered into common section 118 to drill downward toward the intended landing point 224 to meet the lower side 124 from the connecting borehole 140. More specifically, a second rig with the drilling assembly will drill downward toward landing point 224 while the first rig also drills laterally toward landing point 224. Magnetic tools and magnetic sensors will help facilitate the intersection of the boreholes drilled at landing point 224. Once the lower lateral section 124 and the production well 128 have intersected, both directional drilling assemblies can be laterally removed. Figure 10 It depicts the whole after the two sides intersect.

[0190] Although step 710 describes the steps to make production well 128 intersect with the lower lateral section 124, those skilled in the art will recognize that it is still possible to drill production well 128 without drilling along the same downward axis as common well section 118, and that drilling assemblies with magnetic tools and magnetic sensors will be able to help find different intersection points 240, depending on the expected path and trajectory of the well that may be affected by the specifications of the rock formation 320.

[0191] In step 715 (shown in Figure 7), the steel production casing 156 is installed in the lower lateral section 124 between the drilling positions 282 and 286 of the connecting borehole 140 and the common section 118. (Refer to...) Figure 11 A steel production casing 156 (also referred to herein as production liner 156) will cover the open-hole sections at drill positions 282 and 286 leading to the common section 118 and connecting borehole 140, and extend into the inner diameter of intermediate casings 236 and 238. The steel production casing 156, installed along the lower side 124, may have a diameter between 4 ½” and 7”. In a preferred embodiment, the steel production casing 156 may have a diameter of 5 ½”. Each end of the steel production casing 156 will have a connection and / or sealing assembly. The connection / sealing assembly may be used for pressure-tested connections with the multi-branch connector 120 and the geothermal isolation joint 170. In a preferred embodiment, the connection / sealing assembly may be a polished orifice receiver. The polished orifice receiver will be finished with a Baker-centered / reverse sealing orifice extension and an anchored sealing assembly latch profile (not shown).

[0192] Custom-made steel centralizers (not shown) can also be attached to the outside of casing 156 before cementing. The centralizers are typically designed to lift casing 156 from the underside toward the bottom of section 124, allowing cement to completely surround casing 156. Custom-made, elongated centralizers can also directly improve conductivity between formation heat and the steel body of casing 156 (as they are made of steel) via the bonding agent 152. As previously mentioned, hematite addition can also be added to cement 152 to optimize electrical conductivity.

[0193] In step 720 (shown in Figure 7), the steel production casing 156 is cemented into place. An isolation packer 252 and a cementing stage tool 256 are installed near the drill position 282. The calculated amount of hot cement can be pumped and displaced. A second isolation packer 254 can be installed near the drill position 286. The common section 118 is well separated from the steel production casing 156. Excess hot cement is circulated along the borehole 174 to the surface 316 and discarded.

[0194] Isolation packers 252 and 254 are rubber elements that can expand to create an impermeable seal between the outer diameter of the steel production casing 156 and the inner diameter of the intermediate hot casing 236. This prevents cement from entering the remaining intermediate casing and causing blockages in the connection well 140 or common section 118. In a preferred embodiment, two isolation packers 252 and 254 at each drilling location 282 and 286 can be used to increase the integrity of the sealing packer (not shown).

[0195] Stage cementing tool 256 will be opened (which also creates an inner diameter plug at the end of steel production casing 156) to prevent cement from entering the connecting well 140. The steel production casing 156 can then be cemented in place. Cementing the steel production casing 156 involves first circulating cleaning of the lower section 124 and production well 128 between drilling positions 282 and 286 to remove all drill cuttings. A first dart can then be placed in the lower section 124 and production well 128 to expand isolation packers 252 and 254 and open stage cementing tool 256 to allow cement to circulate around the outer diameter of the steel production casing 156. The lower lateral section 124 and production well are then subjected to a 5m... 3 The first pre-flushing with thickening water, similar to the previous flushing, involves weighting the thickening water to maintain an overbalanced wellbore. Then, the lower lateral section 124 and production well 128 undergo a 5 m... 3 The second pre-rinse with the cleaning agent, which was increased in weight to 1450 kg / m³ 3To maintain overbalance within the lower lateral section 124. Cement is then filled / provided into the intermediate hot casing 236, consisting of the total calculated borehole volume plus a 20% margin (approximately 75 t) of insulating cement. Tail cement is then supplied as a 20% excess (approximately 98 t) of airtight cement. The cement is then replaced with fresh water. Those skilled in the art will recognize that, similar to the drilling process described above for the connecting well 140, the volume, mixture, and spacing of cement and pre-flushing can be adjusted based on historical data of the geographic location and formation, formation pressure, and regional control isolation requirements of certain formations to prevent crossflow contamination. A second guide tube is also arranged in the lower lateral section 124 and the production well 128 and will land in the stage cementing tool 256 (which acts as a check valve), which will close the cementing port, thereby effectively preventing cement from flowing back up into the connecting well 140 or the common section 118.

