System for generating energy from geothermal sources and method of operation and construction thereof

Abstract

The present disclosure describes a system and method for generating energy from a geothermal source. The system includes an injection well and a production well extending subsurface into a rock formation, a first lateral section connected to the injection well, and a second lateral section connected to the production well, the first and second lateral sections connected to a polygonal connector to define a downhole well loop pressure-tested within the rock formation in a heat transfer configuration therewith. The downhole well loop is cased with steel and cemented in place within the rock formation. The downhole well loop receives a working fluid capable of undergoing a phase change between liquid and gas within the downhole well loop as a result of heat transferred from the rock formation. The system also includes a pump for circulating the working fluid, a turbine system for converting the flow of the working fluid into electricity, and a chiller.

Description

[Technical Field]

[0001] FIELD OF THE DISCLOSURE This disclosure relates generally to generating energy from geothermal sources, and more particularly to systems for generating energy from geothermal sources and methods of operation and construction thereof. [Background technology]

[0002] Systems for energy production from geothermal sources (also referred to herein as geothermal energy generation systems) are designed so that a working fluid or water is circulated underground and heated, and the thermal energy is then returned to the surface and converted into electricity. The working fluid or water is then cooled and returned underground to the heat source.

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

[0004] One way to solve this is to provide a filter along the flow path of the working fluid or before the working fluid enters the machinery. The filter can help prevent the working fluid from carrying debris or solids into any machinery. However, the need to replace the filter increases maintenance costs. Furthermore, the filter is an additional component and therefore introduces another potential point of failure into the system.

[0005] Another way to solve the problem of debris in the working fluid is to use a binary cycle power plant, where two working fluids are used: a first working fluid is heated underground and then passed through an isolated secondary working fluid in a second loop, which is then heated and used to power a turbine. This prevents the turbine from encountering debris, but the pumps required to circulate the first working fluid underground still have to deal with the debris. Furthermore, binary cycle power plants are inefficient because they have high parasitic loads, and a significant amount of heat may be lost when transferring heat from the first working fluid to the second working fluid.

[0006] Furthermore, working fluid looping underground may begin to erode rock surfaces along the working fluid flow path. The erosion of rock surfaces may lead to unstable paths underground and may result in environmental damage. Therefore, to prevent erosion, the flow rate of the working fluid must be minimized to protect the integrity of the rock formation. This leads to additional underground residence time for the working fluid.

[0007] As the working fluid flows underground, it may leak into the surrounding environment through pores in underground rock layers, causing underground pollution. Therefore, to be environmentally friendly, the working fluid needs to be an environmentally friendly fluid, such as water. Nevertheless, if the first working fluid picks up environmentally unfriendly substances along its path, such as picking up oil while flowing through a pump, it may still leak into the external environment.

[0008] In other known geothermal energy systems, chemical, chemically treated, or polymer coating layers are applied to the circulating fluid to prevent erosion, environmental leakage, and the inclusion of rock debris in the working fluid along the underground loop, and the polymer coating is applied to seal the rock formation from the circulating fluid. However, some inherent drawbacks associated with polymer coating layers include the inability to pressure test underground polymer-coated loops. Without pressure testing the underground loop, there is no assurance as to whether the polymer coating layer will hold up at depths where the working fluid is exposed to high pressures and whether the polymer coating layer will react with different working fluids, and therefore, leakage including subsurface contamination is possible.

[0009] Furthermore, the polymer coating itself may be subject to erosion and, as it erodes, may allow for erosion of the rock layer, leading to contamination of the first working fluid. To prevent this, the polymer coating may need to be applied in several layers and may need to be continually replaced, leading to high maintenance costs, additional downtime, and lost production time. Even after applying the polymer coating, it is difficult to ensure that the entire rock layer and the first working fluid path / loop are coated, and it is even more difficult to ensure the thickness or integrity of the polymer coating.

[0010] In other prior art, such as U.S. Patent Application Publication No. 2018 / 0291880 and International Patent Application Publication No. 2022029699, a casing is provided, but the casing is not cemented, which can lead to instability. Furthermore, the casing is not pressure tested, which can lead to instability due to working fluid at depths with high pressures or high or fluctuating underground flow rates. As provided in both of the aforementioned patent application publications, where two working fluids are used, instability can result in reduced operational performance and potential subsurface contamination if there is a working fluid other than a water leak. Subsurface contamination can occur due to leakage of the working fluid into pores in the rock formation. The pores in the rock formation can be previously existing, unknown fractures or fractures induced by excavation during construction of the geothermal energy generation system. If there is a working fluid leak, the fluid can be transported through the fractures into sensitive resources such as groundwater.

[0011] In other prior art, such as U.S. Patent Application Publication No. 2011 / 0048005, a continuous series of pipes is cemented within and along the entire length of two connected wellboreholes, specifically from the injection wellhead of one underground borehole to a substantially horizontal underground pipeline backing up the ascending wellbore to the production wellhead. This allows the working fluid to be transported underground, undergo a phase change due to heat from the surrounding subsurface rock, and then transported back to the surface for use in the power plant. There is only a single underground horizontal pipeline connecting the injection wellhead and the production wellhead. In this type of system, the single underground horizontal pipeline and the distance between the injection wellhead and the production wellhead tend to be very long to provide sufficient heat transfer between the rock formation and the production fluid. This large distance between the injection wellhead and the production wellhead tends to create a large footprint both above and below ground. This increases the overall cost of the system and potentially increases parasitic loads because there is an additional length of piping required above ground between the injection and production wellheads, an additional amount of working fluid for that additional length of piping above ground, and heat may be lost due to the additional time the production fluid spends above ground. Additionally, the construction techniques provided in U.S. Patent Application Publication No. 2011 / 0048005 do not allow for a pressurized connection between the two sections.

[0012] It would therefore be advantageous to have a solution whereby a geothermal energy generation system could have an underground loop that includes a barrier that could be pressure tested, and where there is minimal risk of erosion, debris inclusion, and leakage into the surrounding rock formations and the environment. It would also be beneficial to have a solution that requires minimal maintenance, saves costs, minimizes downtime, and has fewer points of failure in the system. Summary of the Invention

[0013] According to various aspects of the present invention, a system for generating energy from a geothermal source is provided. The system includes an injection well extending underground into a rock formation, the injection well having an upper end and a lower end. The system also includes a production well extending underground into the rock formation proximate to the injection well, the production well having an upper end and a lower end. The system further includes a first lateral section connected to a location along the injection well and extending away from the location, and a second lateral section connected to a location along the production well and extending away from the location, the first and second lateral sections being connected to a polygonal connector, each of the first and second lateral sections having a length greater than the distance between the upper ends of the injection well and the production well. Each of the injection well, the production well, and the first and second lateral sections is cased with steel and cemented in place within the rock formation. The injection well, the first lateral section, the polygon connector, the second lateral section, and the production well cooperate with one another to define a pressure-tested downhole wellbore loop in a heat transfer arrangement therewith within the rock formation, the pressure-tested downhole wellbore loop being configured to receive a working fluid capable of undergoing a phase change between a liquid and a gas within the pressure-tested downhole wellbore loop as a result of heat transferred from the rock formation. The system also includes a pump fluidly connected to the injection well, the pump configured to circulate the working fluid through the pressure-tested downhole wellbore loop. Further, the system includes a turbine system fluidly connected to the production well, the turbine system operable to convert mechanical energy generated from the flow of the working fluid into electricity. The system further includes a chiller fluidly connected between the pump and the turbine system for cooling the working fluid.

[0014] The system may further include an injection well surface casing surrounding an entrance to the injection well, the injection well surface casing being partially above the surface and configured to prevent leakage of the working fluid into the rock formation.

[0015] The system may further include a production well surface casing surrounding an outlet of the production well, the production well surface casing being partially above the surface and configured to prevent leakage of the working fluid into the rock formation.

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

[0017] The system is 22,500m 2 may have a ground surface area of

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

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

[0020] The injection well may have a depth of 1000m to 4000m.

[0021] The first lateral section may have a length of at least 2000m and at most 4000m.

[0022] The second lateral section may have a length of between 2000m and 4000m.

[0023] Production wells can have depths of 1000m to 4000m.

[0024] The first side section may be longer than the second side section, and the first side section is at a lower depth than the second side section.

[0025] The first lateral section may be at the same depth as the second lateral section, the first lateral section extending away from the lower end of the injection well at a first angle and the second lateral section extending away from the lower end of the production well at a second angle.

[0026] During operation, the pressure tested downhole well loop may be configured to receive pressurized fluid between 7 MPa and 31 MPa.

[0027] The pressure tested downhole well loop can withstand a pressure of at least 7 MPa.

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

[0029] The positive displacement pump may also be selected from the group consisting of a plunger type pump, a gear type pump, and a rotary vane type pump.

[0030] The turbine system may include a turbine expander.

[0031] The turbine system may produce an output power of 0.5 to 2 MW.

[0032] The cooler may use ambient air as the coolant.

[0033] The system may further include a storage tank connected between the chiller and the pump and configured to hold excess working fluid.

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

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

[0036] Alternatively, the working fluid is propane.

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

[0038] Additionally, the system may include an access well having a lateral segment, with the polygonal connector positioned within the lateral segment of the access well.

[0039] The system may also include a second injection well extending underground into the bedrock formation proximate to the second injection well, a second production well extending underground into the bedrock formation, the second injection well having an upper end and a lower end, the polygonal connector being a first polygonal connector, the pressure tested downhole well loop being a first pressure tested downhole well loop, the pump being a first pump, and a second injection well extending underground into the bedrock formation proximate to the second injection well, the second production well having an upper end and a lower end. The system may further include a third lateral section connected to and extending away from a location along the second injection well and a fourth lateral section connected to and extending away from a location along the second production well, the third and fourth lateral sections connected to the second polygonal connector, each of the third and fourth lateral sections having a length greater than the distance between the upper ends of the second injection well and the second production well. Further, each of the second injection well, the second production well, and the third and fourth lateral sections are cased with steel and cemented in place within the rock formation. The second injection well, the third lateral section, the second polygonal connector, the fourth lateral section, and the second production well cooperate with one another to define a second pressure-tested downhole well loop in heat transfer configuration therewith within the rock formation, the second pressure-tested downhole well loop configured to receive a working fluid capable of undergoing a phase change between a liquid and a gas within the second pressure-tested downhole well loop as a result of heat transferred from the rock formation. The system may also include a second pump fluidly connected to the second injection well, the second pump configured to circulate the working fluid through the second pressure-tested downhole well loop. Furthermore, the system may include a second production well fluidly connected to a turbine system, the turbine system configured to receive the working fluid from the first production well of the first pressure-tested downhole well loop and the second production well of the second pressure-tested downhole well loop.The cooler may be fluidly connected to both a first pump connected to the first injection well and a second pump connected to the second injection well, and a second polygonal connector of the second pressure tested downhole well loop is positioned within the lateral segment of the access well at a location spaced from the first polygonal connector.

[0040] Further, the first injection well includes a first inlet, the first production well includes a first outlet, the second injection well includes a second inlet, and the second production well includes a second outlet, the second inlet and the second outlet being located on the surface adjacent to each other, and the second inlet being at a distance of 7 m to 50 m from the second outlet.

[0041] Furthermore, the first inlet and the second inlet may be located on a surface adjacent to each other, the first inlet being at a distance of at least 20 m from the second inlet.

[0042] Furthermore, the first outlet and the second outlet may be located on a surface adjacent to each other, the first outlet being at a distance of at least 20 m from the second outlet.

[0043] The system is 45,000m 2 The surface area may further include a ground surface area of ​​0.05 to 0.15 mm.

[0044] According to various aspects of the present invention, a method for generating energy from a geothermal source is provided. The method includes providing a pressure-tested downhole wellbore loop extending underground into a rock formation, the pressure-tested downhole wellbore loop including an injection well, a production well adjacent to the injection well, a first lateral section connected to the injection well, a second lateral section connected to the production well, and a polygonal connector connecting the first lateral section and the second lateral section, wherein the injection well, the production well, and the first and second lateral sections are each cased with steel and cemented in place within the rock formation, the first and second lateral sections having a length greater than the distance above the surface between the injection well and the production well. The method also includes conveying a working fluid through the pressure-tested downhole wellbore loop, the working fluid being received by the injection well in a liquid state. While conveying the working fluid through the pressure-tested downhole wellbore loop, heat is transferred from the surrounding rock formation to the liquid working fluid, exerting pressure on the liquid working fluid. The method further includes inducing a phase change of the working fluid from a liquid state to a gaseous state, wherein the working fluid exits the production well in a gaseous state. The method further includes converting mechanical energy generated from the flow of gaseous working fluid into electricity. The method also includes cooling the working fluid, inducing a phase change of the working fluid to a liquid state, and returning the working fluid to the injection well.

[0045] Conveying the working fluid through the pressure tested downhole well loop may include pumping the working fluid.

[0046] The step of exerting a pressure on the liquid working fluid may include exerting a pressure of between 7 MPa and 31 MPa on the liquid working fluid.

[0047] Converting the mechanical energy generated from the flow of gaseous working fluid into electricity may produce an output power of between 0.5 and 2 MW.

[0048] The step of cooling the working fluid and inducing a phase change in the working fluid may be performed using a chiller.

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

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

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

[0052] The working fluid may be selected from the group consisting of a refrigerant, a carbon-based fluid, ammonia, carbon dioxide, and water.

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

[0054] Alternatively, the working fluid is propane.

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

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

[0057] If the working fluid is propane, a step may occur when the propane reaches a temperature of 140° C. and a pressure of 6250 kPa (140° C.) which induces a phase change of the propane from a liquid state to a gaseous state.

[0058] Additionally, an induced phase change of the propane from a liquid state to a gaseous state can occur in one of the second lateral sections and the production well.

[0059] Propane leaving the production well in gaseous form may have a temperature of 90°C to 110°C and a pressure of 3000 kPag to 4000 kPag.

[0060] Alternatively, propane leaving a production well in gaseous form may have a temperature of 106°C and a pressure of 3500 kPa.

