WO2023091786A1 - Supercritical geothermal energy system - Google Patents

Abstract

Described herein is a supercritical geothermal energy system including injection and production pipelines, each having a vertical component and horizontal component. The pipelines are disposed in a rock formation of at least 750°F. A working fluid is pumped through the injection pipelines to convert the working fluid into a high enthalpy vapor in the rock formation. The vapor may then be collected in the production pipelines, which are connected to a plant above the surface of the rock formation.

Description

SUPERCRITICAL GEOTHERMAL ENERGY SYSTEM

CROSS REFERENCE TO RELATED APPLICATION(S)

[0001] The present application claims priority to U.S. Provisional Patent Application No. 63/281,771 filed on November 22, 2021, the entire contents of which are incorporated by reference herein.

FIELD OF THE INVENTION

[0002] The present invention relates to energy systems, and in particular to supercritical geothermal energy systems.

BACKGROUND OF THE INVENTION

[0003] Human civilization uses energy to function. Energy is obtained from energy resources such as fossil fuels, nuclear fuel, and renewable energy. One type of renewable energy is geothermal heat.

[0004] The Earth is a vast storehouse of energy. Temperatures in the Earth’s core may reach 10,000 degrees F. In the zone between the mantle and the Earth’s crust, temperatures may reach 1,000 degrees F. Subterranean temperatures closer to the surface rise with increasing depth at a rate of about 30 °C per kilometer (75 °F per mile). Near the edges of tectonic plates, however, temperatures typically rise much faster. Therein, rock formation temperatures in excess of 700 °F are accessible near the Earth’s surface. In the United States, such sites may be found in the Cascade Mountains (Washington and Oregon), in Nevada, and in the Salton Sea (California).

[0005] In simple geothermal systems, a borehole is drilled to a suitable depth in which surrounding rocks are found at a desired temperature for energy extraction. A simple geothermal system may include a looped pipeline for circulating water in contact with rocks of a suitable temperature. The water is heated by conductive contact between water passing along the sides of the pipeline which are, in turn, heated conductively by the surrounding rock. The water is then returned to the surface where the now heated water may directly heat a building, for example, or drive an engine to produce electricity.

[0006] In other systems, a pipeline is placed in a borehole drilled to a depth at which the surrounding rock is at a desired temperature. Water is injected into this pipeline and ejected through perforations in the pipeline. The injection pipeline is located near a similar production pipeline drilled to a suitable depth and which has disposed thereon perforations. Each such pipeline may or may not comprise a horizontal pipeline component. Further, the depth at which injection is made may differ somewhat from the depth at which take up in the production pipe is made. The injected water is heated as it passes through the rock formation and the now hot water is withdrawn through the production pipeline for use. In this system, the rock formation may contain natural seams or may be thermally or hydraulicly stimulated, or both. In a sufficiently hot rock formation, water may be converted to steam prior to take up in the production pipeline.

[0007] While the Earth is a vast storehouse of energy, the ability to tap that energy in a geothermal system is limited. Water pumped through a rock formation can remove energy from the rock far more quickly than it is replaced by the surrounding rocks. That is because rock conducts heat poorly. Granite, for example, conducts heat at about 3.2 W/mK. Copper, by comparison, conducts heat at rate of about 398 W/mK. When water is pumped through geothermal systems at high rates, it commonly can extract more heat than can be replaced conductively by the rocks. As a result, rocks in the vicinity of the pipeline may quickly cool, reducing the efficiency of the geothermal system. This is commonly referred to as thermal breakthrough. In as little as a single day a geothermal system may have so much energy removed that it stops operating efficiently. As a result, geothermal systems are limited in their ability to be scaled up for large commercial operations.

[0008] Climate change caused by carbon emissions has created an urgency for people to develop sustainable alternative energy sources that operate reliably day and night for uninterrupted power production. Solar power operates only on sunny days. Wind power is likewise subject to local weather conditions. Each of these sources of energy require back up systems to provide power when they cannot.

[0009] Geothermal systems have faced challenges in being scaled up for large commercial operations, including designing a system that allows for constant operation at commercial levels (50MWe or more) on a 24/7 basis in a cost-effective way. Further, there is a desire for the system to operate for 25 years or more without losing the heating capability of the rocks tapped for energy production in an economical way. [0010] Thus, there is a need for a geothermal system which allows for the extraction of a large amount of energy from a rock formation at a sustainable rate. PRIOR ART IN THE FIELD

[0011] Research in large-scale geothermal energy systems is progressing at a high rate. U.S. Publication No. 2020/0217181 (the “’181 Publication”) (by Norbeck et al.) describes a geothermal system in which a plurality of injection and production pipelines, each having a vertical element and a horizontal element, are disposed in a rock formation up to approximately 400°F. Injection and production pipelines are disposed in parallel, and each is perforated in stages. Likewise, the rock formation is fractured and propped open using proppants of a plurality of sizes. The horizontal elements of the pipelines may extend through the rock formation from 50 to 5,000 feet. The design of the system of the ’181 Publication creates a uniform flow of a working fluid across the field of rock formation through which the working fluid is pumped. This allows a uniform extraction of heat from the rock formation and so a uniform use of the energy therein. This, then, reduces local cooling that results in local thermal breakthrough.