[0196] The steel production sleeve 156 will be tensioned via an automatic slip tensioning device in the sleeve cup, which allows the steel production sleeve 156 to be bolted to a Class 5 blowout preventer.

[0197] In step 725 (shown in Figure 7), the two-part skewing devices 260 and 262 are installed, and the sleeve windows 264 and 266 are milled. See reference... Figure 12 A two-part directional builder 260 (also referred to herein as directional builder 260) is installed within the lower lateral section 124, close to the isolation packer 252, between the landing point 228 and the isolation packer 252. directional builder 260 includes an upper section (scoop) that forces a pineapple grinder (not shown) to cut a diamond-shaped window 264 (also referred herein as milled window 264 and bridging hole 264) into the intermediate sleeve.

[0198] The second two-part directional drilling rig 262 is installed approximately 700m below the surface 316 along the borehole 174, at the junction 122 between the common section 118 and the production well 128. The directional drilling rig 262 may also include an upper section (scoop) that forces a milling machine (not shown) to cut window 266 along a vertical section of the borehole 174. In a preferred embodiment, directional drilling rigs 260 and 262 are installed simultaneously, and casing windows 264 and 266 are also milled simultaneously. However, those skilled in the art will appreciate that directional drilling rig 260 may be installed first, or directional drilling rig 262 may be installed first. Similarly, casing window 264 may be milled first, or casing window 266 may be milled first. Those skilled in the art will recognize that there are different potential sequences in which directional drilling rigs 260 and 262 may be installed and casing windows 264 and 266 may be milled.

[0199] Anglers 260 and 262 also include a lower section (not shown) comprising a guide and anchor (not shown) that can be permanently disposed within the intermediate casing. In addition to a smaller diameter bore through the center of the guide, the guide allows drilling and completion assemblies to extend through a window. This allows the completion assembly to be steered through the lower section of the wellbore. Those skilled in the art will recognize the use of anglers and their application in creating wellbore connections.

[0200] The directional drilling tool 262 and milling window 266 will also allow drilling of the angled section 126 and vertical section 138 of the injection well 112. In addition, the directional drilling tool 260 and milling window 264 will allow the upper lateral section 116 to be connected to a future-installed multi-branch connector 120.

[0201] In step 730 (shown in Figure 7), the upper lateral section 116 and injection well 112 are drilled, connecting milling windows 264 and 266. See also Figure 13 The first drilling rig can begin drilling the upper lateral section 116 from milling window 264, heading towards the wellbore 174. In a preferred embodiment, the upper lateral section 116 is drilled using an oil-based mud system to minimize flushing and protect wellbore integrity. However, the drilling mud system used may depend on the region and its historical drilling problems. Those skilled in the art will recognize that different possible drilling mud systems can be used.

[0202] Similar to the borehole of the lower side 124, the directional drilling assembly can be removed from the well. A magnetic tool is then lowered to connect the borehole 140 to the casing window 264. The magnetic tool can be an active ranging system that can be used with a MWD system. More specifically, a magnetic sensor can be arranged in the upper side 116, and a magnetic sub-assembly can be arranged in the injection well 112, which will be discussed further below. The magnetic sensor and magnetic sub-assembly enable accurate ranging at the intersection of the upper side 116 and the injection well 112.