[0061] While conveying the working fluid through a pressure tested downhole well loop, the temperature of the propane may increase by 76°C and the pressure of the propane may increase by 2170 kPag.

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

[0063] By cooling the working fluid, the propane can be cooled to a temperature of 30°C and a pressure of 1080 kPag.

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

[0065] According to various aspects of the present invention, a method for constructing a pressure-tested downhole well loop for a system for producing energy from a geothermal source is provided, the pressure-tested downhole well loop being configured to transfer heat from a surrounding rock formation to a working fluid flowing within the pressure-tested downhole well loop to induce a phase change in the working fluid from a liquid state to a gas state. The method includes providing an access well extending subsurface into the rock formation and drilling an injection well into the subsurface rock formation, the injection well being spaced apart from the access well. The method further includes drilling a first lateral section extending away from the injection well and connecting to the access well, and installing first steel casing for the injection well and the first lateral section. The method further includes cementing the first steel casing for the injection well and the first lateral section in place within the rock formation, and drilling a production well into the subsurface rock formation, the production well being adjacent to the injection well. The method also includes drilling a second lateral section extending away from the production well toward a connection point between the first lateral section and the second lateral section, the connection point being located along the access well adjacent to the first lateral section, and installing second steel casing for the production well and the second lateral section. The method further includes providing a polygonal connector through the access well, installing the polygonal connector at the connection point between the first and second lateral sections, and pressure testing the downhole wellbore loop, the downhole wellbore loop including an injection well, the first lateral section, the polygonal connector, the second lateral section, and the production well, the first and second lateral sections having a length greater than the distance above surface between the injection well and the production well. The method also includes cementing the second steel casing for the production well and the second lateral section to the rock formation.

[0066] The method may also include drilling a hole for an injection well surface casing before drilling the injection well, and setting the injection well surface casing in place.

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

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

[0069] Drilling a second lateral section extending away from the production well toward the connection point may include placing a whipstock within the first lateral section proximate the connection point.

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

[0071] Pressurizing the downhole wellbore loop may include subjecting the downhole wellbore loop to a pressure at a maximum depth within the downhole wellbore loop.

[0072] The method may include installing a second isolation packer and a second cementing stage tool prior to cementing the second casing for the production well and the second lateral section in place in the rock formation, the second isolation packer and the second cementing stage tool being installed proximate an intersection between the second lateral section and the polygonal connector, the second isolation packer being installed around an outer diameter of the second casing, and the second cementing stage tool being installed within the second casing and blocking an inner diameter of the second casing.

[0073] According to various aspects of the present invention, a system for generating energy from a geothermal source is provided. The system includes a first injection well and a second injection well extending underground into a bedrock formation, each of the first and second injection wells having an upper end and a lower end. The system includes a first production well and a second production well extending underground into the bedrock formation, each of the first and second production wells being proximate to both the first and second injection wells, each of the first and second production wells having an upper end and a lower end. The system also includes a first lateral section connected to a location along the first injection well and extending away from the location, a second lateral section connected to a location along the first production well and extending away from the location, a third lateral section connected to a location along the second injection well and extending away from the location, and a fourth lateral section connected to a location along the second production well and extending away from the location. The first and second lateral sections are connected to a first polygonal connector, each of the first and second lateral sections having a length greater than the distance between the upper ends of the first injection well and the first production well, and the third and fourth lateral sections are connected to a second polygonal connector, each of the third and fourth lateral sections having a length greater than the distance between the upper ends of the second injection well and the second production well. Further, each of the first and second injection wells, the first and second production wells, and the first, second, third, and fourth lateral sections are cased with steel and cemented in place within the rock formation. The system also includes the first injection well, the first lateral section, the first polygonal connector, the second lateral section, and the first production well cooperating with one another to define a first pressure-tested downhole well loop within the rock formation, and the second injection well, the third lateral section, the second polygonal connector, the fourth lateral section, and the second production well cooperating with one another to define a second pressure-tested downhole well loop within the rock formation, which are in heat transfer configuration with the rock formation, and each of the first and second pressure-tested downhole well loops configured to receive a working fluid capable of undergoing a phase change between a liquid and a gas as a result of heat transferred from the rock formation.The system further includes a first pump fluidly connected to the first injection well, the first pump configured to circulate the working fluid through the first pressure-tested downhole well loop, and a second pump fluidly connected to the second injection well, the second pump configured to circulate the working fluid through the second pressure-tested downhole well loop. The system also includes a turbine system fluidly connected to the first and second production wells, the turbine system operable to convert mechanical energy generated from the flow of the working fluid into electricity. The system further includes a chiller fluidly connected between the first and second pumps and the turbine system, the chiller operable to cool the working fluid received from the turbine system and supply the cooled working fluid to both the first and second pumps, the first and second pressure-tested downhole well loops being located proximate to one another.

[0074] According to various aspects of the present invention, a system for generating energy from a geothermal source is provided. The system includes an injection well extending underground into a rock formation, the injection well having an upper end and a lower end. The system also includes a production well extending underground into the rock formation proximate to the injection well, the production well having an upper end and a lower end. The system further includes a first lateral section connected to a location along the injection well and extending away from the location, and a second lateral section connected to a location along the production well and extending away from the location. The first and second lateral sections are connected to a polygonal connector. Each of the injection well, the production well, and the first and second lateral sections are cased with steel and cemented in place within the rock formation. The system also includes: the injection well, the first lateral section, the polygon connector, the second lateral section, and the production well cooperate with one another to define a pressure-tested downhole wellbore loop within the rock formation in heat transfer configuration therewith; the pressure-tested downhole wellbore loop configured to withstand a pressure of at least 7 MPa and to receive a working fluid capable of undergoing a phase change between a liquid and a gas within the pressure-tested downhole wellbore loop as a result of heat transferred from the rock formation. The system also includes a pump fluidly connected to the injection well, the pump configured to circulate the working fluid through the pressure-tested downhole wellbore loop. Further, the system includes a turbine system fluidly connected to the production well, the turbine system operable to convert mechanical energy generated from the flow of the working fluid into electricity; and a chiller fluidly connected between the pump and the turbine system for cooling the working fluid. [Brief explanation of the drawings]

[0075] Embodiments of the present invention will be more clearly understood in connection with the following detailed description of embodiments of the invention taken in conjunction with the accompanying drawings.

[0076] [Figure 1] 1 is a schematic cross-sectional view illustrating a system for generating energy from a geothermal source according to one embodiment.

[0077] [Figure 2] FIG. 2 is a conceptual schematic diagram of a system for producing energy from a geothermal source shown in FIG. 1.

[0078] [Figure 3] 3 is another conceptual schematic diagram of a system for generating energy from a geothermal source according to an alternative embodiment to that shown in FIG. 2.

[0079] [Figure 4] 3 is a flow chart illustrating steps in a method for generating energy from a geothermal source according to the embodiment shown in FIG. 2.

[0080] [Figure 5] 4 is a flow chart illustrating steps of an alternative method for generating energy from a geothermal source according to the embodiment shown in FIG. 3.

[0081] [Figure 6A] FIG. 1 is a schematic cross-sectional view illustrating an alternative embodiment of a system for generating energy from a geothermal source in which two fully cased downhole well loops are connected to a single access well, according to one embodiment.

[0082] [Figure 6B] FIG. 6B is a conceptual schematic diagram of an embodiment of a system for producing energy from a geothermal source of FIG. 6A in which two fully cased downhole well loops are fluidly connected to a single turbine system and a single cooler, and the working fluid is propane.

[0083] [Figure 7] 2 is a schematic cross-sectional view illustrating the first step in constructing the system for producing energy from the geothermal source shown in FIG. 1, showing the drilling of the injection well, construction well, and first lateral connection section.

[0084] [Figure 8]2 is a schematic cross-sectional view illustrating a second step in constructing the system for producing energy from a geothermal source shown in FIG. 1 , showing casing being installed along the injection well and through a portion of the first lateral connection section.

[0085] [Figure 9] 1 is a schematic cross-sectional view illustrating a third step in constructing the system for producing energy from a geothermal source shown in FIG. 1 , showing the isolation packer and cementing stage tooling installed and cement being injected between the casing and the wall of the injection well and a portion of the first lateral connection section.

[0086] [Figure 10] FIG. 2 is a schematic cross-sectional view showing a fourth step in constructing the system for producing energy from a geothermal source shown in FIG. 1 , showing the two-piece whipstock installed adjacent to the isolation packer and drilling of the wellbore for the production well.

[0087] [Figure 11] 1 is a schematic cross-sectional view illustrating a fifth step in constructing a system for generating energy from a geothermal source shown in FIG. 1 , showing the drilling of a production well, a second lateral connection section, and the opening of a casing window in a two-piece whipstock.

[0088] [Figure 12] 1 is a schematic cross-sectional view showing a sixth step in constructing a system for producing energy from a geothermal source shown in FIG. 1 , illustrating removing the core of the two-piece whipstock, leaving a window guide installed between the two lateral connection sections, and installing casing along the production well, the second lateral connection section, and the casing window openings in the two lateral connection sections.

[0089] [Figure 13]A schematic cross-sectional view showing the seventh step of constructing a system for generating energy from a geothermal source shown in Figure 1, showing the installation of a polygonal connector along the window guide between the two lateral connection sections, and the connection of an injection well and a production well via the two lateral connection sections and the polygonal connector.

[0090] [Figure 14] 1 is a schematic cross-sectional view showing the eighth step of constructing the system for generating energy from a geothermal source shown in FIG. 1 , illustrating the installation of an isolation packer and cementing stage tool along the casing window opening of the two-piece whipstock, and the injection of cement between the casing and the production well, the second lateral connection section, and the wall of the casing window opening of the two-piece whipstock.

[0091] [Figure 15] 2 is a flowchart illustrating steps in a method for constructing a system for generating energy from a geothermal source as shown in FIG. 1 according to one embodiment of the present invention. DETAILED DESCRIPTION OF THE INVENTION

[0092] The following description and the embodiments described therein are provided as examples of the principles and aspects of the present invention, or as illustrations of specific embodiments. These examples are provided for purposes of illustration, not limitation, of those principles of the present invention. In the following description, like reference numerals are used throughout the specification and drawings to refer to like parts.

[0093] As a general overview, a system for generating energy from a geothermal source 100 (also referred to herein as a geothermal energy generation system 100) having a single heat exchange loop is provided, the system 100 including a fully cased, pressure tested, and cemented downhole wellbore loop 108 (also referred to herein as a fully cased downhole wellbore loop 108) for isolating and circulating the 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., a subsurface heat source). The system 100 uses a Rankine cycle (preferably an organic Rankine cycle) to convert energy stored in the heated working fluid 200 into mechanical energy, which is then used to generate electrical power.

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

[0095] The geothermal energy generation system 100 includes below the ground a fully cased downhole well loop 108 in the nature of a vertical injection well 112 extending into the ground, a first lower lateral section 116 connected to and extending away from the vertical injection well 112, a vertical production well 128 extending into the ground, and a second upper lateral section 124 connected to and extending away from the vertical production well 128. The first and second lateral sections 116, 124 meet at a junction where a polygonal connector 120 is installed. At the surface, the geothermal energy generation system 100 includes a pump 104 fluidly connected to the injection well 112 and configured to move a liquid working fluid 204 down the injection well 112, away from the surface 316, through the first lower lateral section 116, the polygon connector 120, and the second upper lateral section 124, and then back toward the surface 316 to the production well 128. The liquid working fluid 204 undergoes a phase change while underground and returns to the surface 316 through the production well 128 as a gaseous working fluid 208, which flows into the turbine system 132 for power generation. Within the turbine system 132, the gaseous working fluid 208 rotates a turbine, which rotates a shaft to generate mechanical energy. The mechanical energy is converted to electricity by a shaft-driven generator (not shown). A cooler 136 fluidly connected to the turbine system 132 is also provided. The cooler 136 condenses the low-pressure gaseous working fluid 208 after it exits the turbine system 132, returning it to its original liquid state where it can be pumped to the injection well 112 and circulated through the fully cased downhole well loop 108.

[0096] As will be understood by those skilled in the art and apparent from the following description, the disclosed geothermal energy generation system 100 tends to address the above-identified challenges. More specifically, the use of a fully cased downhole well loop 108 eliminates the risk of cross-contamination between the working fluid 200 flowing through the fully cased downhole well loop 108 and the rock formation 320 or formation fluids, and the risk of the working fluid 200 eroding 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 fully cased downhole well loop 108 because there is no risk of the rock formation 320 eroding 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 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 controlled and monitored to ensure minimal erosion of the wellbore or subsurface section. Minimal or no erosion is important not only from an environmental perspective, but also to avoid creating instabilities in the rock formation 320 that could lead to earthquakes or other potential consequences. Furthermore, because the working fluid 200 is isolated from the rock formation 320, there is no risk of dissolving minerals or other substances that could change the composition of the working fluid 200. In other prior art systems where the working fluid 200 may come into contact with the surrounding rock formation 320, there is a risk of dissolving minerals or other substances that the working fluid 200 may come into contact with, especially while the working fluid 200 is eroded at the surface of the rock formation 320 and undergoes thermal changes. Dissolution of minerals can also lead to the deposition of said minerals on pipes or other components of the geothermal energy generation system 100 as the working fluid 200 cools, creating blockages and requiring additional maintenance on the system 100.

[0097] The fully cased downhole well loop 108 is pressure tested and cemented into the surrounding rock formation 320 underground. Due to its construction, the working fluid 200 finding its way out of the fully cased downhole well loop 108 is significantly minimized. Therefore, the risk of the working fluid 200 leaking or finding its way out of the fully cased downhole well loop 108, potentially causing contamination or other environmental concerns, is significantly minimized, especially when the working fluid 200 is subjected to significant changes in temperature and pressure. In contrast, other prior art systems may suffer fluid loss due to fluid contamination from leakage and / or formation fluid inflow into the formation due to a lack of complete isolation of the working fluid from the rock formation 320. This results from the lack of casing, including the inability to successfully obtain a valid pressure test. As a result, the fully cased downhole well loop 108 can use unconventional working fluids 200 with different heat capacities and different phase transition points, thus enabling a potentially more energy-efficient system, greater power generation, and geothermal power generation systems in a smaller footprint while reducing environmental contamination concerns. Additionally, parasitic power losses are minimized. As one skilled in the art will appreciate, parasitic losses can be described as absorbed power, which is the energy required to operate pumps, chiller fans, and other loads, reducing the net energy output of the system. As will also be appreciated by one skilled in the art, net energy is the power produced minus the power used to operate the system.