[0012] The ’181 Publication is limited by the complexity of its design, in which perforations may be 8 inches apart or 40 feet apart. Each well requires separate rock formation analysis. Likewise, a variety of proppant sizes must be used, and it is expected that the rock formation must be refractured from time-to-time.

[0013] The ’181 Publication is also limited by its dependence on maintaining water or other working fluid in liquid form and not a vapor. Thus, it is believed that the ’181 Publication is likewise inefficient. This is because it operates in lower temperature rock formations that do not convert all or even most of the injected water into steam. Therefore, the enthalpy of the water used to product electricity is lower than needed for efficient operation.

[0014] The present invention creates a larger rock formation reservoir and has a simpler design than the present prior art. The present invention also is able to convert the water into vapor form, improving on the efficiency of such energy systems.

SUMMARY OF THE INVENTION

[0015] The present invention is a high output geothermal energy system for the large- scale production of energy from a rock formation using water or a working fluid injected into a plurality of injection pipelines each having a vertical element suitable to reach a high temperature rock formation and a horizontal element inserted into the high temperature rock formation. The horizontal element of each injection pipeline includes a plurality of packers suitable to allow water or the working fluid to be pumped from the pipeline into the rock formation in a controlled manner by the control of adjustable ports on each packer. Pressure applied to the water then forces the water through thermal and hydraulic stimulation sites (referred to generally herein as “stimulation sites”) imposed in the rock formation and proximate to the packers of the injection pipeline. Each stimulation site is directed toward one or more of a plurality of production pipes, each having a horizontal element substantially the same length as the horizontal element of each injection pipeline. Each horizontal element of each production pipeline includes a plurality of packers suitable to allow the take up of hot vaporous water (steam) heated by passage through a stimulation site. Each horizontal element of each production pipeline is connected to a vertical pipeline suitable to return the hot steam to the surface of the Earth for use. Desired rock formations for the present invention are at a temperature of at least about 750°F.

[0016] Specifically, during passage from the injection pipeline through a stimulation site of the hot rock toward a production pipeline, water is “flashed,” or vaporized into steam by energy taken up into the water by contact between the water and the hot rock formation. The invention is designed to ensure 100% of the injected water is flashed into steam. The steam passes through the rock formation and continues to pick up additional energy from the rock formation during passage. It is then taken up by the production pipeline as a high enthalpy vapor and returned to the surface for use. The energy may be used for example, in electricity production in a Rankine engine.

[0017] Each injection pipeline and production pipeline has a large diameter and is disposed in a separate borehole which includes a vertical element which is drilled from the surface to a rock formation at a depth at which the temperature of the rock formation is in the desired range of temperatures. Ideally, this may be near the juncture of two tectonic plates. In such a location, tectonic plates typically generate heat by frictional forces between them near the Earth’s surface. Thus, shallower pipelines are possible. Likewise, the pipeline may be located in areas in which rock formations of a suitable temperature he deeper in the Earth. In some locations, suitable rock formations may be reached at about 1,000 feet. In other locations, suitable rock formations may be located at about 10 to about 12 miles into the Earth. A range of borehole diameters and pipeline diameters known in the field may be used. The desired pipeline diameter may be determined by the amount of water to be pumped into the rock formation in a set time period.

[0018] The horizontal borehole element may be drilled to extend form the bottom or near the bottom of the vertical borehole element. The horizontal borehole element may extend at least about 2 miles (typically about 7,000 to about 11,000 feet) through the rock formation. A pipeline may then be disposed in the vertical and horizontal elements of each borehole and may be fully or partially encased in cement or another suitable form of encasement. Typically, one or two production pipelines may be associated with each injection pipeline. In an embodiment, two production pipelines may be used for each injection pipeline. One production pipeline may be placed in parallel to the injection pipeline and spaced about 750 to about 1,500 feet from the injection pipeline on one side of the injection pipeline and the other production pipeline may be placed parallel to the injection pipeline and is also spaced about 750 to about 1,500 feet from the injection pipeline on the other side of the injection pipeline. A plurality of injection pipelines may be drilled and installed in a production field, typically side-by-side and spaced to allow production pipelines to be installed as described.

[0019] The horizontal elements of the injection pipelines may have disposed thereon a plurality of packers which permit the controlled passage of water therethrough. Packers may be spaced to allow the functional creation of the plurality of stimulation sites imposed in the rock formation surrounding the injection pipelines. The rock formation may be stimulated thermally and hydraulically in a plurality of locations along the horizontal element of the pipeline to create a minimum volume of pathways. Further, stimulation may be accomplished to expose a suitable volume of the rock formation to water pumped into the rock formation through each injection pipeline.