[0203] Simultaneously, a second drilling rig can drill injection well 112 from milling window 266. Specifically, the angled section 126 can be drilled by the second drilling rig at milling window 266. After drilling the angled section 126 to a predetermined length, the vertical section 138 can be drilled. The angled section 126 and the vertical section 138 of injection well 112 can be drilled using an oil-based drilling mud system to minimize flushing and protect wellbore integrity. However, the drilling mud system used may depend on the region and the region's historical drilling problems. Those skilled in the art will recognize that different possible drilling mud systems can be used.

[0204] The drilling assembly can be used to drill angled sections 126 and vertical sections 138. In a preferred embodiment, the drilling assembly may include a magnetic sensor. The magnetic sensor may be a Lodestone sensor. TM As part of the enclosure, the drilling assembly can be lowered through common well section 118 to enter drilling injection well 112. The drilling assembly, equipped with magnetic sensors and magnetic tools, facilitates the intersection of the two wells in the upper lateral section 116. Specifically, the drilling assembly facilitates the intersection of the vertical section 138 of injection well 112 and the upper lateral section 116. In a preferred embodiment, injection well 112 and upper lateral section 116 intersect at intersection point 290. However, those skilled in the art will recognize that intersection point 290 can be any point along upper lateral section 116 or any point along injection well 112. Once injection well 112 and upper lateral section 116 intersect, both drilling assemblies can be removed from the first and second drilling rigs.

[0205] In step 735 (shown in Figure 7), the steel production casing 156 is installed in the upper lateral section 116 and the injection well 112. As... Figure 14 As can be seen, the steel production casing 156 extends the length of the upper lateral section 116 and the injection well 112, but does not enter casing windows 264 and 266. Specifically, the steel production casing 156 may be installed within 50 feet of casing windows 264 and 266. The steel production casing 156 also covers the opening / entry from the lower lateral section 124 and from the wellbore 174 to the upper lateral section 116. Each end of the steel production casing 156 specifically has a connection / sealing assembly installed at casing windows 264 and 266. In a preferred embodiment, this connection / sealing assembly is a polished orifice receiver. The polished orifice receiver is finished with a Baker-centered / reverse sealing orifice extension and an anchored sealing assembly latch profile (not shown). The polished orifice socket facing the lower lateral section 124 is also prepared to connect to the multi-branch connector 120. This will be discussed further below.

[0206] In step 740 (shown in Figure 7), isolation packers 294 and 298 are installed and inflated. The staged cementing tool 300 is also installed and opened. Figure 15 As shown, once the packers 294 and 298 expand and the stage cementing tool 300 opens, a calculated amount of hot cement can be pumped. The drill pipe will then separate from the steel production casing 156. Excess hot cement can be circulated to the surface through the common section 118.

[0207] In step 745 (shown in Figure 7), on both wells, the upper sections of build-up directional drilling rigs 260 and 262 are removed, leaving the lower sections of build-up directional drilling rigs 260 and 262 within the intermediate hot casing 236. This can... Figure 16As seen in the diagram, the lower sections of directional drilling rigs 260 and 262 include guides and anchors, allowing casing or drilling assemblies to be diverted from the window guides of directional drilling rigs 260 and 262 into the lower lateral section 124. Furthermore, these window guides have predetermined holes passing through the center of directional drilling rigs 260 and 262, allowing access to the steel production casing 156 below the directional drilling hole. Specifically, the directional drilling hole allows tools or shunts with an outer diameter smaller than the predetermined hole diameter to be lowered below directional drilling rigs 260 and 262 for connection to the steel production casing 156. The outer diameter of completion assemblies or any tools operating within the steel production casing 156 after drilling has been completed can be adjusted to ensure the appropriate assembly enters the correct wellbore.

[0208] In step 750 (shown in Figure 7), the multi-branch connector 120 is installed and connected between the upper lateral section 116 and the lower lateral section 124. Then, a pressure test is performed on the entire casing downhole circulation loop 08. (Refer to...) Figure 17 Two dummy trips are performed on borehole 174 and connecting borehole 140. The first trip is performed using a polishedbore locator seal assembly (without a latch), whose outer diameter is larger than the directional guides of directional guides 260 and 262, to contact the receiver in lower lateral section 124 to verify the precise depth of the gap. The second trip is performed using a polishedbore locator seal assembly (without a latch), whose outer diameter is smaller than the directional guides of directional guides 260 and 262, to contact the receiver in upper lateral section 116 to verify the precise depth of the gap. This process allows for precise measurement of the depth and distance between well 140, lower lateral section 124, and upper lateral section 116. The multi-branch connector 120 can then be configured with appropriate spacing to connect lower lateral section 124 and upper lateral section 116. Additionally, the geothermal isolation joint 170 can be configured with appropriate spacing to connect two sides simultaneously, as will be explained further below.