[0098] The casing material of the fully cased downhole well loop 108 may be steel. Unlike other prior art in which chemical liners may be used, steel, along with a cement support, is a hardened, inert material and can withstand high pressures. Furthermore, there is a lower risk of steel chemically interacting with the working fluid 200, allowing for a greater selection of working fluids 200 for the geothermal energy generation system 100. Furthermore, the construction and application of steel casing is substantially safer compared to chemical liners when it comes to ensuring there are no leaks in the fully cased downhole well loop 108.

[0099] By using a single heat exchange loop with a single working fluid 200, as opposed to two loops with two working fluids, parasitic losses of energy are significantly reduced because heat is retained within the single working fluid 200 and is not lost to the environment in heat transfer when multiple working fluids are present.

[0100] Furthermore, because the working fluid 200 is completely contained within the geothermal energy generation system 100, the working fluid 200 can be easily changed if environmental conditions change. For example, if the underground temperature changes, the working fluid 200 can be easily replaced with another working fluid 200 having a lower boiling point. This allows the geothermal energy generation system 100 to continue operating without requiring structural modifications, such as adjusting the depth of side sections, to obtain the required heat.

[0101] By providing a polygonal connector underground to connect the two lateral sections, the injection well 112 and the production well 128 can be located relatively close to each other. Thus, the geothermal energy generation system 100 tends to occupy a smaller footprint, both underground and aboveground, compared to other prior art systems. A smaller footprint can reduce capital and operating costs. For example, U.S. Patent Application Publication No. 2011 / 0048005 has a single horizontal pipeline underground. This results in the injection and production wellheads being significantly farther apart, thus occupying a larger footprint than the embodiments described below. A larger footprint can result in inefficient heat transfer and increased construction costs.

[0102] 1 and 2 , one embodiment of a geothermal energy generation system 100 is shown. The major components of the geothermal energy generation system 100 include a fully cased downhole well loop 108, more specifically, an injection well 112, a first lower lateral section 116, a polygon connector 120 (also referred to herein as a cross-connect splitter 120 or polygon junction 120), a second upper lateral section 124, and a production well 128. The geothermal energy generation system 100 further includes a pump 104 and a turbine system 132 fluidly connected to the fully cased downhole well loop 108. More specifically, the pump 104 is connected to the injection well 112, and the turbine system 132 is connected to the production well 128. A cooler 136 is fluidly connected between the turbine system 132 and the pump 104 to close the circuit for a single heat exchange loop.

[0103] 1 , an additional wellbore 140 is disposed adjacent to the fully cased downhole well loop 108. This wellbore 140 (also referred to herein as a connecting wellbore 140, an access wellbore 140, or a sacrificial wellbore 140) is drilled to assist in the construction of the fully cased downhole well loop 108, but is not part of the geothermal energy production system 100 and does not contribute to the normal operation of the geothermal energy production system 100. The wellbore 140 is described further below with respect to the construction of the geothermal energy production system 100.

[0104] 1, the direction of flow of the liquid working fluid 204 is indicated by the solid arrows, and the direction of flow of the gaseous working fluid 208 is indicated by the dashed arrows. Details regarding the operation and phase changes of the working fluid 200 are described further below.

[0105] The fully cased downhole well loop 108 resides below ground in surrounding rock formations 320, but has access points to the fully cased downhole well loop 108 located at the surface 316, more specifically, an inlet 112A located at the upper end 180 of the injection well 112 and an outlet 128A located at the upper end 192 of the production end 128. The inlet 112A is part of the injection well 112 and is configured to provide an entry point at the surface 316 for the liquid working fluid 204. The inlet 112A is surrounded by a surface casing 144. Similarly, the production well 128 includes an outlet 128A configured to provide an exit point at the surface 316 for the gaseous working fluid 208. The outlet 128A is surrounded by a surface casing 148, which is similar to the surface casing 144. In this embodiment, the remainder of the fully cased downhole well loop 108 is underground, with the exception of the aforementioned inlet 112A, outlet 128A, and surface casings 144 and 148. The surface casings 144 and 148 are provided to isolate the segments of the injection well 112 and production well 128 proximate the surface 316 from fresh groundwater and to prevent spillage or migration of the working fluid 200 into the groundwater and / or the environment. Details regarding the construction of the surface casings 144 and 148 are provided below. Those skilled in the art will recall that reference to bedrock formation 320 is not limited to rock, but may include any formation or combination of formations underground.

[0106] Furthermore, in this embodiment, the inlet 112A of the injection well 112 and the outlet 128A of the production well 128 are close to each other. By locating the injection well 112 and the production well 128 close to each other, the geothermal energy generation system 100 can have a smaller footprint on the surface 316 compared to prior art systems. In this embodiment, the inlet 112A and the outlet 128A are 50 meters apart, although the inlet 112A and the outlet 128A may be 7 meters to 50 meters apart. Furthermore, in a preferred embodiment, the distance between the inlet 112A and the outlet 128A is less than either the length of the upper lateral section 124 or the length of the lower lateral section 116. Furthermore, a preferred embodiment of the footprint size of the above-ground geothermal energy generation system 100 is 22,500 m 2 or 150 m by 150 m. However, the configuration of the inlet 112A, injection well 112, outlet 128A, production well 128, lower lateral section 116, and upper lateral section 124 may not be limited based on the location of the inlet 112A and outlet 128A. In other configurations, the inlet 112A may be a significant distance from the outlet 128A. Indeed, in some alternative configurations of the fully cased downhole wellbore loop 108, the lower lateral section 116 and the upper lateral section 124 may be at the same depth. Those skilled in the art will recognize different possible configurations of the fully cased downhole wellbore loop 108 and different possible placements of the inlet 112A, injection well 112, outlet 128A, and production well 128.

[0107] The entire piping, wells, and sections of the fully cased downhole well loop 108 are lined with cement 152 and cased with steel 156. More specifically, in this embodiment, steel tubing is cemented within the wellbore of the injection well 112 and the production well 128 as part of both the lower lateral section 116 and the upper lateral section 124, as part of the polygonal connector 120, and any connecting pieces between the aforementioned components. To ensure there are no leaks, the entire fully cased downhole well loop 108 is pressure tested. A pressure test may be defined as a hydraulic test in which the continuously cemented steel casing 156 is subjected to a minimum downhole pressure related to the maximum pressure the fully cased downhole well loop 108 can withstand. The maximum pressure the fully cased downhole well loop 108 can withstand may be the point along the fully cased downhole well loop 108 having the greatest depth, which is likely along the lower lateral section 116. In certain embodiments, the following equation may be used to determine the total downhole pressure for a pressure test:

[0108] (Number 1) Surface pressure + hydrostatic pressure

[0109] Here, the hydrostatic pressure is (Number 2) (Maximum depth x specific gravity of water) It can be calculated as:

[0110] For example, if the deepest point along the fully cased downhole well loop 108 is along the lower lateral section 116 at a depth of 2500 m and the pressure applied to the surface is 2 MPa, the specific gravity of water is 10 KPa / m, and in this particular example, the total downhole pressure can be calculated by adding the surface and hydrostatic pressures. (Number 3) 2MPa + (2500m × 10KPa / m) = 21MP

[0111] As in the case of a leak due to high pressure, the pressure test is performed using water, so that the leaking water does not cause pollution to the surrounding environment. If the specific gravity of water is greater than that of the working fluid 200, the above formula using the hydrostatic pressure of water may be used for the working fluid 200. For example, because the specific gravity of propane is less than that of water, the above formula provides a higher pressure test than that required for propane as the working fluid 200, ensuring safe operation of the fully cased downhole wellbore loop 108. As will be appreciated by those skilled in the art, if the working fluid 200 has a higher specific gravity than water, the above formula can be compensated for by providing the specific gravity of the working fluid 200 and then pressure testing the fully cased downhole wellbore loop 108 with water accordingly. Furthermore, in certain embodiments, the total downhole pressure calculated for the above pressure test can be increased to provide a safety factor, thus testing the fully cased downhole wellbore loop 108 at a pressure higher than the operational limit for safety reasons. The pressures that the fully cased downhole wellbore loop 108 is constructed and pressure tested to withstand are pressures not found in prior art systems for producing energy from geothermal sources. This is due to the fact that the operating pressure of the working fluid in prior art systems tends to be much lower than the operating pressure of the working fluid 200 while flowing through the fully cased downhole wellbore loop 108.

[0112] The pressure tested fully cased downhole well loop 108 is capable of receiving and delivering a working fluid 200 pressurized between 7 MPa and 31 MPa. In an embodiment in which the working fluid 200 is pentane, the pressure tested fully cased downhole well loop 108 is capable of receiving and delivering a working fluid 200 between 7 MPa and 22 MPa. In a preferred embodiment in which the working fluid 200 is propane, the pressure tested fully cased downhole well loop 108 is capable of receiving and delivering a propane working fluid 200 between 7 MPa and 20 MPa.

[0113] During its operation, the fully cased downhole wellbore loop 108 can withstand pressures of at least 7 MPa. In other embodiments, pressure testing of the fully cased downhole wellbore loop 108 may include pressure testing up to 31 MPa, and can be designed to burst or fail at up to 39 MPa.

[0114] Cement 152 is used to structurally secure the steel 156 casing to the surrounding rock formation 320, although in alternative embodiments, the cement 152 may be mixed with other substances, such as the addition of hematite to adjust the thermal conductivity of the cement 152. While cement 152 and steel 156 are used in this embodiment, it will occur to those skilled in the art that any other material may be used as a barrier, so long as it physically isolates the working fluid 200 from the external environment / rock formation 320, can withstand the pressure requirements from both the working fluid 200 expanding and contracting as it undergoes a phase change, and allows heat to be conducted through the material.

[0115] The injection well 112 extends vertically downward from an inlet 112A at the surface 316 a predetermined distance (or depth) underground. The predetermined distance (or depth) can be determined for each site depending 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 consider in determining the depth and residence time at that depth to induce a phase change in the working fluid 200. The injection well depth is selected to achieve high rock temperatures while minimizing drilling costs, which increase with many factors, including the depth and geological composition of the rock formation 320. In this embodiment, at its lower end 196, the injection well 112 is cemented to a lower lateral section 116 by a curved connecting piece 160. However, the lower lateral section 116 may be connected to the injection well 112 and extend away from the injection well 112 at any location along the injection well 112. The injection well 112 has a depth of approximately 1000 m to 4000 m and a production steel casing 156 with an internal diameter of approximately 139 mm based on a preferred working fluid temperature of 140° C. to be achieved. However, the injection well can be a different size (i.e., drilled to a different depth, whether greater or shallower, and having a different diameter, whether larger or smaller) as needed to suit a particular application. In the embodiment shown in FIG. 1 , the injection well 112 is shown extending vertically downward into the ground. Of course, this need not be the case in all embodiments. In some embodiments, the injection well can extend downward into the ground at an angle from vertical.

[0116] In a preferred embodiment, the lower lateral section 116 is seen to be perpendicular to the injection well 112 and extending laterally away therefrom toward the XC connector 120. Additionally, the lower lateral section 116 has a length of approximately 2000 m to 4000 m and a production steel casing 156 having an inside diameter of approximately 139 mm. In other embodiments, the lower lateral section 116 need not be positioned laterally relative to the injection well 112, but can extend laterally away from the injection well 112 at an angle, and can also be a different size.

[0117] Cementing the lower lateral section 116 to the upper lateral section 124 is a polygonal connector 120. The polygonal connector 120 may include an XC splitter or other equivalent connection device that can be connected between the lower lateral section 116 and the upper lateral section 124 in a manner that allows the fully cased downhole well loop 108 to be pressure tested and to operate under pressure. For example, the SAGD XC splitter polygonal system manufactured by Baker Hughes Company. Polygonal connectors 120 are well known in the oil and gas industry, and one skilled in the art will recognize the various types of polygonal connectors 120 available. However, the use of polygonal connectors 120 within a geothermal energy generation system is novel.

[0118] In this embodiment, the upper lateral section 124 extends laterally away from the polygonal connector 120 to cement the lower end 198 of the production well 128 via the curved connecting piece 164. However, the upper lateral section 124 can cement the production well 128 at any location along the production well 128. The upper horizontal section 124 is positioned perpendicular to the production well 128. Furthermore, the upper lateral section 124 has a length of approximately 2000 m to 4000 m and a production steel casing 156 with an inner diameter of approximately 139 mm. In other embodiments, the upper lateral section 124 does not need to be positioned laterally relative to the production well 128, but can extend laterally at an angle toward the production well 128. It can also be of a different size.

[0119] In embodiments in which the lower lateral section 116 is disposed laterally relative to the injection well 112 and the upper lateral section 124 is disposed laterally relative to the production well 128, both lateral sections 116 and 124 may lie in the same vertical plane. However, as will be appreciated by those skilled in the art, in alternative configurations, the lateral sections 116 and 124 may be offset from one another in the vertical plane.

[0120] In this embodiment, the production well 128 does not extend as deep into the ground as the injection well 112. Preferably, the production well has a depth of between 1000 m and 4000 m and a production steel casing 156 having a diameter of approximately 139 mm. However, the production well can be differently sized (i.e., drilled to different depths, whether greater or shallower, and having different diameters, whether larger or smaller) as needed to suit a particular application.