[0020] Similarly, each production pipeline may have disposed thereon a plurality of spaced packers in which the spacing of the plurality of packers matches the spacing of the plurality of packers of each injection pipeline. The rock formation surrounding each of the packers of the production pipeline may be stimulated to associate with at least one stimulation site of the injection pipeline so as to create a tortuous path for the water (and later steam) through the rock formation from the injection pipeline to the production pipeline. [0021] Each packer of each horizontal pipeline may have disposed thereon a plurality of ports which can be selectively opened and closed to regulate the flow of water out of the packers of the injection pipeline or into the packers of the production pipeline to control the rate of energy production of the invention. This may also permits the control of extraction of heat from the rock formation.

[0022] A volume of stimulated rock formation may be established along and between the plurality of horizontal injection and production pipeline elements so as to establish a reservoir of heat therein. The volume of stimulated rock formation may be sufficiently large that it can be, in essence, “tapped” at commercial rates of production at a competitive cost for working life of the installation. The nature and extent of stimulation of the rock formation may be accomplished to permit the consistent and effective use of the entire volume of stimulated rock during the lifetime (at least 25 years) of the system.

[0023] More specifically, the size, shape and configuration of stimulation sites in the rock formation permit the pressurized flow of water injected through the injection pipelines into the rock formation for the take up of energy into the water to convert all of the water to steam in the stimulation sites at a steady, predictable and high rate. The steam continues to take up energy as it is pressed through the rock formation to become a high enthalpy steam prior to being taken up in the production pipeline. The design of the present invention allows large amounts of energy to be delivered at consistent rates of production over a long period of time without depleting the heat source. The present invention allows for fully customizable and scalable designs of geothermal systems based on temperature of the rock formation, the type of rock in the rock formation and the number of years the system is to be operated.

BRIEF DESCRIPTION OF THE DRAWINGS

[0024] The present disclosure is illustrated by way of example, and not by way of limitation, in the figures of the accompanying drawings in which like references indicate similar elements. It should be noted that different references to “an” or “one” embodiment in this disclosure are not necessarily to the same embodiment, and such references mean at least one. [0025] FIG. 1 illustrates a schematic of a borehole in a supercritical system including a vertical borehole element and horizontal borehole element according to an embodiment of the present invention;

[0026] FIG. 2 illustrates a side view of a pipeline in the borehole element of FIG. 1, including optional cement and placement of packers, according to an embodiment of the present invention;

[0027] FIG. 3 illustrates a top view of a borehole relative to faults, fissures, cracks or other suitable weaknesses in rock formations;

[0028] FIG. 4 illustrates a top view of an injection pipeline placed between two production pipelines;

[0029] FIG. 5 illustrates a side end view of an injection pipeline placed between two production pipelines;

[0030] FIG. 6 illustrates a top view of a plurality of injection pipes and production pipes in a rock formation according to an embodiment of the present invention;

[0031] FIG. 7 illustrates a system according to an embodiment of the present invention including the flow of water and heat throughout;

[0032] FIG. 8A illustrates a cross-sectional view of one set of stimulation sites in the system relative to an injection pipeline and a pair of production pipelines, in which the pipelines are aligned;

[0033] FIG. 8B illustrates a cross-sectional view of one set of stimulation sites in the system relative to an injection pipeline and a pair of production pipelines, in which the pipelines are on different levels;

[0034] FIG. 9 illustrates stimulations extending between an injection pipe and a production pipe and flow through it;

[0035] FIG. 10 illustrates a side view of a packer and ports according to an embodiment of the present invention;

[0036] FIG. 11 illustrates a supercritical geothermal energy system according to an embodiment of the present invention; and

[0037] FIG. 12 is a graph representing the power output over time of a system according to an embodiment of the present invention. DETAILED DESCRIPTION OF THE INVENTION

[0038] The present disclosure relates to large scale, long term geothermal energy systems. In a small scale geothermal systems that may power, for example, a single home, neighborhood or business, the amount of energy produced is minute compared to the amount of energy stored in the Earth, even on a local level. If such systems utilize a geothermal system which operates by injecting water into a pipeline disposed in a borehole to heat to the water to power a Rankine engine to power a single house, the amount and rate of heat withdrawn from the Earth would be low and slow. The amount and rate would be so low and slow that the energy taken from the Earth does not significantly lower the temperature of the rock formation surrounding the pipeline enough to lower the efficiency of the system much. That is, the temperature of the rock formation may remain relatively stable. This stability does not exist in a large- scale system (one operating at, for example, about 50 MWe or more). This is because, when a large amount of water is injected into the Earth through pipelines, the temperature of the rock formation surrounding the pipeline may almost immediately lower, which reduces the efficiency of the geothermal system. In some instances, this may happen as quickly as one day.