[0209] The multi-branch connector 120 can be lowered into the connection well 140 (using drill pipe for landing operations) to connect the upper lateral section 116 and the lower lateral section 124. The multi-branch connector 120 will consist of two distinct "legs," each designed to secure and facilitate access to a specific well (upper lateral section 116 or lower lateral section 124), and forming a pressure-tested connection with the steel production casing 156 in each of the upper lateral section 116 and lower lateral section 124. One leg 292 will include a polished orifice positioning seal assembly with a mid-shear-type protective shield and an outer diameter smaller than that of the directional guide of the directional guide 260. This will allow the polished orifice positioning seal assembly to be lowered via the window guide and connected to the polished orifice receiver of the steel production casing on the lower lateral section 124. The second leg 296 of the multi-branch connector 120 has the same design, except that its outer diameter will be larger than that of the yaw guide of the yaw guide 260, thereby forcing the polished orifice positioning seal assembly with a central shear-type protective cover away from the sleeve window 264 and connecting it to the steel production sleeve 156 via a polished orifice receiver on the upper lateral section 116. The second leg 296 may also include a pin / shear activated sled to protect the seal from frictional damage through the window 280 and the opening section.

[0210] The multi-branch connector 120 provides fully mechanical and hydraulic isolation support for the re-entry-capable connection area. The multi-branch connector 120 is designed to accommodate re-entry connections in steam-assisted gravity drainage applications. It is typically installed with a full-length gasket during one connection, and a second connection with an existing lateral pressure-tested seal. The multi-branch connector 120 is used to provide the engagement between the upper lateral section 116 and the lower lateral section 124, utilizing the connection borehole 140 as an inlet and / or entry point.

[0211] In step 755 (as shown in Figure 7), the geothermal insulation joint 170 can be installed. For example... Figure 4As shown, the geothermal isolation joint 170 can be lowered through the borehole 174 and connected to the angled section 126 of the injection well 112 and the 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 orifice positioning seal assembly with a central shear-type guard, the outer diameter of which is smaller than that of the directional drilling guide of the directional drilling device 262. The smaller outer diameter of the directional drilling guide of the directional drilling device 262 allows the polished orifice positioning seal assembly to be lowered through the window guide of the directional drilling device 262 and connected to the polished orifice receiving seat of the production well 128. The second leg 310 (also referred to as the insulated production pipe 166) has the same design and also includes a polished orifice positioning seal assembly with a central shear-type guard. However, the polished orifice positioning seal assembly includes an outer diameter larger than that of the directional guide of the directional guide 262 to force the polished orifice positioning seal assembly with a central shear-type guard away from the casing window 266 and connect to the steel production casing 156 of the angled 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 frictional damage through the casing window 266 and the open section between the angled section 126 of the injection well 112 and the borehole 174. The geothermal isolation joint 170 also acts as a joint between both the injection well 112 and the production well 128, thereby allowing isolation of the input and output flow paths.

[0212] In step 760 (shown in Figure 7), the staged cementing tool 300 can be milled out using a drilling rig. In an alternative embodiment, a joint drill pipe or continuous tubing unit can be used to mill the staged cementing tool 300. Any debris from the staged cementing tool 300 can also be removed.

[0213] In step 765 (shown in Figure 7), a pressure test can be performed. Once the milling of the staged cementing tool 300 has been completed, a flow path is provided for the entire loop of the full casing downhole circulation loop 108. If circulation can be established, a pressure test can be performed on the entire full casing downhole circulation loop 108 (as is known to those skilled in the art).

[0214] Once the test has been successfully completed, the geothermal power generation system 100 is ready to proceed according to... Figure 5 and ​ Follow the methods and steps described in the text.

[0215] The geothermal power generation system 100 utilizes known techniques and methods in well construction in the oil and gas field, but applies these techniques and methods in a novel and inventive manner to generate and produce energy from geothermal sources.