[0121] In this embodiment, due to the location of the inlet 112A and outlet 128A, the length of the upper lateral section 116 is shorter than the length of the lower lateral section 116. 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 underground in contact with the exothermic rock formation 320 and the flow rate of the working fluid 200. For example, if the working fluid 200 takes longer to heat up before undergoing a phase change, whether due to the heat transfer properties of the surrounding rock formation 320, the well casing and lining of the lateral sections 116 and 124, or due to the properties of the type of working fluid 200 being used, then both lateral sections 116 and 124 may need to be longer to accommodate the time that the working fluid 200 needs to be heated to induce the phase change. Flow rate is another variable that needs to be considered; lower flow rate means lower distance traveled over time, and the length of the side sections 116 and 124 can be further adjusted accordingly.

[0122] In a preferred embodiment, the lower lateral section 116 extends deeper than the upper lateral section 124. Having the two lateral sections 116 and 124 at different depths may reduce thermal interference between the wells 112 and 128, thereby increasing heat capture from the surrounding rock formation 320. However, the fully cased downhole wellbore loop 108 is not limited to this configuration. In an alternative embodiment (not shown), the lateral section leading back to the production well 128 may be located deeper than the lateral section connected to the injection well 112. Furthermore, in an alternative embodiment (not shown), both lateral sections 116 and 124 may be at the same depth but at an angle to each other, with the polygonal connector 120 connecting the two lateral sections 116 and 124 from different angles. One skilled in the art will recognize the different possible configurations and lengths available for both the lateral sections 116 and 124, as well as the different possible configurations of the entire fully cased downhole wellbore loop 108.

[0123] 1 and 2, a pump 104 located at the surface 316 is fluidly connected to the inlet 112A of the injection well 112. The pump 104 is operable to circulate a working fluid 200 through a fully cased downhole well loop 108 that enters through the inlet 112A of the injection well 112 and proceeds underground.

[0124] The pump 104 is also configured to maintain the liquid working fluid 200 flowing through the entire single heat exchange loop by maintaining an appropriate flow rate of the working fluid 204. The flow rate (and therefore residence time) is determined by the subsurface well loop to transfer enough thermal energy to convert the working fluid from a liquid to a gas at a sufficient temperature. In this embodiment, the liquid working fluid 204 received by the pump 104 may be at a pressure range of 500 kPag to 2000 kPag and a temperature range of 10°C to 40°C. The pump 104 is configured to increase the pressure in the range of 700 kPag to 3000 kPag and maintain a flow rate of 15 kg / s to 25 kg / s. In a preferred embodiment, the pump 104 can deliver the liquid working fluid 204 to the inlet 112A of the injection well 112 at a pressure of approximately 1300 kPag and a temperature of approximately 30°C. A preferred embodiment of the pump 104 utilizes a liquid pump for thermodynamic efficiency. The liquid pump minimizes the parasitic energy losses in the system compared to using a mechanical gas compressor.

[0125] In other prior art geothermal systems where the working fluid 200 comes into contact with the rock formation 320 due to a lack of casing, or where the working fluid 200 may pick up subsurface debris, the pump would 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 deal with water chemistries that have scale-forming properties during operation. In contrast, in the present embodiment, because the fully cased downhole well loop 108 is fully lined with cement 152 and cased with steel 156, the working fluid 200 does not come into contact with any rock formation 320 and is physically isolated from the environment. Therefore, the working fluid 200 does not pick up any debris and remains a clean, homogenous fluid. This allows the pump 104 to have a long service life with minimal maintenance, thereby saving on procurement and operating costs and may allow the use of less robust or standard pump designs.

[0126] In a preferred embodiment, the pump 104 may be a positive displacement pump with a variable speed drive controller. Positive displacement pump types typically have high overall thermal efficiency and can maintain a desired outlet head when paired with a variable speed drive. Positive displacement pump types include plunger, gear, or rotary vane pumps. However, as would be apparent to one skilled in the art, the 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 or diaphragm pumps. One skilled in the art will recognize a variety of potential pumps that may be used based on the aforementioned pressure, flow, and temperature specifications, as well as purchase and maintenance costs.

[0127] Also above surface level is a turbine system 132 fluidly connected to an upper end 192 of the production well 128. The turbine system 132 may include a turbine (not shown) having an output shaft connected to an electrical generator (not shown).

[0128] In this embodiment, the turbine system 132 is located close to the outlet 128A to prevent the gaseous working fluid 208 from losing heat as it travels along the insulated piping between the outlet 128A and the turbine system 132. In other embodiments, the turbine system 132 may be located further away from the outlet 128A, but this tends to be less preferred. While the exterior piping that carries the gaseous working fluid 208 to the turbine system may be insulated, heat and pressure may still be lost, and such travel distance and time are important considerations. Those skilled in the art are familiar with the structure, configuration, and operation of the turbine system 132 and associated generators and need not be described herein.

[0129] During operation, the turbine system 132 receives the gaseous working fluid 208 from the outlet 128A of the production well 128, and the gaseous working fluid 208 drives a turbine connected to a shaft. Mechanical energy generated by the rotation of the turbine is transferred to a generator, which can convert the mechanical energy into commercially saleable electricity. The electricity may then be sent to a utility-owned power grid for further distribution. In this embodiment, the turbine system 132 is capable of generating between 0.5 MW and 2 MW of electricity. In a preferred embodiment, the turbine system 132 is capable of generating approximately 1 MW of electricity.

[0130] Alternatively, when power is not needed by the power grid, it may be sent to batteries, other local loads, or dissipated for short periods via an electrical resistive load bank. Using a load bank to dissipate power allows equipment to operate without a live connection to the power grid. This can be done for equipment testing and short-term operational upsets (not shown).

[0131] In other embodiments, the turbine system 132 may include either a turbine expander, a piston expander, or a scroll expander. In a preferred embodiment, a turbine expander is used, which may be radial or axial, with the radial turbine expander connected to one end of a shaft and a generator connected to the other end of the shaft. The expander output shaft can be connected to the generator directly or through a reduction gearbox. The reduction gearbox can match the high-speed (rpm) turbine wheel to the desired operating speed of the generator. The type of expander and generator determines whether a gearbox and type of gearbox are required. In alternative embodiments, the turbine expander may also be a positive displacement machine, such as a scroll, screw, or vane expander. The preferred output of the geothermal energy generation system 100 is targeted to exceed 1 MW generated by each expander, making a high-speed, compact turboexpander the preferred embodiment; positive displacement expanders are large and expensive for the targeted power output.

[0132] In another embodiment, multiple expanders can be used to maximize the power generated. The use of multiple expanders can be beneficial when constructability limits the size of the expanders, reduces efficiency, or when attempting to expand (flash) a particular working fluid 200 in stages, where the first stage flash occurs in the primary expander, but energy resides in the working fluid that can be flashed again to a lower pressure in parallel with the first stage flash.

[0133] If a turboexpander is included, the gaseous working fluid 208 may expand as it passes through a conically housed radial turbine, thus reducing the pressure and temperature of the gaseous working fluid 208 while driving the turbine. As with the previous embodiment of turbine system 132, rotation of the radial turbine produces mechanical energy that is transferred to a generator, where it is converted into commercially saleable electricity. The voltage from the generator may be increased using a power step-up transformer to meet third party transmission line requirements for sale of the electricity to desired markets.

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

[0135] The cooler 136 (also referred to as the condenser 136) is disposed between and fluidly connected to the turbine system 132 and the pump 104. The cooler 136 is configured to receive the low-pressure gaseous working fluid 208 output from the turbine system 132 and cool and condense the low-pressure gaseous working fluid 208 into a liquid working fluid 204 using a heat exchanger cooled by forced draft air or by a mechanical chiller (not shown). In embodiments where the working fluid 200 received by the cooler 136 from the turbine system 132 is in a mixture of both gas and liquid, the amount of energy used by the cooler 136 may be reduced because less work is required to cool the working fluid 200 to a liquid state. Alternatively, the residence time of the working fluid 200 within the cooler 136 may also be reduced. As one skilled in the art will appreciate, the specifications of the cooler 136 used may also depend on the specifications of the working fluid 200, the type of turbine system 132, and the desired final temperature and pressure of the liquid working fluid 204 after exiting the cooler 136.

[0136] When the cooler 136 is fluidly connected to the pump 104, the resulting liquid working fluid 204 output from the cooler 136 is returned to the pump 104 and pumped again through the fully cased downhole wellbore loop 108. Preferably, the cooler 136 is a finned tube type with forced draft ambient air used as the coolant. This type of condenser cooler 136 is effective and relatively inexpensive. However, other embodiments can be used, such as brazed aluminum plate-style, tube-style, or other heat exchangers with a working fluid cooled by a separate coolant.

[0137] Connecting pieces 168, 172, and 176 function as additional pieces to complete the portion of a single heat exchange loop above surface 316. Specifically, connecting piece 168 functions as a connector for fluidly connecting outlet 128A of production well 128 to the inlet of turbine system 132. Similarly, connecting piece 172 fluidly connects the outlet of turbine system 132 to the inlet of cooler 136. Furthermore, connecting piece 176 functions as a connector for fluidly connecting the outlet of cooler 136 to the inlet of pump 104.

[0138] As previously mentioned, the fully cased downhole well loop 108 is fully lined and cased to physically isolate the working fluid 200 from the rock formation 320 and the environment. In this embodiment, the connection pieces 168, 172, and 176 may be steel pipe; however, in alternative embodiments, the connection pieces 168, 172, and 176 may be constructed of other materials that are leak-proof and can withstand pressure and temperature changes above ground. In a preferred embodiment, the connection piece 168 between the outlet 128A and the turbine system 132 may also be insulated to prevent heat loss from the gaseous working fluid 208 before it reaches the turbine system 132. However, in alternative embodiments, all surface connection pieces 168, 172, and 176 may be insulated to reduce heat loss, which may lead to parasitic losses. Furthermore, the single heat exchange loop of the geothermal energy generation system 100, which may include the connection pieces 168, 172, and 176, is pressure tested to ensure they do not leak when transporting the working fluid 200 while the working fluid 200 is subjected to pressure changes. Those skilled in the art will appreciate that the connecting pieces 168, 172, 176 may be of any shape or size depending on the location and specifications of the working fluid 200, the outlet 128A, the turbine system 132, the cooler 136, the pump 104, and the inlet 112A. Those skilled in the art will also appreciate that in embodiments where components are combined into a single unit, such as the cooler 136 and the pump 104, certain connecting pieces may not be necessary and may be omitted.

[0139] As shown in FIG. 2 , the geothermal energy generation system 100 may also include a storage vessel 188 (also referred to herein as a storage tank 188) to hold excess liquid working fluid 204 and provide sufficient and consistent mass flow to the pump 104. While not shown, other components, such as valves, heat exchangers, and other equipment, may be used to optimize the geothermal energy generation system 100. In alternative embodiments, a filter or filter separator may be added to the outlet 128A upstream of the turbine system 132; however, in this embodiment, a filter is not required if all piping is sufficiently clean to remove manufacturing lubricants, mill scale, dirt, and other contaminants prior to commissioning of the turbine system 132, as well as the single working fluid 200 in the single heat exchange loop, and little or no debris or foreign matter is expected during normal operation.

[0140] FIG. 3 illustrates a geothermal energy generation system 100A, which is an alternative embodiment to the embodiment illustrated in FIGS. 1 and 2. For convenience, similar elements or structures illustrated in FIGS. 2 and 3 are identified with the same reference numerals. System 100A is similar in all materials to system 100, except that geothermal energy generation system 100A includes a recuperator 184 (also referred to herein as a heat exchanger 184). Recuperator 184 is disposed between and connected to turbine system 132 and cooler 136, and between and connected to pump 104 and injection well 112. Recuperator 184 is configured to minimize the cooling load on cooler 136 and to preheat liquid working fluid 204 before it enters injection well 112 by cross-exchanging heat from the outlet gaseous working fluid 208 of warm low-pressure turbine system 132 with the cold liquid working fluid 204 from the outlet of pump 104. As the warm low-pressure gas working fluid 208 exits the turbine system 132 and travels through the recuperator 184, it may transfer its heat to the cold liquid working fluid 204, which also travels through the recuperator 184 from the outlet of the pump 104 to the injection inlet 112. By providing heat from the low-pressure gas working fluid 208 exiting the turbine system 132 to the cold liquid working fluid 204 toward the injection well 112, thermal energy is saved and reused. The low-pressure gas working fluid 208 exiting the turbine system 132 travels toward the cooler 136 to condense and induce a phase change; therefore, by transferring thermal energy from the low-pressure gas working fluid 208 before the cooler 136, the time and energy required for the cooler 136 to condense the gas working fluid 208 into a liquid is reduced. Additionally, the liquid working fluid 204 heading to the injection well 112 is partway underground to be heated; therefore, pre-heating the liquid working fluid 204 may reduce the required underground residence time, thereby allowing for shorter lateral sections 116 and 124, or lateral sections 116 and 124 at shallower depths. Those skilled in the art will recognize the possibilities for the recuperator 184 and possible configurations of a geothermal energy generation system with the recuperator 184.

[0141] In alternative embodiments, the geothermal energy generation system 100 may be used for purposes other than generating electricity. For example, the work generated from the geothermal energy generation system 100 may be used to perform other mechanical work. Alternatively, the work generated from the geothermal energy generation system 100 may be used to generate hydrogen.

[0142] Referring to FIG. 4, a flowchart illustrating steps in a method 400 for operating a geothermal energy generation system 100 according to one embodiment of the present invention is shown. Operation of the geothermal energy generation system 100 occurs after the system has been primed and started and follows a Rankine cycle (preferably an organic Rankine cycle, in which an organic carbon-based working fluid is used). An example of priming the geothermal energy generation system 100 involves slowly circulating the working fluid 200 through the injection well 112 and allowing any residual liquid or gas (either from the construction process or previous operation of the geothermal energy generation system 100) to drain into a storage vessel for collection. Once all residual liquid or gas has been removed, the working fluid 200 can continue to circulate through the geothermal energy generation system 100 as part of its normal operation. As can be seen, the method 400 is a loop. For ease of understanding, the process can be described as beginning at step 405 and ending at step 440 before beginning the process again at step 405.