[0039] Large scale, advanced geothermal systems differ from small scale systems in both design and function. A large scale system extracts a much larger amount of energy from the rock formation for a longer period of time. Because of the low thermal conductivity of rock, energy extracted from the rock formation is not quickly restored. Typically, a reservoir of accessible rock is stimulated for use, with the heat therein restored slowly over time. The present invention includes a system designed to create a sufficient reservoir of heat which is accessed in a manner to permit use of a single system for a period of 25 years or more. The present invention includes a system having wells including injection pipelines and production pipelines attached to a plant and/or production facility.

[0040] More specifically, the present invention provides a geothermal energy production facility designed to produce at least 50 MWe of electricity for 25 years or more. A working fluid, such as water, may be injected at a temperature of about 116 °F and withdrawn as high enthalpy steam at the return wellhead at a temperature of about 700 °F. The pressure at injection of the working fluid may range from 500 psia to 3,000 psia. The working fluid may be injected into each well at a rate of 800 to 3,000 gpm (gallons per minute). Steam pressure at the producer wellhead may range from 300 psi to 1,000 psi.

[0041] Various embodiments are described hereinafter. It should be noted that the specific embodiments are not intended as an exhaustive description or as a limitation to the broader aspects discussed herein. One aspect described in conjunction with a particular embodiment is not necessarily limited to that embodiment and can be practiced with any other embodiment(s).

[0042] As used herein, “about” will be understood by persons of ordinary skill in the art and will vary to some extent depending upon the context in which it is used. If there are uses of the term which are not clear to persons of ordinary skill in the art, given the context in which it is used, “about” will mean up to plus or minus 10% of the particular term.

[0043] The articles “a”, “an”, and “the” are used herein to refer to one or to more than one (i.e., to at least one) of the grammatical object of the article. By way of an example, “a pipeline” means one pipeline or more than one pipeline.

[0044] Recitation of ranges of values herein are merely intended to serve as a shorthand method of referring individually to each separate value falling within the range, unless otherwise indicated herein, and each separate value is incorporated into the specification as if it were individually recited herein. All methods described herein can be performed in any suitable order unless otherwise indicated herein or otherwise clearly contradicted by context.

[0045] The use of any and all examples, or exemplary language (e.g., “such as”) provided herein, is intended merely to illuminate certain materials and methods and does not pose a limitation on scope. No language in the specification should be construed as indicating any non-claimed element as essential to the practice of the disclosed materials and methods.

[0046] In an embodiment of the present invention, a geothermal energy system is provided. The geothermal energy system may include a working fluid including water or a well fluid; an injection pipeline, wherein the injection pipeline comprises a horizontal element and a vertical element; and a production pipeline, wherein the production pipeline comprises a horizontal element and a vertical element, and wherein the geothermal energy system is operable at temperatures of at least about 750°F. [0047] In some embodiments, the geothermal energy system may be placed in a rock formation. The rock formation may be at a temperature higher than about 750°F.

[0048] In some embodiments, the working fluid may be water. In some embodiments, the working fluid may be well fluid.

[0049] In some embodiments of the geothermal energy system, the injection pipeline may be configured to deliver the fluid to the rock formation.

[0050] In some embodiments of the system, the working fluid may be vaporized in the rock formation to form steam. In some embodiments, the production pipeline may be configured to collect the steam and deliver the steam to a plant.

[0051] In some embodiments of the system, about 100% of the working fluid may be vaporized into steam.

[0052] In some embodiments, the horizontal element of the injection pipeline and the production pipeline may include a sleeve. The sleeve may be a generally cylindrical device configured to be inserted into the borehole. The sleeve may be separated from other sleeves by a packer. In some embodiments, the sleeve may be a stimulation, flow control and/or fracking sleeve. The sleeve may be a multi-valve metal fracking sleeve. The sleeve may be used to control fluid flow to an underground region (rock formation) via opening a valve (e.g. a port of the sleeve) in a high-temperature downhole environment. In some embodiments, the working fluid may be pumped through a port on the sleeve of the injection pipeline. In some embodiments, the converted working fluid may be collected through a port on the sleeve of the production pipeline.

[0053] In some geothermal systems, one or more holes (e.g., wells, bores) are drilled into the Earth to a depth at which the temperature of the surroundings (e.g., surrounding rock formation) is sufficient to heat a working fluid.

[0054] Following the drilling of one well the well is stimulated through the sleeves that is segmented down the lateral utilizing the metal packers. The number of stimulations (e.g., sleeves) may vary (e.g., from every 30 feet (ft), 45 ft, 60 ft, or 90 ft) based upon the heat resource and lateral portion down its length. Well lengths may vary from about 3,000 ft to about 11,000 ft long.

[0055] In some embodiments, the vertical element of the production pipeline and injection pipeline may be drilled into a separate vertical borehole from the surface to a rock formation, wherein the rock formation may be at a depth at which the temperature is higher than 750°F. In some embodiments, the depth may be near the juncture of two tectonic plates. In some embodiments, the depth may be about 1,000 feet to about 30,000 feet. In some embodiments, the depth may be about 10 to about 12 miles.