[0216] Although the foregoing description and figures represent specific preferred embodiments of the invention as currently contemplated by the inventors, 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 a geothermal source, the system comprising: A common well section extends underground into the rock strata, the common well section having an upper end and a lower end; An insulated injection pipe extends underground into the rock formation, a portion of which is located together with the common well section, and the insulated injection pipe is fluidly isolated from the common well section; An injection well extends deeper underground from the lower end of the common well section, the injection well having an upper end and a lower end, the upper end of the injection well being fluidly connected to the insulated injection pipe; A production well extends deeper underground from the lower end of the common well section, the production well having an upper end and a lower end, the upper end of the production well being fluidly connected to the common well section; A first lateral section is connected to a location along the injection well and extends away from that location; The second lateral section connects to a location along the production well and extends away from that location; A multi-branch connector that combines the first lateral segment and the second lateral segment; Each of the common well section, the injection well, the production well, the first lateral section, and the second lateral section is fitted with a steel casing and fixed in place with cement within the rock strata; 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 section cooperate with each other to define a pressure-tested downhole circulation loop within the rock formation and to be arranged in a heat transfer manner with the rock formation. The pressure-tested downhole circulation loop is configured to receive working fluid, which is capable of undergoing a phase change between liquid and gaseous states within the pressure-tested downhole circulation loop due to heat transferred from the rock formation. A pump, fluidly connected to the insulated injection pipe, is configured to circulate the working fluid through the pressure-tested downhole circulation loop; A turbine system, fluidly connected to the common well section, is operable to convert mechanical energy generated by the flow of the working fluid into electrical energy; as well as A cooler, fluidly connected between the pump and the turbine system, is used to cool the working fluid.

2. The system of claim 1 further includes a surface casing surrounding an opening in the common well section, the surface casing being partially located above the surface and configured to prevent the working fluid from escaping into the rock formation.

3. The system according to claim 1 or claim 2, further comprising, wherein, The system has a diameter of 30,100 m. 2 The surface area above ground.

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 non-homogeneous working fluid.

6. The system according to any one of claims 1 to 5, wherein, The common well section 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 between 1,000 m and 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 between 1,000 m and 3,500 m.

9. The system according to any one of claims 1 to 8, wherein, The first lateral segment has a length between 2000 m and 4000 m.

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

11. The system according to any one of claims 1 to 10, wherein, The first lateral segment is deeper than the second lateral segment.

12. The system according to any one of claims 1 to 10, wherein, The second lateral segment is deeper than the first lateral segment.

13. The system according to any one of claims 1 to 10, wherein, The first lateral segment and the second lateral segment are at the same depth, and there is a gap between the first lateral segment and the second lateral segment.

14. The system according to any one of claims 1 to 13, wherein, During operation, the pressure-tested downhole circulation loop is configured to receive fluid at pressures between 7 MPa and 31 MPa.

15. The system according to any one of claims 1 to 13, wherein, The pressure-tested downhole circulation 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 with a variable speed drive controller.

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

18. The system according to any one of claims 1 to 17, wherein, The turbine system includes an expansion turbine.

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

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

21. The system according to any one of claims 1 to 20, further comprising a storage tank connected between the cooler and the pump and configured to retain 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: refrigerants, hydrocarbon-based fluids, ammonia, carbon dioxide, and water.

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

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 co-current heat exchanger having a first flow channel connected between the turbine system and the cooler, and a second flow channel connected between the pump and the insulated injection pipe, the co-current heat exchanger being configured to transfer heat from the first flow channel to the second flow channel.

26. The system according to any one of claims 1 to 25, wherein, The heat-insulating injection pipe is a steel pipe coated with a heat-insulating compound.

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

28. The system according to any one of claims 1 to 27, wherein, The upper end of the injection well includes a downward angled 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 well is separated from the production well.

30. The system according to claim 29, wherein, The majority of the injection well is separated from the production well by a lateral distance of at least 80 m.

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

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

33. The system according to any one of claims 1 to 28, wherein, A portion of the insulated injection pipe is positioned eccentrically with the common well section.