[0143] As previously mentioned, the geothermal energy generation system 100 is a single heat exchange loop with a fully cased downhole wellbore loop 108. Once the fully cased downhole wellbore loop 108 is fully cased and pressure tested, the working fluid 200 can be a variety of liquids, gases, or plasmas. In alternative embodiments, the working fluid 200 can be a carbon-based, commercially available, environmentally friendly refrigerant or a mixture of refrigerants, such as 90% propane with a 10% mole fraction of ethane. Alternatively, the working fluid 200 can be any composition (heterogeneous working fluid 200) or pure (homogeneous working fluid 200) of hydrocarbons, carbon dioxide, or ammonia. In a preferred embodiment in which the geothermal energy generation system 100 is an organic Rankine cycle, the working fluid 200 can be propane. With propane, the maximum temperature achieved by the propane working fluid 200 is approximately 140°C at a depth of 2000 m and a bedrock 320 temperature of approximately 160°C. Furthermore, the propane working fluid 200 can condense to a liquid state working fluid 208 on a hot summer day without substantial cooling using ambient air forced across the fin-tube cooler 136. While propane is the working fluid 200 of choice, other organic (carbon-based) hydrocarbons, such as hydrocarbons or hydrocarbon mixtures, may also be used. Hydrocarbon mixtures can be used to maximize the return pressure of the working fluid 200. Hydrocarbon mixtures allow the working fluid 200 to be tailored to specific depth and temperature conditions. For example, adding ethane to a majority of the propane working fluid 200 allows for earlier wellbore flashing at specific rock formation 320 temperatures. Earlier flashing allows for increased flow rate of the working fluid 200 and therefore increased power generation. Another example is mixing hydrocarbons with butane to increase the heat capacity of the working fluid. By mixing heavier hydrocarbons, the flash / vaporization point along the fully cased downhole well loop 108 can be tailored depending on the temperature of the surrounding rock formation 320.For example, the vaporization point can be adjusted along the upper lateral section 124 or the production well 128 based on the temperature of the surrounding rock formation 320 to maximize the velocity of the working fluid 200 and minimize friction of the working fluid 200 along the remainder of the pipe before exiting the fully cased downhole wellbore loop 108. One skilled in the art will recognize the potential combinations of different variations in rock formation 320 temperature and hydrocarbon mixture to adjust the location of the vaporization point along the fully cased downhole wellbore loop 108. The working fluid 200 can be water, but is preferably one of the aforementioned fluids because such substances have lower boiling points and shorter subsurface residence times than water. Furthermore, the aforementioned fluids can have advantageous heat capacities and different phase transition points, allowing for a more efficient system and shorter subsurface residence times within the fully cased downhole wellbore loop 108.

[0144] The following steps illustrate an embodiment in which the working fluid 200 is propane. In step 405, the propane liquid working fluid 204 is transported underground along the lower lateral section 116, the polygon connector 120, and the upper lateral section 124 by flowing down the injection well 112. To reach the injection well 112, the liquid working fluid 204 is pumped using the pump 104. In effect, the working fluid 200 is circulated through a single, fully cased heat exchange loop using the pump 104. To ensure proper circulation, the pump 104 increases the pressure of the liquid working fluid 204 from 1080 kPag to 1300 kPag as received by the inlet 112A of the injection well 112. In this embodiment, where working fluid 200 is propane after exiting pump 104 and before being received by inlet 112A, liquid working fluid 204 may have an approximate temperature range of about 10° C. to about 40° C., with a preferred temperature of about 20° C., and an approximate pressure range of about 1000 kPag to about 2000 kPag, with a preferred pressure of about 1300 kPag. Once liquid working fluid 204 is received by inlet 112A, the liquid working fluid flows downward along vertical injection well 112.

[0145] When the liquid working fluid 204 reaches the curved connecting piece 160, the flow direction of the liquid working fluid 204 transitions from vertical to lateral and then continues along the lower lateral section 116. The liquid working fluid 204 then reaches the polygonal connector 120, where it changes direction and enters the upper lateral section 124, continuing to flow to the curved connecting piece 164 adjacent the lower end 198 of the production well 128.

[0146] Towards the lower end 196 of the injection well 112, at a depth where the lower lateral section 116 is located, the surrounding environment and rock formation 320 naturally conduct heat from the surrounding rock formation 320. As the liquid working fluid 204 flows downward along the injection well 112, heat is transferred from the surrounding environment or rock formation 320 to the liquid working fluid 204 when the liquid working fluid 204 reaches a certain depth where the temperature of the rock formation 320 exceeds the temperature of the liquid working fluid 204 (step 405). Heat transfer can occur while the liquid working fluid 204 is still flowing downward through the injection well 112 and continues to occur while the liquid working fluid 204 flows through the connecting piece 160 and the lower lateral section 116. This heat can be conductively transferred from the surrounding environment through the cement liner 152 and the steel casing 156 to the liquid working fluid 204. The depth threshold at which the liquid working fluid 204 begins to receive heat, thus increasing the temperature of the liquid working fluid 204, is when the temperature of the surrounding environment is greater than the temperature of the liquid working fluid 204. This depth threshold depends on the geothermal gradient of the site and the working fluid reinjection temperature. Heat continues to transfer to the liquid working fluid 204 as it flows through the polygonal connector 120 and upper lateral section 124, thereby increasing the temperature of the liquid working fluid 204 as it flows through said components.

[0147] Furthermore, as the liquid working fluid 204 flows downward within the injection well 112, the pressure exerted on the liquid working fluid 204 increases (at step 415) as a result of the hydrostatic head. Once the liquid working fluid 204 reaches the connecting piece 160 and the lower lateral section 116, the pressure of the liquid working fluid 204 continues to increase as the fluid absorbs thermal energy. Although there may be a slight drop in pressure due to wellbore flow friction losses, the liquid working fluid 204 has a net pressure increase. The approximate pressure of the liquid working fluid 204 upon reaching the lower end 196 of the injection well 112 / connecting piece 160 is about 10,000 kPa at a depth of about 2,000 m as provided in this embodiment. While pressure increases during depth changes, the rate at which heat is transferred, and therefore the rate at which the temperature of the liquid working fluid 204 increases, depends on the depth, the thermal conductivity of the rock, the residence time, and the temperature of the rock formation 320. Thus, the increase in temperature continues as the liquid working fluid 204 flows downward within the injection well 112 and laterally along the lower lateral section 116. Both the heat transfer and the increasing pressure action are indicated by step 415.

[0148] At some point during the liquid working fluid 204 flowing through the lower lateral section 116, the connecting piece 160, the polygonal connector 120, the connecting piece 164, and the upper lateral section 124, the liquid working fluid 204 undergoes a phase change from liquid to gas (step 415) as the liquid working fluid 204 reaches its boiling point from the heat and increased pressure. More specifically, the rate of temperature increases until the liquid working fluid 204 begins to vaporize, at which point the temperature remains constant until all of the liquid working fluid 204 changes to a gaseous state (gas working fluid 208), and then the temperature increases again as the vapor or gaseous working fluid 208 superheats. Those skilled in the art will recognize 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, in which the working fluid 200 is propane, it is vaporized at a temperature of approximately 140° C. and a pressure of approximately 6250 kPa (100 psi). In a preferred embodiment, the phase change occurs in the upper lateral section 124 or production well 128 to minimize the amount of friction between the working fluid 200 and the remainder of the casing length, and therefore maximize the velocity of the working fluid 200, before the working fluid 200 exits the fully cased downhole well loop 108; however, it may be envisioned by one skilled in the art that the phase change to the working fluid 200 may occur anywhere underground within the fully cased downhole well loop 108. It may be envisioned by one skilled in the art that the location along the flow path of the working liquid within the fully cased downhole well loop 108 will vary depending on the configuration of the fully cased downhole well loop 108, the length and depth of the components within the fully cased downhole well loop 108, the flow rate and boiling point of the working fluid 200, as well as the temperature of the rock formation 320, and the rate of conduction from the rock to the working fluid 200 through the steel casing 156 and cement 152.

[0149] In step 425, the gaseous working fluid 208 rises through the production well 128 to the surface 316 and exits the fully cased downhole well loop 108 at outlet 128A. As the gaseous working fluid 208 rises to the surface 316, the pressure and temperature decrease slightly due to the change in depth, but the temperature of the working fluid 208 is high enough to maintain the gaseous state of the working fluid 208. The approximate temperature and pressure of the gaseous working fluid 208 at outlet 128A is about 90°C to about 110°C, with a preferred temperature of about 106°C, and about 3000 kPa to about 4000 kPa, with a preferred pressure of 3500 kPa. The gaseous working fluid 208 is then conveyed along the connector piece 168 toward the turbine system 132.

[0150] Thus, in this embodiment, because the temperature of the liquid working fluid 204 is about 30° C. and about 1080 kPag at the inlet 112A and the temperature of the gaseous working fluid 208 is about 106° C. and about 3500 kPag at the outlet 128A, a trip through the fully cased downhole wellbore loop 108 with the working fluid 200 increased its temperature by about 76° C. and the pressure of the working fluid 200 by about 2170 kPag. Furthermore, in this embodiment, the residence time of the working fluid 200 between the inlet 112A and the outlet 128A is about 30 minutes. One skilled in the art will recognize that the temperature difference and residence time are affected by several factors, including, but not limited to, the configuration, depth, and length of the components of the fully cased downhole wellbore loop 108, as well as the temperature of the rock formation 320, the thermal conductivity of the rock, the conductivity from the rock through the casing 156 and cement 152 into the working fluid 200, and the flow rate of the working fluid 200.

[0151] In this embodiment where the working fluid 200 is propane, the temperature of the propane may range from approximately the temperature of the surrounding environment / environment (ambient temperature) as it enters the fully cased downhole well loop 108 at inlet 112A to 185°C as it exits the fully cased downhole well loop 108 at outlet 128A. Ambient temperature may vary depending on the environment in which the geothermal energy production system 100 is located and may range from -43°C to 45°C.

[0152] In this embodiment, the turbine system 132 is a turboexpander. In step 430, the turbine system 132 receives the gaseous working fluid 208, which drives a turbine (also referred to herein as a turbine wheel), thereby generating mechanical energy. When the turbine wheel is connected to a shaft connected to a generator, the mechanical energy is transferred to the generator, which then converts the mechanical energy to electrical energy in step 435. In an embodiment, the gaseous working fluid 208 is expanded by the expander / valve configuration, and the pressure and temperature of the gaseous working fluid 208 are also reduced while rotating the radial turbine connector to the shaft. The approximate pressure and temperature of the propane gaseous working fluid 208 exiting the turbine system 132 are in the ranges of about 1500 kPa (1500 kPa) to about 63°C and about 700 kPa (1500 kPa) to about 16°C. In a preferred embodiment, the approximate pressure and temperature of the gaseous working fluid 208 are within the ranges of about 1500 kPa (1500 kPa) to about 63°C and about 700 kPa (1500 kPa) to about 16°C, respectively, from ambient air temperature through the cooler 136, allowing the gaseous working fluid 208 to be easily condensed into liquid working fluid 204. The electrical energy generated by the generator in step 435 is approximately 1 MW and may vary depending on the lower condensing pressure at ambient conditions. Thus, reducing the load required for the cooler 136 to condense the gaseous working fluid 208 increases the net electrical energy generated by the generator. As one skilled in the art will appreciate, reducing parasitic loads, such as the need to use energy to cool the gaseous working fluid 200, increases the amount of electrical energy generated and increases the efficiency of the geothermal energy generation system 100. In certain embodiments, one skilled in the art will recognize that depending on the efficiency of the turbine system 132 and the specifications of the working fluid 200, the working fluid 200 exiting the turbine system 132 may be in a mixture of both gas and liquid.

[0153] At step 440, the gaseous working fluid 208 exiting the turbine system 132 may travel along the connecting piece 172 and be received by the cooler 136. The cooler 136 may condense the gaseous working fluid 208 to a liquid state. At the outlet of the cooler 136, the temperature and pressure of the propane liquid working fluid 204 may be 30° C. and 1080 kPa (1080 kPa) but may vary depending on the temperature and pressure of the ambient air.

[0154] Upon exiting the cooler 136 , the liquid working fluid 204 can return to the pump 104 via the connecting piece 176 where the liquid working fluid 204 is circulated again as seen by step 405 .

[0155] Referring to Figure 5, a flow chart illustrating steps of a method 400A for operating a geothermal energy generation system 100A according to one embodiment of the present invention is shown. For convenience, like reference numerals are used to indicate like steps in Figures 4 and 5. Method 400A is similar to method 400 in all materials except for the additional steps 437 and 432 relating to the recuperator 184.

[0156] Steps 405, 415, 420, 425, 430, and 435 are performed as previously described in the context of method 400 shown in Figure 4. Step 437 occurs after step 435, in which the gaseous working fluid 208 transfers heat to the parallel tubes containing the liquid working fluid 204 (to be received by the liquid working fluid 204, as described in more detail below in step 442). By transferring heat through the recuperator 184, the temperature of the gaseous working fluid 208 is reduced, thereby allowing the cooler 136 to require less energy to condense the gaseous working fluid 208 in the subsequent step 440. The temperature of the gaseous working fluid 208 after leaving the recuperator 184 and before being received by the cooler 136 is reduced by approximately 15°C.

[0157] Step 440 is then performed as previously described in the context of method 400 shown in FIG. 4 , i.e., the gas working fluid is condensed to a liquid working fluid. Following step 440, in step 442, the liquid working fluid 204 enters the recuperator 184 and receives heat therefrom. More specifically, the recuperator 184 interacts with the working fluid 200 at two locations along the single heat exchange loop: after the turbine system 132 as the gas working fluid 208, and after the pump 104 as the liquid working fluid 204. The two tubes carrying the working fluid 200 are in close proximity while within the recuperator 184, allowing for the transfer of heat from the gas working fluid 208 to the liquid working fluid 204. Thus, in step 442, the liquid working fluid 204 receives heat from the gas working fluid 208 (transferred from the gas working fluid 208 in step 437), thereby increasing the temperature of the liquid working fluid 204 before proceeding to the inlet 112A. In this embodiment, the temperature of the liquid working fluid 204 may be increased by as much as 10° C. after exiting the recuperator 184 and before reaching the inlet 112A.