[0056] In some embodiments of the geothermal energy system, a horizontal borehole for each of the injection and production pipeline may be attached at or near the bottom of the vertical borehole of each. In some embodiments, the horizontal borehole may extend about 5,000 feet to about 15,000 feet.

[0057] In some embodiments of the geothermal energy system, the pipelines in the vertical boreholes may be fully encased in cement. In some embodiments, the pipelines in the vertical boreholes may be partially encased in cement.

[0058] In some embodiments, the geothermal energy system may include two production pipelines for each injection pipeline. In some embodiments of the geothermal energy system, the production pipeline may be parallel to the injection pipeline. In some embodiments of the geothermal energy system, the production pipeline may taper from the injection pipeline, such that the production pipeline is about 10% further at one end than the other end.

[0059] In some embodiments of the geothermal energy system, the production pipeline may be about 750 to about 2,000 feet from the injection pipeline. In some embodiments, each of the two production pipelines may be placed about 750 to about 2,000 feet from the injection pipeline, such that the one of the two production pipelines are on either side of the injection pipeline.

[0060] In some embodiments of the system, a plurality of the injection pipelines may be included, wherein each injection pipeline may have the production pipeline on each side of the injection pipeline.

[0061] In some embodiments of the geothermal energy system, the injection pipeline and the production pipeline may be included according to the following formula:

When there is n injection pipelines, there is (n+1) production pipelines, where n is an integer from 1 to 100.

[0062] In some embodiments of the system, the plurality of the injection pipelines may be stacked above each other, or are placed side-by side in a rock formation. In some embodiments, the plurality of the injection pipelines may be spaced about 50 feet to about 200 feet lower than the production pipeline. [0063] In some embodiments of the system, the horizontal element of the injection pipeline includes a plurality of packers. In some embodiments of the system, the plurality of packers may be spaced evenly across the horizontal element. In some embodiments of the system, the plurality of packers may be spaced about 25 feet to about 90 feet.

[0064] In some embodiments, the horizontal element of the production pipeline may include a plurality of packers. In some embodiments, the plurality of packers on the production pipeline and the plurality of packers on the injection pipeline may align.

[0065] In some embodiments of the system, wherein the plurality of packers may include a plurality of ports.

[0066] In some embodiments, the geothermal energy system may be a heat exchanger.

[0067] In some embodiments of the geothermal energy system, the steam may be delivered to a heat exchanger above a surface in the plant. In some embodiments, the heat exchanger above the surface may be connected to a turbine in the plant. In some embodiments of the system, the ratio of the horizontal element of the production pipeline to the horizontal element of the injection pipeline is 1:2 to 2:1, 1:1.8 to 1.8:1, 1:1.6 to 1.6:1, 1:1.4 to 1.4:1, 1:1.2 to 1.2:1, or 1:1.

[0068] In some embodiments of the geothermal energy system, the system may produce about 40 mega watts electrical (“MWe’j, about 45 MWe, about 50 MWe, about 55 MWe, about 60 MWe, about 65 MWe, about 70 MWe, about 75 MWe, about 80 MWe, about 85 MWe, or about 90 MWe of power.

[0069] In another embodiment of the present invention, a method for collecting energy from the earth is provided. The method includes injecting a working fluid into an injection pipeline, releasing the working fluid into a rock formation under the Earth’s surface through the injection pipeline, wherein the working fluid may be converted to steam, collecting the steam through a production pipeline and delivering the steam to a system above the rock formation. The injection pipeline and the production pipeline may be in a well.

[0070] In some embodiments, the rock formation may be at a temperature of at least about 750°F. In some embodiments, the injection pipeline may include a plurality of packers. The plurality of packers may include a plurality of ports. [0071] In some embodiments, the production pipeline may include a plurality of packers.

[0072] In some embodiments, the working fluid may be released into the rock formation at a pressure of about 6,000 psi to about 8,000 psi.

[0073] In some embodiments, the injection of the working fluid may be performed by pumping the working fluid. In some embodiments, the pumping may be performed at a rate of about 300 to about 3,000 gallons per well per minute.

[0074] In some embodiments, the system may be a plant. In some embodiments, the plant may include a heat exchanger and a turbine.

[0075] In some embodiments, the steam may be delivered to the plant at a power of 50 MWe to about 70 MWe.

[0076] Referring to the figures, in FIG. 1, a schematic of a borehole suitable for use in the system is illustrated. On the Earth’s surface 101, a part of an energy production system 102 is constructed in working proximity to a borehole 110, wherein the borehole 110 may include either an injection pipeline or production pipeline for the invention. If borehole 110 is drilled for an injection pipeline, the part of the energy production system 102 installed may be pumping equipment. The pumping equipment may inject water into the rock formation 111. If borehole 110 is drilled for a production pipeline, the part of the energy production system 102 installed may be generator equipment. The generator equipment may convert high temperature steam into electricity.