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

35. The system according to claim 34, In the case where the common well section is the first common well section, 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 downhole circulation loop is the first pressure-tested downhole circulation loop, and the pump is the first pump; The system also includes: The second common well section extends underground into the rock strata, and the second common well section has an upper end and a lower end; A second insulated injection pipe extends underground into the rock formation. A portion of the second insulated injection pipe is positioned together with the second common well section. The second insulated injection pipe is fluidly isolated from the second common well section. The second injection well extends deeper underground from the lower end of the second common well section. The second injection well has an upper end and a lower end, and the upper end of the second injection well is fluidly connected to the second insulated injection pipe. A second production well extends deeper underground from the lower end of the second common well section. The second production well has an upper end and a lower end, and the upper end of the second production well is fluidly connected to the common well section. The third lateral section connects to a location along the second injection well and extends away from that location; The fourth lateral section connects to a location along the second production well and extends away from that location; The second multi-branch connector combines the third lateral section and the fourth lateral section; Each of the second common well section, the second injection well, the second production well, the third lateral section, and the fourth lateral section is fitted with a steel casing and fixed in place with cement within the rock formation; 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 section cooperate with each other to define a second pressure-tested downhole circulation loop within the rock formation and to be arranged in a heat transfer manner with the rock formation. The second pressure-tested downhole circulation loop is configured to receive working fluid that is capable of undergoing a phase change between liquid and gaseous states within the second pressure-tested downhole circulation loop due to heat transferred from the rock formation. A second pump, fluidly connected to a second insulated injection pipe, is configured to circulate the working fluid through the pressure-tested downhole circulation loop; The second common well section is fluidly connected to the turbine system, which is configured to receive working fluid from the first production well of the first pressure-tested downhole circulation loop and the second production well of the second pressure-tested downhole circulation loop; and The cooler is fluidly connected to both the first pump, which is connected to the first insulated injection pipe, and the second pump, which is connected to the second insulated injection pipe.

36. The system according to claim 35, wherein, The second multi-branch connector of the second pressure-tested downhole circulation loop is positioned at a location spaced apart from the first multi-branch connector within the lateral section of the wellhead.

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

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

39. The system according to any one of claims 35 to 38, wherein, The system has 30, 100 m 2 The surface area above ground.

40. A system for generating energy from a geothermal source, the system comprising: A common well section extends underground into the rock strata, the common well section having an upper end and a lower end; An insulated production pipe extends underground into the rock stratum, a portion of which is located together with the common well section, and the insulated production pipe is fluidly isolated from the common well section; An injection well extends deeper underground from the lower end of the common well section, the injection well having an upper end and a lower end, the upper end of the injection well being fluidly connected to the insulated injection pipe; A production well extends deeper underground from the lower end of the common well section, the production well having an upper end and a lower end, the upper end of the production well being fluidly connected to the insulated production pipe; A first lateral section is connected to a location along the injection well and extends away from that location; The second lateral section connects to a location along the production well and extends away from that location; A multi-branch connector that combines the first lateral segment and the second lateral segment; Each of the common well section, the injection well, the production well, the first lateral section, and the second lateral section is fitted with a steel casing and fixed in place with cement within the rock strata; The common well section, the injection well, the first lateral section, the multi-branch connector, the second lateral section, the production well, and the insulated production pipe cooperate with each other to define a pressure-tested downhole circulation loop within the rock formation and to be arranged in a heat-transferring manner with the rock formation. The pressure-tested downhole circulation loop is configured to receive working fluid that can undergo a phase change between liquid and gaseous states within the pressure-tested downhole circulation loop due to heat transferred from the rock formation. A pump, fluidly connected to the common well section, is configured to circulate the working fluid through the pressure-tested downhole circulation loop; A turbine system, fluidly connected to the insulated production pipe, is operable to convert the mechanical energy generated by the flow of the working fluid into electrical energy; as well as A cooler, fluidly connected between the pump and the turbine system, is used to cool the working fluid.