[0158] Those skilled in the art will recognize that the approximate temperature and pressure ranges provided above may vary depending on the configuration of geothermal energy generation system 100 or 100A, and may vary depending on the specifications of 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 above-described embodiments in which the preferred working fluid 200 is a carbon-based, commercially available, environmentally friendly refrigerant, geothermal energy generation system 100 will continue to operate despite the preferred working fluid 200 being outside of the approximate temperature and pressure ranges.

[0159] 6A , an embodiment of a geothermal energy production system 100-1 is shown that includes two fully cased downhole well loops 108A and 108-2, both of which are connected to a single connecting wellbore 140. As will be further explained below, this facilitates construction because only the single connecting wellbore 140 needs to be drilled. Furthermore, the use of the single connecting wellbore 140 further minimizes the footprint of the geothermal energy production system. Those skilled in the art will recognize that the geothermal energy production system 100-1 is not limited to two fully cased downhole well loops, but may include any number of fully cased downhole well loops.

[0160] Referring to Figure 6B, the components of the two fully cased downhole well loops 108-1 and 108-2 can be seen. The two fully cased downhole well loops 108-1 and 108-2 have similar components to those of the fully cased downhole well loop 108 referenced above in Figures 1, 2, and 3. Accordingly, the components within each of these two fully cased downhole well loops 108-1 and 108-2 are numbered similarly to the components of the fully cased downhole well loop 108, with the suffix -1 or -2 added to indicate the first or second fully cased downhole well loop 108-1 or 108-2. Given that the components are similar, the components will not be described further.

[0161] In embodiment 100-1, the two fully cased downhole well loops 108-1 and 108-2 operate in the same manner as the previously described embodiment of the fully cased downhole well loop 108, except that after exiting the outlets 128A-1 and 128A-2 of the production wells 128-1 and 128-2, respectively, the two streams of gaseous working fluid 208 may combine into a single stream that is received by the single turbine system 132. Accordingly, the combine connection piece 168-1 may be configured to enable said combining of the two streams of gaseous working fluid 208. Additionally, a single cooler 136 may receive the gaseous working fluid 208 exiting the turbine system 132 and condense the gaseous working fluid 208 into a liquid working fluid 204. The liquid working fluid 204 may then be split into two flows using splitter connection piece 176-1 to be received by pump 104-1 and pump 104-2, where pump 104-1 may increase the pressure of the liquid working fluid 204 injected into injection well 112-1 and pump 104-2 may increase the pressure of the liquid working fluid 204 injected into injection well 112-2.

[0162] When using embodiment 100-1, the turbine system 132 and cooler 136 can be shared across the fully cased downhole loops 108-1 and 108-2, thereby minimizing the amount of components or equipment required. This can further minimize costs. Additionally, because there is only a single turbine system 132 and cooler 136 on land, as opposed to a turbine system 132 and cooler 136 for each fully cased downhole well loop 108-1 and 108-2, the footprint and ground surface area are minimized. Additionally, as will be described below, scalability and economies of scale are inherent in the design of embodiment 100-1.

[0163] Those skilled in the art will recognize the modularity of the turbine system 132, the cooler 136, and the pump 104. Specifically, as will be appreciated by those skilled in the art, any number of fully cased downhole well loops 108 can be connected to a single turbine system 132, a single cooler 136, and a single pump 104. Alternatively, any number of fully cased downhole well loops can be connected to multiple turbine systems 132, a single cooler 136, and a single pump 104. Similarly, any number of fully cased downhole well loops can be connected to a single turbine system 132, multiple coolers 136, and a single pump 104. Alternatively, as will be appreciated by those skilled in the art, multiple pumps 104 can be used. Accordingly, those skilled in the art will recognize different combinations and variations of fully cased downhole well loops 108, turbine systems 132, coolers 136, and pumps 104.

[0164] During commercial operation, when multiple well loops are producing and selling power to a power transmission line through a sales meter, it is desirable to control the power generated. For example, if 25 MW needs to be delivered to the power grid, twenty-five (25) fully cased downhole well loops 108 can be used. An on / off power control scheme is used to export the optimal amount of power to the power grid on an hourly basis. The system can electronically monitor grid capacity and power demand and then provide feedback to the facility's process logic controller (PLC). In an embodiment with a single turbine system 132 connected to 25 fully cased downhole well loops 108, the PLC automatically turns off pumps 104 and other rotating equipment and closes electronically actuated well head valves to quickly "turn off" individual geothermal well loops. This on / off control system allows the facility to vary power output from 0 MW to 25 MW in 1 MW increments. Alternatively, in an embodiment where there are twenty-five (25) turbine systems 132 connected to twenty-five (25) fully cased downhole well loops 108, the PLC can turn off the pumps 104 and turn off the turbine systems 132 for each fully cased downhole well loop 108, allowing the facility to provide power output from 0 MW to 25 MW in 1 MW increments.

[0165] This control scheme can also be used on a predetermined schedule. The advantage of an on / off control system is that it is relatively simple to design and operate and provides good power output control. This control scheme can be used for a single closed-loop system, such as that shown in FIG. 6B, where the working fluid interacts only with the underground reservoir through conduction. Reservoir fluid does not enter the geothermal loop, and well working fluid 200 does not enter the reservoir. All well heating occurs through conductive heat transfer. This allows for rapid changes in power production by isolating the flow of working fluid 200 to the injection well 112 and shutting down power generation for that well. Also, when a well is turned off, the subsurface rock can "recharge" through conductive heating, allowing the fully cased downhole well loop 108 to generate increased power (compared to steady-state operation) when it is turned back on. Those skilled in the art will recognize the ability of the above control scheme to control any number of fully cased downhole loops 108 and turbine systems 132.

[0166] 15, a flowchart illustrating steps in a method 1500 for constructing a fully cased downhole well loop 108 of a geothermal energy generation system 100 according to one embodiment of the present invention is shown. Construction of a fully cased downhole well loop 108 involves using a drilling rig to drill and connect two wellbores (the injection well 112 and the production well 128), and a third wellbores, the connecting wellbores 140, may be drilled and extended to provide a connection point for the injection wells 112 and the production wells 128.

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

[0168] Two drilling rigs can be moved and secured at separate surface locations. Referring to FIG. 7 , these are locations 304 and 308. Locations 304 and 308 are at least a predetermined distance apart from the length of lateral sections 116 and 124 (as shown in FIG. 1 ), plus any offset distance required for the construction angle of the well trajectory. It will be apparent to one skilled in the art that the positioning of the two drilling rigs in this case is based on an embodiment of a fully cased downhole wellbore loop 108 in which the injection well 112, production well 128, lateral sections 116 and 124, and polygonal connector 120 are along the same vertical plane, and that the positioning of the two drilling rigs can be adjusted based on the location and configuration of the components of the fully cased downhole wellbore loop 108. Furthermore, while two drilling rigs are used in this embodiment, it will be apparent to one skilled in the art that the sequence of events could be modified to include the use of an additional, third drilling rig.

[0169] The first drilling rig, positioned at location 304 above the planned connection wellbore 140, will drill a 440 mm (17 1 / 4 inch) diameter hole to a depth of 650 m. The drilling mud / drilling fluid used may be an environmentally friendly freshwater gel system. Examples of drilling muds include, but are not limited to, bentonite clay as a gel, along with additives such as barium sulfate (barite), calcium carbonate (chalk), or hematite. Those skilled in the art will recognize different drilling muds that may be used in connection with the drilling rig. A surface casing 212 is set in place having a diameter of 340 mm (13 3 / 8 inches) and extending to a depth of 650 m. The entire length and circumference of the surface casing 212 is cemented to the surface 316. The surface casing 212 is important for securely securing the planned connection wellbore 140 in place, preventing shallow formations from collapsing into the wellbore, and providing a foundation for the Class 5 blowout preventer, described below.

[0170] The second rig, located at location 308 of the proposed injection well 112, drills a 311 mm (12 1 / 4 inch) diameter hole to a depth of 650 m. Similar to the drilling by the first rig located at location 304, the drilling mud for the second rig can be an environmentally friendly freshwater gel system. A surface casing 144 is set in place having a diameter of 244 mm (9 5 / 8 inches) and extending to a depth of 650 m. The entire length and circumference of the surface casing 144 is cemented to the surface 316. Similar to the surface casing 212, the purpose of the surface casing 144 is to securely anchor the proposed injection well 112 in place, prevent shallow formations from collapsing into the wellbore, and provide a foundation for a Class 5 blowout preventer, described below. Additionally, the surface casing 144 prevents leakage of the working fluid 200 into the surrounding environment.

[0171] The cement casing used for both surface casings 144 and 212 is preferably 1860 kg / m 3 (Total cement mass approximately 80t) with the calculated total void volume and 50% excess hot-mix cement. The cement casing was then filled to 2.5m 3 The cement casing can then be subjected to a first pre-flush of 1200 kg / m of fresh water. 3 Weighted to 5m 3 The cement plug can then be dropped and replaced with fresh water.

[0172] A Class 5 blowout preventer (not shown) may be installed on or near the surface casings 144 and 212. The Class 5 blowout preventer is used to seal, control, and monitor the injection well 112 and connecting wellbore 140 to prevent blowouts. In this embodiment, the Class 5 blowout preventer is pressure tested to a low pressure of 1,400 kPa and a high pressure of 35,000 kPa, with each pressure tested for a period of at least ten (10) minutes. The Class 5 blowout preventer may also be pressure tested according to the formation pressure and any associated regulatory requirements.

[0173] The drilling of the holes in the injection well 112 and the connector wellbore 140 is directional controlled by a directional drilling assembly with measurements taken during drilling ("MWD") survey to maintain target accuracy. Specifically, the first drilling rig at location 304 drills a 311 mm (12 1 / 4 inch) diameter intermediate hole (not shown) through the surface casing to a predetermined depth. The connector wellbore 140 is first drilled vertically and then directionally drilled to achieve a 90-degree dip at a landing point 228 adjacent the lower end 216 of the connector wellbore 140. This landing point 228 is within the geothermal target formation located at the target temperature depth. In this embodiment, the connector wellbore 140 is drilled with an oil-based mud system to minimize spills and protect the integrity of the wellbore. However, the drilling mud system used may depend on the region and historical drilling issues in that region. Those skilled in the art will recognize different potential drilling mud systems that may be used.

[0174] An intermediate thermal casing 236 having a diameter of 244 mm (9 5 / 8 inches) runs the full depth of the connecting wellbore 140, and the intermediate thermal casing 236 can be cemented to the surface of the surrounding rock formation 320. The intermediate thermal casing 236 is then extended for a distance of 5 m. 3 The intermediate thermal casing 236 may then receive an initial pre-flush of 1450 kg / m thickened water, which is weighted to provide a wellbore pressure / hydrostatic pressure greater than that of the formation pressure to maintain an overbalanced wellbore. 3Weighted over 5m 3 A second pre-flush of scavenger may be performed. The overbalanced wellbore prevents gas or fluid buildup from entering the wellbore and rising to the surface. Cement is then filled / fed into the intermediate thermal casing 236 with Thermolite cement at the calculated total borehole volume plus a 20% surplus (approximately 75 t). The tail cement is then fed with 20% (approximately 45 t) of airtight cement. The inner diameter of the cement is then replaced with fresh water to form a hollow wellbore, leaving the outer diameter cemented to the bedrock formation 320.

[0175] The cement volume and mix can be adjusted depending on historical well data, formation pressure, and local regulatory isolation requirements for the particular formation to prevent cross-flow contamination.

[0176] The intermediate thermal casing 236 can be secured to the wellhead / entrance 232 using a speedhead or additional wellhead section to set a slip. The slip (also referred to herein as an anchor) may be set in full tension on the intermediate thermal casing 236 to hold the intermediate thermal casing 236 inside the surface casing 212. In certain embodiments, the Class 5 blowout preventer on the surface casing 212 may have to be disassembled to install the slip. Once reassembled, the Class 5 blowout preventer may be pressure tested again at the same pressure and specifications to confirm the integrity of the Class 5 blowout preventer after reassembly, but with the intermediate thermal casing 236 in the connected well 140.

[0177] A gyroscopic wireline survey tool can be deployed in the connecting wellbore 140. The gyroscopic wireline survey tool allows for continuous surveying from vertical to horizontal and to the point of rejection. The gyroscopic wireline survey tool provides the wellbore geometry with very high accuracy and gives precise coordinates of the connecting wellbore 140 to assist in intersecting with the injection well 112.

[0178] The first drilling rig then drills a 222 mm (8 3 / 4 inch) diameter main hole through the intermediate thermal casing 236 to provide a 200 m diameter open hole. As above, the drilling of the main hole by the first drilling rig may use an oil-based mud system.

[0179] After the main hole is drilled, the directional drilling assembly is removed from the well. The magnetic tool is then lowered into the wellbore to the end of the 200m open-hole section. An example of a magnetic tool is the Lodestone™ provided by Scientific Drilling. The magnetic tool is an active ranging system built for intentional wellbore intersections. It can be used in conjunction with any MWD system. The magnetic tool's sensor can be deployed in the connection wellbore 140, and the magnetic sub can be deployed in the directional drilling assembly of the injection well 112. The resulting magnetic field provides accurate ranging of the intersection along the horizontal section 116 between the connection wellbore 140 side and the injection well 112 side.

[0180] The second rig drills a 222 mm (8 3 / 4 inch) main hole through the surface casing 144 to a predetermined depth. In a preferred embodiment, the predetermined depth is 2300 m to 2500 m, although the depth may vary depending on the preferred temperature or geothermal target formation. Initially, the well may be drilled vertically and then directionally drilled to achieve a 90-degree dip with the landing point 224 proximate the lower end 196 of the injection well 112. The landing point 224 is within the geothermal target formation. Similar to the first drill rig drilling the main hole of the connecter wellbore 140, the main hole of the injection well 112 may be drilled with an oil-based mud system. The drilling assembly may then be removed from the wellbore. A gyroscope wireline survey tool may then be deployed within the injection well 112 to provide the coordinates of the injection well 112 to assist in intersecting the connecter well 140. A new directional control drilling assembly equipped with magnetic tools (such as the Lodestone™ package mentioned above) is lowered into the wellbore.