[0077] This is better described in FIG. 11, which illustrates a schematic of a large scale supercritical energy system 1100 in accordance with an embodiment of the present disclosure. As can be seen in FIG. 11, the system 1100 includes a supercritical heat exchanger 1105 in a rock formation 111. The rock formation 111 may include any rock as described herein, but is not limited to, igneous rock, such as granite, basalt, or other hot, dry rock that is at supercritical temperatures. The supercritical heat exchanger 1105 includes an injection pipeline 1110 and production pipelines 1115a and 1115b. It should be understood that the supercritical heat exchanger 1105 is not limited to one injection pipeline and two production pipelines. As will be described herein, there may be multiple injection pipelines throughout the heat exchanger 1105. In some embodiments, there may be two production pipelines for every injection pipeline included. In another embodiment, there may be one production pipeline for each injection pipeline included. In some embodiments, the injection pipeline 1110 and production pipelines 1115a and 1115b are inserted into the rock formation 111 through a well.

[0078] As can be seen in FIG. 11, a fluid is provided to the supercritical heat exchanger 1105 through the injection pipeline 1110. The fluid enters the system through the injection wellhead 1120, which is above the surface. The fluid may be water, a well fluid, or a working fluid as understood by one of skill in the art. When the fluid enters below the earth’s surface and into the heat exchanger, it is heated because of the high temperatures of the rock formation 111. The temperatures of the rock formation 111 may be about 500°F, about 550°F, about 600°F, about 650°F, about 700°F, about 750°F, about 800°F, about 850°F, about 900°F, about 950°F, or higher. As the fluid is heated within the supercritical heat exchanger 1105, it becomes a vapor and travels throughout the rock formation towards the production pipelines 1115a,b. The production pipelines 1115a,b collect the vapor and deliver the vapor above the surface through production wellheads 1125a,b to a surface heat exchanger 1130.

[0079] The surface heat exchanger 1130 will collect the vapor from the geothermal system. The vapor will either be heated and delivered to a turbine 1135, or be cooled and delivered back to the injection pipeline 1110. When the vapor is heated to the turbine 1135, it is able to power the turbine and supply energy to the generator 1140. The generator 1140 is then able to power large scale power distributors 1145. The vapor may also be cooled while in the turbine 1135 and delivered to a condenser 1150. The condenser 1150 sends the vapor/fluid to a wet cooling tower 1155 through a condensate pump 1160. The condenser 1150 receives the cooled fluid from the wet cooling tower 1155 and as able to send the fluid back to the surface heat exchanger 1130. Thus, a continuous flow of fluid is able to be achieved.

[0080] Referring back to FIG. 1, borehole 110 may include a vertical element 103 drilled down into the Earth’s surface to a depth at which the rock formation 111 reaches a desired temperature, for example about 750 °F to about 850 °F. In some embodiments, the temperature of the rock formation may be at least about 500°F, at least about 550°F, at least about 600°F, at least about 650°F, at least about 700°F, at least about 750°F, at least about 800°F, or at least about 850°F. Once the desired temperature range is encountered in the rock formation 111 , a horizontal element 104 of the borehole 110 may be drilled. Horizontal element 104 may be approximately horizontal. That is, the horizontal element 104 may not be exactly straight through the rock formation 111. Horizontal element 104 may also be disposed entirely in the desired rock formation 111. Horizontal element 104 may be drilled to a length suitable to meet the needs of the invention described further herein. The present invention entails the use of horizontal elements 104 of about 7,000 feet to about 11,000 feet. In some embodiments, horizontal elements 104 may be about 7,000 feet, about 7,500 feet, about 8,000 feet, about 8,500 feet, about 9,000 feet, about 9,500 feet, about 10,000 feet, about 10,500 feet, or about 11,000 feet.

[0081] In some embodiments, the geothermal energy system of the present invention may be installed at a location in which the high temperature rock formation 111 may be close to the Earth’s surface, such in regions in which tectonic plates meet. For example, the west coast of the United States may provide many suitable locations. In another example, other countries in the world may provide suitable locations for installations. These locations may reduce the amount of vertical drilling, which may help to control costs.

[0082] Rock formations 111 having temperatures at or above 700 °F may be used to create a high enthalpy supercritical steam. For example in rock formation 111, when the temperature is above 700 °F, water may be flash heated to steam when subjected to such high temperatures even under the pressures used in the present disclosure. As understood herein, “high enthalpy” may refer to a value of at least about 1200 btu/lb, at least about 1300 btu/lbm, at least about 1400 btu/lbm, or higher.