41. A method for generating energy from a geothermal source, the method comprising: Provides a pressure-tested downhole circulation loop extending underground into rock formations, the pressure-tested downhole circulation loop comprising: The system 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 section, wherein a portion of the insulated injection pipe is positioned together with the common well section. Each of the injection well, the production well, the first lateral section, the second lateral section, and the common well section is fitted with a steel casing and fixed in place with cement within the rock strata; The working fluid is delivered through the pressure-tested downhole circulation loop, and the working fluid is received in liquid state by the insulated injection pipe; While the working fluid is being delivered through the pressure-tested downhole circulation loop... Heat is transferred from the surrounding rock layers to the liquid working fluid, and pressure is applied to the liquid working fluid; This causes a phase change in the working fluid from a liquid state to a gaseous state, and the working fluid leaves the common well section in a gaseous state; The mechanical energy generated by the flow of the gaseous working fluid is converted into electrical energy; Cooling the working fluid and causing a phase change of the working fluid to a liquid state; and The working fluid is returned to the insulated injection pipe.

42. The method according to claim 41, wherein, Delivering the working fluid through the pressure-tested downhole circulation loop includes pumping the working fluid.

43. The method of claim 41 or claim 42, wherein applying pressure to the liquid working fluid comprises applying a pressure between 7 MPa and 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 by the flow of the gaseous working fluid into electrical energy generates an output power between 0.5 MW and 2 MW.

45. The method according to any one of claims 41 to 44, wherein, The step of cooling the working fluid and causing a phase change in the working fluid is performed 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 non-homogeneous 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-based fluids, ammonia, carbon dioxide, and water.

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

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 temperature of the propane reaches 140°C and the pressure reaches 6250 kPag, a phase transition occurs in the propane from a liquid state to a gaseous state.

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

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

57. The method of claim 56, wherein the propane leaving the common well section 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, When the working fluid is delivered through the pressure-tested downhole circulation loop, the temperature of the propane increases by 76°C and the pressure of the propane increases by 2170 kPag.

59. The method according to any one of claims 51 to 58, wherein, After converting the mechanical energy generated by the flow of the gaseous working fluid into electrical energy, 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 step of cooling the working fluid involves cooling the propane to a temperature of 30°C and a pressure of 1080 kPag.

61. The method according to any one of claims 51 to 60, further comprising: Heat is transferred from the working fluid in the first region to the working fluid in the second region using a co-current heat exchanger. The working fluid in the first region occurs between the step of converting the mechanical energy generated by the flow of the gaseous working fluid and the step of cooling the working fluid. The working fluid in the second region occurs between the step of delivering the working fluid through the pressure-tested downhole circulation loop and the step of receiving the working fluid in a liquid state by the insulated injection pipe.

62. A method for constructing a pressure-tested downhole circulation loop for generating energy from a geothermal source, the pressure-tested downhole circulation loop being configured to transfer heat from surrounding rock formations to a working fluid flowing within the pressure-tested downhole circulation loop, and causing a phase change of the working fluid from a liquid state to a gaseous state, the method comprising: Provides access wells that extend underground into the rock strata; A common well section is drilled into the underground rock strata, the common well section having an upper end and a lower end; Install the first steel casing for the common well section; The first steel casing used for the common well section is fixed in place in the rock formation with cement; Drill a production well deeper underground from the lower end of the common well section to the first intended intersection point; Drill the first lateral section along the entry well to the first expected intersection point; Connect the first lateral section to the production well at the first expected intersection point; Install a second steel casing for the production well and the first lateral section; The second steel casing used for the production well and the first lateral section is cemented in place within the rock formation; Drill an injection well deeper underground from the lower end of the common well section to the second intended intersection point, the injection well having an upper end and a lower end; The second lateral section will be drilled along the entry well to the second expected intersection point, wherein the first lateral section and the second lateral section are adjacent to each other along the entry well from the starting drilling position of the entry well. Connect the second lateral section and the injection well at the second expected intersection point; Install a third steel casing for the second lateral section and the injection well; The third steel casing used for the second lateral section and the injection well is cemented in place within the rock formation; A multi-branch connector is provided through the access well, and the multi-branch connector is installed at the connection point between the first lateral section and the second lateral section; Provides a thermally insulated injection pipe with fluid connection to the upper end of the injection well, wherein a portion of the thermally insulated injection pipe is co-located with the common well section; and The pressure test is performed on the downhole circulation loop, which 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 section.