[0181] To intersect the ends of the lower lateral sections 116, drilling continues laterally from the injection well 112 and the landing point 224 ends of the lower lateral sections 116 toward the connecting wellbore 140. The magnetic tooling facilitates the intersection of the two wellbores. Once the ends of the lower lateral sections 116 intersect at the intersection point 240, both directional control drilling assemblies can be removed from their respective wellbores.

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

[0183] Referring to FIG. 8 , a 139 mm (5 1 / 2 inch) diameter production steel casing 156 may be installed along the injection well 112 and along the lower lateral section 116 from the landing point 224 to the intersection 240. Specifically, the production steel casing 156 may extend from the entrance 112A of the injection well 112 at the surface 316 up to 50 m into the intermediate thermal casing 236 of the connecting wellbore 140. The lowermost section 248 of the production steel casing 156 has a connection / seal assembly (not shown) used to make a pressure-tested connection with the polygonal connector 120. In this embodiment, the connection / seal assembly is a polished bore receptacle. The polished bore receptacle is completed with a Baker convergent / inverted seal bore extension and an anchor seal assembly latch profile (not shown).

[0184] Custom steel centralizers (not shown) can also be attached to the exterior of the casing 156 prior to cementing. The centralizers are typically designed to elevate the casing 156 from the bottom of the lower lateral sections 116, thus allowing the cement to completely surround the casing 156. Custom elongated centralizers can also be used to increase the electrical conductivity between the formation heat and the steel body of the casing 156 directly through the cement 152 (because it is made of steel). As previously mentioned, hematite additions may be added to the cement 152 to optimize electrical conductivity.

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

[0186] 9, the isolation packer 252 is a rubber element that can be expanded to form an impermeable seal between the outer diameter of the production steel casing 156 and the inner diameter of the intermediate thermal casing 236. This prevents cement from entering the remaining intermediate casing and causing a blockage within the construction well 140. In a preferred embodiment, two isolation packers 252 can be used to increase the integrity of the seal packer (not shown).

[0187] The cementing stage tool 256 is opened (which also forms an internal diameter plug in the end of the production steel casing 236 to prevent cement from entering the intermediate thermal casing 156 from the connecting well 140). The production steel casing 156 from the injection well 112 may then be cemented to the surface of the surrounding rock formation 320.

[0188] The cementing production steel casing 156 includes a first circulation injection well 112 that cleans out all drill cuttings. A first dart is then dropped from the surface into the injection well 112 to expand the isolation packer 252, and the cementing stage tool 256 is opened to allow cement to circulate around the outer diameter of the production steel casing 156. The injection well 112 is then pumped to a depth of 5 m. 3 The injection well 112 then receives an initial pre-flush of 5 m thickened water, where, as with the previous flush, the thickened water is metered to maintain an overbalanced wellbore. 3 A second pre-flush of the scavenger is performed, with the scavenger pumping 1450 kg / m 3 to maintain the overbalance in the injection well 112. 3The cement is then filled / fed into the intermediate thermal casing 236 with thermolite cement at the calculated total borehole volume plus a 20% excess (approximately 62 t). The tail cement is then fed with a 20% excess (approximately 98 t) of airtight cement. The cement is then replaced with fresh water. As with the previously described drilling procedure for connecting the well 140, those skilled in the art will appreciate that the volume, mix, and spacing of the cement and pre-flushing can be adjusted based on the geographic location and historical formation data, formation pressure, and local regulatory isolation requirements for the particular formation to prevent cross-flow contamination. A second dart is also dropped from the surface into the injection well 112 and lands within the cementing stage tool 256 (which acts as a check valve), closing the cementing port and effectively preventing cement from flowing back up the injection well 112.

[0189] The production steel casing 156 is tensioned by automatic slip within the casing bowl, which allows the production steel casing 156 to be bolted to a Class 5 blowout preventer.

[0190] The second drilling rig picks up a milling assembly including a 4 1 / 2 inch (114.3 mm) bit, mud motor, and 2 7 / 8 inch (73 mm) diameter drill pipe. It drills the hole and mills the cementing stage tool 256 and float device to allow unrestricted flow of working fluid 200. Debris is also removed from the connecting wellbore 140, lower lateral section 116, connecting piece 160, and injection well 112 by circulating blocked water down the injection well 112, through the connecting piece 160 and lower lateral section 116, and to the connecting wellbore 140 to the surface 316.

[0191] In step 1520 (shown in FIG. 15), the two-piece whipstock 260 is installed, access holes are drilled to allow for the planned production well 128 and intersection of the upper lateral section 124 and the lower lateral section 116, and an initial hole for the production well 128 is drilled.

[0192] Referring to FIG. 10 , a two-piece whipstock 260 (also referred to herein as whipstock 260) is installed in the lower side section 116 between the landing point 228 and the isolation packer 252, adjacent to the isolation packer 252. The whipstock 260 includes an upper section (spoon) that forces a pineapple mill (not shown) to cut a diamond-shaped window 264 (also referred to herein as a milled window 264 and a bridge hole 264) through the intermediate casing 236. The whipstock 260 also includes a lower section (not shown) that includes a guide and anchor (not shown) that may be permanently installed in the intermediate casing. The guide allows the drilling assembly and completion assembly to be pushed through the window, along with a 5½-inch diameter hole through the center of the guide. This allows the completion assembly to be diverted to the lower section of the wellbore. Those skilled in the art will recognize the use of whipstocks and their use in creating wellbore joints.

[0193] The whipstock and milled window 264 allow for the drilling of a second wellbore from the connecting wellbore 140 into the geothermal target formation.

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

[0195] The cement casing used in conjunction with the surface casing 148 is preferably 1860 kg / m 3 (approximately 45t) volume + 50% hot cement. Then the cement casing is 2.5m 3The cement casing can then be subjected to a first pre-flush of 1200 kg / m of fresh water. 3 Weighted to 5m 3 The cement plug can then be dropped in and replaced with fresh water.

[0196] Similar to the alternative configuration of surface casing 144, a Class 5 blowout preventer may be installed on or near surface casing 148. The Class 5 blowout preventer may then be pressure tested under the same conditions and with the same considerations as the Class 5 blowout preventer at injection inlet 112.

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

[0198] Referring to FIG. 11 , a first drilling rig can drill a 222 mm (8 3 / 4 inch) diameter main hole through intermediate thermal casing 236 to provide an additional 200 m of open hole. In this embodiment, the main hole may be drilled with an oil-based mud system. The directional control drilling assembly can be removed from the connection wellbore 140. The magnetic tooling can then be lowered into the connection wellbore 140 to the end of the 200 m open hole leading from connector piece 160. The magnetic tooling can be deployed into the connection well 140 and a magnetic sub can be deployed on the directional assembly in the production well 128.

[0199] The second drilling rig penetrates the surface casing 148 and drills a 222 mm (8 3 / 4 inch) diameter main hole to a predetermined depth. The production well 128 is first drilled vertically and then directionally drilled to achieve a 90-degree inclination at a landing point 272, which is in the geothermal target formation. As with the previous drilling procedure, the production well 128 can be drilled with an oil-based mud system. The directional control drilling assembly can be detached from the production well 128, and a gyroscopic wireline survey tool can be deployed to the production well 128. The gyroscopic wireline survey tool can provide coordinates of the production well 128 to assist in intersecting the connecting wellbore 140. A new drilling assembly equipped with a magnetic tool can be lowered into the production well 128. Drilling continues in the direction of the connecting wellbore 140. The magnetic tool and magnetic sensor facilitate the intersection of the two wellbores. Once the connecting wellbore 140 and the production well 128 intersect, both directional control drilling assemblies can be removed from the wellbore.

[0200] The upper section of the whipstock (spoon) is removed, leaving the lower section of the whipstock 260 within the intermediate thermal casing 236 of the connecting wellbore 140. The lower whipstock section (guide and anchor) allows the polygon connector 120 with a short section of casing or directional drilling assembly to be diverted from the window to the open-hole section connected to the production well 128. Additionally, the guide has a 139 mm (5 1 / 2 inch) diameter hole through the center of the whipstock 260. This allows a polygon connector 120 with a specific outer diameter to be lowered below the whipstock and connected to the production casing above the injection well 112. By adjusting the outer diameter of the completed assembly, the installer can ensure that the correct assembly enters the correct wellbore.

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

[0202] Referring to FIG. 12 , a 139 mm (5 1 / 2 inch) diameter production steel casing 156 is installed in the wellbore that intersects the connecting wellbore 140. The production steel casing 156 may extend from the production well 128 at the surface 316 of the outlet 128A to within approximately 20 m of the intermediate thermal casing window 264 in the connecting wellbore 140. The lowermost section 276 of the production steel casing 156 may have a connection / seal assembly similar to that of the lowermost section 248; specifically, in this embodiment, the connection / seal assembly may be a polished bore receptacle with a baker convergence / inverted seal bore extension and an anchor seal assembly latch profile.

[0203] In step 1535 (shown in FIG. 15), the polygon connector 120 is installed and connected between the upper lateral section 124 and the lower lateral section 116. The fully cased downhole well loop 108 is then pressure tested.

[0204] Referring to FIG. 13 , two dummy trips are made to the injection well 128. The first trip is made using a polished bore locating seal assembly without a latch and having an outer diameter greater than 5½ inches for a tag receptacle in the production well 128 to verify the correct depth of the interval. The second trip is made using a polished bore locating seal assembly without a latch and having an outer diameter less than 5½ inches for a tag receptacle in the injection well 112 to verify the correct depth of the interval. This process allows for accurate depth measurements and distances between the access well 140, the injection well 112, and the production well 128. The polygon connectors 120 can then be configured at the appropriate intervals to connect the injection well 112 and the production well 128.

[0205] To connect the injection well 112 and the production well 140, the polygonal connector 120 can be lowered (using drill pipe for landing operations) into the connection well 128. The polygonal connector 120 is composed of two distinct "legs," each designed to securely and easily enter a specific well (either the injection well 112 or the production well 128) and form a pressure-tested connection with the production steel casing 156 in each of the injection well 112 and the production well 128. One leg 292 includes a ground bore-locating seal assembly with a concentrated shear-type protective shroud having an outer diameter of less than 139 mm. This allows the ground bore-locating seal assembly to be lowered through a window guide and connected to the ground bore receptacle of the production steel casing on the injection well 112. The second leg 296 of the polygonal connector 120 is of the same design except that it has an outer diameter greater than 139 mm and extrudes a polished bore-locating seal assembly with a concentrated shear protective shroud through the milled window and connects with the production steel casing 156 through a polished bore receptacle in the production well 128. The second leg 296 may also include a pin / shear-actuated sleeve to protect the seal from rubbing damage through the window 280 and open-hole section.

[0206] The polygonal connector 120 provides complete mechanical and hydraulic isolation support for the cementing area with re-entry capability. The polygonal connector 120 is designed to accommodate re-entry tie-ins in steam-assisted gravity drainage applications. The polygonal connector is typically performed with a full-length liner on one attachment, and a second attachment provides an existing lateral pressure test seal. The polygonal connector 120 serves to provide a confluence for the injection well 112 and the production well 128, utilizing the connecting wellbore 140 as the entry point.

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

[0208] Once the connection of the polygonal connector 120 to the injection well 112 and the production well 128 is complete, circulation can be established from the production well 128 through the production steel casing 156, through the drill pipe, and to the surface 316 above the connecting wellbore 140. Valves can be closed at the surface 316 of the connecting wellbore 140, and the entire assembly and seal connection of the injection well 112 and the production well 128 can be pressure tested. The production well 128 can be circulated first to allow the production well 128 and the injection well 112 to be cleaned of any remaining cuttings.

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

[0210] In step 1540 (shown in FIG. 15), the isolation packers 284 and cementing stage tooling 288 are installed and the production steel casing 156 and upper lateral section 124 of the production well 128 are cemented in place.

[0211] 13 , upon successful circulation and passing of the pressure test, the cementing stage tool 288 can be opened. The cementing stage tool 288 also creates an inside diameter plug at the end of the production steel casing to prevent cement from entering the intermediate thermal casing 236 from the connecting wellbore 140 and injection well 112. The production steel casing 156 from the production well 128 is cemented full length to the surface of the surrounding rock formation 320 at the production well 128. This includes the entire open-hole section of the production well 128 and the inside diameter of the surface casing.

[0212] Cementing the production steel casing 156 follows the same procedures as described above, including dropping the first dart, expanding the isolation packer 284, opening the cement staging tool 288, pre-cleaning the production steel casing 156 first with viscous water and then with scavenger, filling with thermolite cement, providing tail cement, replacing the cement with fresh water, and then dropping the second dart. The production steel casing 156 is tensioned by automatic slip within the casing bowl.

[0213] The second drilling rig picks up a milling assembly consisting of a 4 1 / 2 inch (114.3 mm) bit, mud motor, and 2 7 / 8 inch (73 mm) diameter drill pipe. It then drills the hole and mills the cementing stage tool 288 and float device. Additionally, all debris is removed from the wellbore by circulating first back to the production well 128 and finally to the production steel casing 156 of the injection well 112.

[0214] Alternatively, the cementing stage tools 256 and 288 may be milled into the injection well 112 and the production well 128, along with the connections of the polygon connectors 120 to the lateral sections 116 and 124 after cementing. This can be completed with a drilling rig and cementing drill pipe, or a coiled tubing unit. In either case, a 114 mm (4 1 / 2 inch) drill bit can be used to mill the cementing stage tools 256 and 288 and verify the full gauge inside diameter of the production steel casing 156. Additionally, milling cleans the inside diameter of the production steel casing 156 of any debris and excess cement. Coiled tubing can also be used to mill both the production well 128 and the injection well 112.

[0215] A wireline retrievable insulating plug may be installed in the connecting wellbore 140 in the intermediate thermal casing 236 above the polygonal connector 120. Positive and negative pressure tests may then be performed.