[0083] Referring now to FIG. 2, a pipeline 201 may be disposed in each of vertical element 103 and horizontal element 104 of borehole 110. Pipeline 201 includes a vertical pipeline element 210 and a horizontal pipeline element 211. In some embodiments, at least a portion of pipeline 201 may be encased in the borehole 110 using a suitable high temperature encaser 205. For example, the high temperature encaser may be as described as in International Application No. PCT/US22/452357. Depending on the location in the borehole 110 where encaser 205 is installed, encaser 205 may have heat conductive, heat insulative or other useful properties. Encaser 205 may have multiple useful properties. For example, when the temperature of the rock formation is below about 650 °F, a suitable insulative or conductive cement may be used. In another example, when temperatures are above about 650 °F but below about 850 °F, a suitable resin may be used. In the alternative, an encaser may be a non-elastomeric packer 206 as is described in more detail herein. Multiple types of encasers 205 may be used in a single borehole depending on the properties (insulative, conductive or otherwise) needed in a location along the pipeline 201. Encasers 205 used in the invention may be those currently known in the industry or may be specifically developed for use in high temperature geothermal systems.

[0084] Referring to FIG. 3, a top view of a location for installing a borehole 110 in a rock formation 111 according to an embodiment is illustrated. Before installing a borehole, an analysis is performed on the rock formation 111 to identify optimal positioning of the pipeline relative to the rock formation 111. The analysis may include identifying the rock stress directions of the rock formation and/or the temperature of the rock formation. The analysis may also include identifying the type of rock in the rock formation. In some embodiments, geothermal systems may operate at above about 450 °F, where the rock formations 111 may commonly be granite or other igneous rock. To pump a working fluid, such as water through a rock formation 111 made of granite, the rock formation 111 may be stimulated using water, heat, thermal-hydraulic stimulation, fluid containing a proppant or other suitable method. Thermal-hydraulic stimulation may include, but is not limited to, fracking or fracturing. Thermal -hydraulic stimulation provides pathways for fluid (e.g., from a first well to enter a second well) and allows fluids, which may be in the formation naturally or which may be injected into the formation, to circulate to allow extracted heat to be replaced more quickly by increasing directly the flow of heat through the rock formation. Fracking may be performed by the perforation of a pipeline. Then a fracking liquid is pumped into the pipeline under pressure to expand and fracture the surrounding rocks. Fracking is usually done in sections along the pipeline (e.g., starting with the toe). Sections of the pipeline may be isolated by frac sleeves that form a seal against the inner wall of a pipe. Fracking sleeves may be separated from other fracking sleeves or the well bore by packers. A frac sleeve is a generally cylindrical device having a length and diameter suitable to be inserted into a lined geothermal pipeline. The frac sleeve is delivered down the vertical element of the pipeline to the toe (e.g., end) of the pipeline. Fracking is typically started from the toe of the pipeline. A frac sleeve includes one or more ports through which fracking fluid may be pumped. Fracking ports are selected for use by opening certain ports and by closing certain ports. This may be accomplished through the use of fracking balls and slidable collets.

[0085] Granite is an igneous rock commonly comprising natural fissures and cracks. Likewise, rock formations 111 contain natural stresses and strains. Stresses and strains in the rock formation 111 can be exploited through stimulation to create additional fissures and gaps to create passages for water and steam pumped through the system. In the present invention, to optimize the flow of working fluid, such as water or a well fluid, pumped through the rock formation, an analysis of the rock formation 111 may be performed. The analysis may include determining the optimal position of the horizontal element 104 of the pipeline of FIG. 2 to identify a principal rock stress direction 301 in the rock formation 111. There may be more than one principal rock stress direction 301 in the rock formation. For example, there may be 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, or more principal rock stress directions 301 in the rock formation 111 for the geothermal system of the present invention. Thus, the amount of stimulation to the rock formation is kept to a minimum to reduce the chances of, for example, seismic issues (e.g., induced earthquakes) from occurring.

[0086] Stimulation may be performed at approximately right angles to the pipeline. In some embodiments, stimulation may be performed to take advantage of existing fissures, stresses and strains in the rock formation 111. Thus, pipeline 201 FIG. 2 may be positioned at an approximately right angle to the majority of the identified principal rock stress directions 301 in the rock formation 111.

[0087] Referring now to FIG. 4, in an embodiment of the invention, an injection pipeline 401 may be disposed in a rock formation 111 in a position relative to the principal rock stress directions 301 in the rock formation 111 as described above in reference to FIG. 3. The horizontal pipeline element 211a of injection pipeline 401 includes an injection wellhead 410 at the surface 101 and an injection end point 415 underground. Similarly, each horizontal pipeline element 211b of each production pipeline 402 has a production wellhead 411 at the surface 101 and a production end point 416 underground. In some embodiments, the horizontal element 211a of the injection pipeline and the horizontal element 21 lb of the production pipeline may be parallel to one another. In some embodiments the horizontal element 211b of the production pipeline may taper such that the production end point 416 may be spaced further away from the injection end point 415 than the initial placement at the surface. That is, the production end point 416 may be about 5%, about 10%, about 15%, about 20%, about 25%, about 30%, about 35%, about 45%, or about 50% further than from where the production wellhead 411 is placed. In FIG. 5, a side end view of an injection pipeline 401 placed between two production pipelines 402 is illustrated. In some embodiments, the injection pipeline 401 may be disposed deeper in the rock formation than each of the production pipelines 402. In some embodiments, the injection pipeline 401 may be disposed on the same level in the rock formation with the production pipelines 402.