63. A system for generating energy from a geothermal source, the system comprising: The first common well section and the second common well section extend underground into the rock strata, and the first common well section and the second common well section each have an upper end and a lower end; The first and second insulated injection pipes extend underground into the rock strata. A portion of the first insulated injection pipe is located together with the first common well section, and a portion of the second insulated injection pipe is located together with the second common well section. The first and second insulated injection pipes each have an upper end and a lower end. A first injection well and a second injection well, wherein the first injection well extends from the lower end of the first common well section to a deeper underground location, and the second injection well extends from the lower end of the second common well section to a deeper underground location, and each of the first injection wells and the second injection wells has an upper end and a lower end, wherein 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. A first production well and a second production well, the first production well extending deeper underground from the lower end of the first common well section, the second production well extending deeper underground from the lower end of the second common well section, the first production well and the second production well each having an upper end and a lower end, the upper end of the first production well being fluidly connected to the first common well section, and the upper end of the second production well being fluidly connected to the second common well section; A first lateral section is connected to a location along the first injection well and extends away from that location; The second lateral section connects to a location along the first production well and extends away from that location; The third lateral section connects to a location along the second injection well and extends away from that location; The fourth lateral section connects to a location along the second production well and extends away from that location; A first multi-branch connector, combining the first lateral segment and the second lateral segment; The second multi-branch connector combines the third lateral section and the fourth lateral section; Each of the first common well section and the second common well section, the first injection well and the second injection well, the first production well and the second production well, the first lateral section, the second lateral section, the third lateral section and the fourth lateral section is fitted with a steel casing and fixed in place with cement within the rock strata; 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 section cooperate with each other to define a first pressure-tested downhole circulation loop within the rock formation. 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 section cooperate with each other to define a second pressure-tested downhole circulation loop within the rock formation. Both the first pressure-tested downhole circulation loop and the second pressure-tested downhole circulation loop are arranged in a heat-transferring manner with respect to the rock formation. Each of the first pressure-tested downhole circulation loop and the second pressure-tested downhole circulation loop is configured to receive working fluid that is capable of undergoing a phase change between a liquid and a gaseous state due to heat transferred from the rock formation. A first pump, fluidly connected to the first insulated injection pipe, is configured to circulate the working fluid through the first pressure-tested downhole circulation loop; A second pump, fluidly connected to the second insulated injection pipe, is configured to circulate the working fluid through the second pressure-tested downhole circulation loop; A turbine system fluidly connected to the first common well section and the second common well section, the turbine system being operable to convert mechanical energy generated by the flow of the working fluid into electrical energy; A cooler, fluidly connected between the first and second pumps and the turbine system, is operable to cool the working fluid received from the turbine system and to supply the cooled working fluid to the first and second pumps; and the first pressure-tested downhole circulation loop and the second pressure-tested downhole circulation loop are adjacent to each other.

64. A system for generating energy from a geothermal source, the system comprising: A common well section extends underground into the rock strata, the common well section having an upper end and a lower end; An insulated injection pipe extends underground into the rock formation, a portion of which is located together with the common well section, and the insulated injection pipe is fluidly isolated from the common well section; An injection well extends deeper underground from the lower end of the common well section, the injection well having an upper end and a lower end, the upper end of the injection well being fluidly connected to the insulated injection pipe; A production well extends deeper underground from the lower end of the common well section, the production well having an upper end and a lower end, the upper end of the production well being fluidly connected to the common well section; A first lateral section is connected to a location along the injection well and extends away from that location; The second lateral section connects to a location along the production well and extends away from that location; as well as A multi-branch connector that combines the first lateral segment and the second lateral segment; Each of the common well section, the injection well, the production well, the first lateral section, and the second lateral section is fitted with a steel casing and fixed in place with cement within the rock strata; 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 section cooperate with each other to define a pressure-tested downhole circulation loop within the rock formation and to be arranged in a heat-transferring manner with the rock formation. The pressure-tested downhole circulation loop is configured to withstand a pressure of at least 7 MPa and to receive working fluid that is capable of undergoing a phase change between liquid and gaseous states within the pressure-tested downhole circulation loop due to heat transferred from the rock formation. A pump, fluidly connected to the insulated injection pipe, is configured to circulate the working fluid through the pressure-tested downhole circulation loop; A turbine system, fluidly connected to the common well section, is operable to convert mechanical energy generated by the flow of the working fluid into electrical energy; as well as A cooler, fluidly connected between the pump and the turbine system, is used to cool the working fluid.

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