[0216] Once the test has been successfully performed, the geothermal energy generation system 100 is ready to operate according to the method steps shown in FIGS.

[0217] The construction of the geothermal energy generation system 100 utilizes known techniques and methods in wellbore construction in the oil and gas field, but applies said techniques and methods in a new and innovative way for the production and generation of energy from geothermal sources.

[0218] While the foregoing description and accompanying drawings are directed to certain preferred embodiments of the invention presently contemplated by the inventors, it will be understood that various changes, modifications, and adaptations can be made thereto without departing from the spirit of the invention.

Claims

1. 1. A system for generating energy from a geothermal source, comprising: an injection well extending underground into the bedrock formation and having an upper end and a lower end; a production well extending underground into the bedrock formation adjacent to the injection well, the production well having an upper end and a lower end; a first lateral section connected to and extending away from a location along the injection well; a second lateral section connected to a location along the production well and extending away from the location; the first and second side sections are connected to a polygonal connector, and each of the first and second side sections has a length greater than the distance between the upper ends of the injection well and the production well; each of the injection well, the production well, and the first and second lateral sections being cased with steel and cemented in place within the rock formation; the injection well, the first lateral section, the polygonal connector, the second lateral section, and the production well cooperate with one another to define a pressure tested downhole well loop within the rock formation in heat transfer configuration therewith, the pressure tested downhole well loop configured to receive a working fluid capable of undergoing a phase change between a liquid and a gas within the pressure tested downhole well loop as a result of heat transferred from the rock formation; a pump fluidly connected to the injection well, the pump configured to circulate the working fluid through the pressure tested downhole wellbore loop; a turbine system fluidly connected to the production well and operable to convert mechanical energy generated from the flow of the working fluid into electricity; and a cooler fluidly connected between the pump and the turbine system for cooling the working fluid.

2. 10. The system of claim 1, further comprising an injection well surface casing surrounding an entrance to the injection well, the injection well surface casing partially above the surface and configured to prevent leakage of the working fluid into the rock formation.

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

4. 4. The system of claim 1, wherein the injection well includes an inlet and the production well includes an outlet, the inlet and the outlet being located on the surface in close proximity to each other, and the inlet being at a distance of 7 m to 50 m from the outlet.

5. 22,500m ２ 5. The system of claim 1, wherein the system has a ground surface area of

6. The system of claim 1 , wherein the working fluid is a homogeneous working fluid.

7. The system of claim 1 , wherein the working fluid is a heterogeneous working fluid.

8. The system of any one of claims 1 to 7, wherein the injection well has a depth of between 1000m and 4000m.

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

10. The system of any one of claims 1 to 9, wherein the second lateral section has a length of between 2000m and 4000m.

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

12. 12. The system of claim 1, wherein the first lateral section is longer than the second lateral section and the first lateral section is at a depth less than a depth of the second lateral section.

13. 12. The system of claim 1, wherein the first lateral section is at the same depth as the second lateral section, the first lateral section extends away from the lower end of the injection well at a first angle, and the second lateral section extends away from the lower end of the production well at a second angle.

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

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

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

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

18. The system of claim 1 , wherein the turbine system includes a turbine expander.

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

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

21. 21. The system of claim 1, further comprising a storage tank connected between the chiller and the pump and configured to hold excess working fluid.

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

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

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

25. 25. The system of claim 1, further comprising a recuperator having a first flow passage connected between the turbine system and the cooler and a second flow passage connected between the pump and the injection well, the recuperator configured to transfer heat from the first flow passage to the second flow passage.

26. 26. The system of any one of claims 1 to 25, further comprising an access well having a lateral segment, the polygonal connector being positioned within the lateral segment of the access well.

27. the injection well is a first injection well, the production well is a first production well, the polygonal connector is a first polygonal connector, the pressure tested downhole well loop is a first pressure tested downhole well loop, and the pump is a first pump; a second injection well extending subsurface into the bedrock formation and having an upper end and a lower end; a second production well extending underground into the bedrock formation adjacent to the second injection well, the second production well having an upper end and a lower end; a third lateral section connected to and extending away from a location along the second injection well; a fourth lateral section connected to a location along the second production well and extending away from the location, the third and fourth lateral sections being connected to a second polygonal connector, each of the third and fourth lateral sections having a length greater than the distance between the upper ends of the second injection well and the second production well; each of the second injection well, the second production well, and the third and fourth lateral sections being cased with steel and cemented in place within the rock formation; the second injection well, the third lateral section, the second polygonal connector, the fourth lateral section, and the second production well cooperate with one another to define a second pressure tested downhole well loop within the rock formation in heat transfer configuration therewith, the second pressure tested downhole well loop being configured to receive the working fluid capable of undergoing a phase change between a liquid and a gas within the second pressure tested downhole well loop as a result of heat transferred from the rock formation; a second pump fluidly connected to the second injection well, the second pump configured to circulate the working fluid through the second pressure tested downhole well loop; the second production well is fluidly connected to the turbine system, the turbine system configured to receive the working fluid from the first production well of the first pressure tested downhole well loop and the second production well of the second pressure tested downhole well loop; the cooler is fluidly connected to both the first pump connected to the first injection well and the second pump connected to the second injection well; 27. The system of claim 26, wherein the second polygonal connector of the second pressure tested downhole well loop is positioned within the lateral segment of the access well at a location spaced apart from the first polygonal connector.

28. 28. The system of claim 27, wherein the first injection well includes a first inlet, the first production well includes a first outlet, the second injection well includes a second inlet, and the second production well includes a second outlet, the second inlet and the second outlet being located on a surface adjacent to each other, and the second inlet being at a distance of 7 m to 50 m from the second outlet.

29. 30. The system of claim 28, wherein the first inlet and the second inlet are located on the surface adjacent to each other, the first inlet being at a distance of at least 20 m from the second inlet.

30. 30. The system of claim 28, wherein the first outlet and the second outlet are located on the surface adjacent to each other, and the first outlet is at a distance of at least 20 m from the second outlet.

31. The system is 45,000m ２ 30. The system of claim 28, having a ground surface area of

32. 1. A method for producing energy from a geothermal source, comprising: providing a pressure tested downhole wellbore loop extending subsurface into a rock formation, said pressure tested downhole wellbore loop comprising: the system includes an injection well, a production well adjacent to the injection well, a first lateral section connected to the injection well, a second lateral section connected to the production well, and a polygonal connector connecting the first lateral section and the second lateral section; each of the injection well, the production well, and the first and second lateral sections being cased with steel and cemented in place within the rock formation, the first and second lateral sections having a length greater than the distance above the surface between the injection well and the production well; conveying the working fluid through the pressure-tested downhole well loop, wherein the working fluid is received by the injection well in a liquid state; Meanwhile, conveying the working fluid through the pressure-tested downhole well loop to transfer heat from the surrounding rock formation to the liquid working fluid and exert pressure on the liquid working fluid; inducing a phase change of the working fluid from a liquid state to a gaseous state, such that the working fluid exits the production well in a gaseous state; converting mechanical energy generated from the flow of gas working fluid into electricity; cooling the working fluid to induce a phase change of the working fluid to a liquid state; and returning the working fluid to the injection well.

33. 33. The method of claim 32, wherein conveying the working fluid through the pressure tested downhole well loop comprises pumping the working fluid.

34. 34. The method of claim 32 or 33, wherein exerting a pressure on the liquid working fluid comprises exerting a pressure of between 7 MPa and 31 MPa on the liquid working fluid.

35. 35. The method of any one of claims 32 to 34, wherein the step of converting mechanical energy generated from the flow of gaseous working fluid into electricity produces an output power of between 0.5 and 2 MW.

36. 36. The method of any one of claims 32 to 35, wherein the step of cooling the working fluid to induce a phase change in the working fluid is cooled using a chiller.

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

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

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

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

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

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

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

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

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

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

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

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

49. 49. The method of any one of claims 32 to 48, wherein the temperature of the propane increases by 76°C and the pressure of the propane increases by 2170 kPag during conveying the working fluid through the pressure tested downhole well loop.

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

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

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

53. 1. A method of constructing a pressure-tested downhole well loop for a system for producing energy from a geothermal source, the pressure-tested downhole well loop configured to transfer heat from a surrounding rock formation to a working fluid flowing within the pressure-tested downhole well loop to induce a phase change of the working fluid from a liquid state to a gaseous state, the method comprising: providing an access well extending subsurface into the bedrock formation; drilling an injection well into the subsurface rock formation, the injection well being spaced from the access well; drilling a first lateral section extending away from the injection well and connecting to the access well; installing a first steel casing for the injection well and the first lateral section; cementing the first steel casing for the injection well and the first lateral section in place within the rock formation; drilling the production well into the subterranean rock formation adjacent to the injection well; and drilling a second lateral section extending away from the production well toward a connection point between the first lateral section and the second lateral section, the connection point being located along the access well adjacent to the first lateral section; installing a second steel casing for the production well and the second lateral section; providing a polygonal connector through the access well and installing the polygonal connector at the connection point between the first and second side sections; pressure testing the downhole wellbore loop, the downhole wellbore loop including the injection well, the first lateral section, the polygonal connector, the second lateral section, and the production well, the first and second lateral sections having lengths greater than a distance on the surface between the injection well and the production well; and cementing the second steel casing for the production well and the second lateral section into the rock formation.

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

55. 55. The method of claim 53 or 54, wherein cementing the first casing for the injection well and the first lateral section in place within the rock formation includes drilling a bridge hole at an intersection between the first lateral section and the second lateral section, and drilling the second lateral section includes connecting the second lateral section to the bridge hole.

56. 56. The method of any one of claims 53 or 55, further comprising installing a first isolation packer and a first cementing stage tool prior to cementing the first casing for the injection well and the first lateral section in place within the rock formation, the first isolation packer and the first cementing stage tool being installed proximate the intersection between the first lateral section and the access well, the first isolation packer being installed around an outer diameter of the first casing, and the first cementing stage tool being installed within the first casing to block an inner diameter of the first casing.

57. 57. The method of any one of claims 53 to 56, wherein drilling the second lateral section extending away from the production well toward the connection point includes placing a whipstock within the first lateral section proximate the connection point.

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

59. 59. The method of any one of claims 53 to 58, wherein pressure testing the downhole wellbore loop comprises subjecting the downhole wellbore loop to a pressure at a maximum depth within the downhole wellbore loop.

60. 61. The method of any one of claims 53 to 60, further comprising the step of installing a second isolation packer and a second cementing stage tool prior to cementing the second casing for the production well and the second lateral section in place within the rock formation, the second isolation packer and the second cementing stage tool being installed proximate the intersection between the second lateral section and the polygonal connector, the second isolation packer being installed around an outer diameter of the second casing, and the second cementing stage tool being installed within the second casing to block an inner diameter of the second casing.

61. 1. A system for generating energy from a geothermal source, comprising: a first injection well and a second injection well extending subsurface into the bedrock formation, each of the first and second injection wells having an upper end and a lower end; a first production well and a second production well extending subsurface into a bedrock formation, each of the first and second production wells being adjacent to both the first and second injection wells, each of the first and second production wells having an upper end and a lower end; a first lateral section connected to and extending away from a location along the first injection well; a second lateral section connected to a location along the first production well and extending away from the location; a third lateral section connected to and extending away from a location along the second injection well; a fourth lateral section connected to a location along the second production well and extending away from the location; the first and second lateral sections are connected to a first polygonal connector, and each of the first and second lateral sections has a length greater than the distance between the upper ends of the first injection well and the first production well; the third and fourth lateral sections are connected to a second polygonal connector, and each of the third and fourth lateral sections has a length greater than the distance between the upper ends of the second injection well and the second production well; each of the first and second injection wells, the first and second production wells, and the first, second, third, and fourth lateral sections being cased with steel and cemented in place within the rock formation; the first injection well, the first lateral section, the first polygonal connector, the second lateral section, and the first production well cooperate with one another to define a first pressure-tested downhole wellbore loop within the rock formation, and the second injection well, the third lateral section, the second polygonal connector, the fourth lateral section, and the second production well cooperate with one another to define a second pressure-tested downhole wellbore loop within the rock formation and in heat transfer arrangement with the rock formation, each of the first and second pressure-tested downhole wellbore loops configured to receive a working fluid capable of undergoing a phase change between a liquid and a gas as a result of heat transferred from the rock formation; a first pump fluidly connected to the first injection well, the first pump configured to circulate the working fluid through the first pressure tested downhole well loop; a second pump fluidly connected to the second injection well, the second pump configured to circulate the working fluid through the second pressure tested downhole well loop; a turbine system fluidly connected to the first and second production wells, the turbine system operable to convert mechanical energy generated from the flow of working fluid into electricity; a cooler fluidly connected between the first and second pumps and the turbine system, the cooler operable to cool the working fluid received from the turbine system and to supply the cooled working fluid to both the first and second pumps; The system wherein the first and second pressure tested downhole well loops are located in close proximity to one another.

62. 1. A system for generating energy from a geothermal source, comprising: an injection well extending below ground into the bedrock formation and having an upper end and a lower end; a production well extending underground into the bedrock formation adjacent to the injection well, the production well having an upper end and a lower end; a first lateral section connected to and extending away from a location along the injection well; a second lateral section connected to a location along the production well and extending away from the location; the first and second side sections are connected to a polygonal connector; each of the injection well, the production well, and the first and second lateral sections being cased with steel and cemented in place within the rock formation; the injection well, the first lateral section, the multi-lateral connector, the second lateral section, and the production well cooperate with one another to define a pressure-tested downhole well loop within the rock formation in heat transfer configuration therewith, the pressure-tested downhole well loop configured to withstand a pressure of at least 7 MPa and to receive a working fluid capable of undergoing a phase change between a liquid and a gas within the pressure-tested downhole well loop as a result of heat transferred from the rock formation; a pump fluidly connected to the injection well, the pump configured to circulate the working fluid through the pressure tested downhole well loop; and a turbine system fluidly connected to the production well, the turbine system operable to convert mechanical energy generated from the flow of the working fluid into electricity. a cooler fluidly connected between the pump and the turbine system for cooling the working fluid.

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