[0088] The geothermal energy system described herein may include a plurality of injection pipelines 401 and a plurality of production pipelines 402. In some embodiments, the pipelines may be laid out so that there is a production pipeline 402 on each side of the injection pipeline 401, as is shown in FIG. 5. The geothermal system of the present invention is not limited to the embodiment illustrated in FIG. 5, but may include a plurality of pipelines. For example, FIG. 6 depicts a field of five injection wells/pipelines 40 lo-c and six production wells/pipelines 402o-/'in the rock formation 111. In some embodiments, each injection pipeline 401 may be associated with two production pipelines 402. In another embodiment, a field may include at least one more production well than the number of injection wells.

[0089] In a non-limiting embodiment, the field of FIG. 6 will be described as a representative production field. FIG. 2 may also be referred to so that the dimensions of the system are described herein. In the geothermal system, each horizontal pipeline element 211, for either an injection well or a production well, is about 5,000 to about 15,000 feet in length. In some embodiments, the horizontal pipeline element 211 may be about 5,000 to about 15,000 feet, about 5,500 to about 14,500 feet, about 6,000 to about 14,000 feet, about 6,500 to about 13,500 feet, about 7,000 to about 13,000 feet, about 7,500 to about 12,500 feet, about 8,000 to about 12,000 feet, about 8,500 to about 11,500 feet, about 9,000 to about 11,000 feet, or about 9,500 to about 10,500 feet. In one embodiment, the horizonal pipeline element is about 11,000 feet in length. Each production pipeline 402 may be spaced from about 750 feet to about 2,000 feet from each associated injection pipeline 401. In some embodiments, each production pipeline may be spaced from about 750 feet to about 2,000 feet, about 800 feet to about 1,950 feet, about 850 feet to about 1,900 feet, about 900 feet to about 1,850 feet, about 950 feet to about 1,800 feet, about 1,000 to about 1,750 feet, about 1,050 to about 1,700 feet, about 1,100 to about 1,650 feet, about 1,150 to about 1,600 feet, about 1,200 to about 1,550 feet, about 1,250 to about 1,500 feet, or about 1,300 to about 1,450 feet, from each associated injection pipeline. In some embodiments, the production pipeline may be spaced about 750 feet, about 800 feet, about 850 feet, about 900 feet, about 950 feet, about 1,000 feet, about 1,050 feet, about 1,100 feet, about 1,150 feet, about 1,200 feet, about 1,250 feet, about 1,300 feet, about 1,350 feet, about 1,400 feet, about 1,450 feet, about 1,500 feet, about 1,550 feet, about 1,600 feet, about 1,650 feet, about 1,700 feet, about 1,750 feet, about 1,800 feet, about 1,850 feet, about 1,900, about 1,950 feet, or about 2,000 feet from the injection pipeline. In one example of FIG. 6, if the spacing of the production pipeline is about 1,500 feet between each injection pipeline 401 a-e and each production pipeline 402 a-f. a system including 5 injection pipelines 401 a-e and 6 production pipelines 402 a -/is about 15,000 feet wide.

[0090] Referring now to FIG. 7, a partial field 700 having an injection pipeline 701 and 2 production pipelines 702 is shown. As can be seen in FIG. 7, an injection pipeline 701 is included in the field 700 having a vertical element 703 and a horizontal element 704. Two production pipelines 702 are provided on either side of the injection pipeline 701. The production pipelines 702 also have a vertical element 703 and a horizontal element 704. The field 700 is disposed within a rock formation 111. The rock formation 111 may be one of granite, basalt, or other hot, dry rock suitable for geothermal energy production and stimulation. The horizontal elements 704 of the injection pipeline 701 and production pipeline 704 are about 5,000 feet to about 15,000 feet in length. In some embodiments, the horizontal elements are about 5,000 feet to about 15,000 feet, about 5,500 feet to about 14,500 feet, about 6,000 feet to about 14,000 feet, about 6,500 feet to about 13,500 feet, about 7,000 feet to about 13,000 feet, about 7,500 feet to about 12,500 feet, about 8,000 feet to about 12,000 feet, about 8,500 feet to about 11,500 feet, about 9,000 feet to about 11,000 feet, or about 9,500 feet to about 10,500 feet in length. Along the length of the horizontal elements 704, a plurality of stimulation sites 710 are present. The stimulation sites 710 may be spaced about 30 feet, about 45 feet, about 60 feet, about 75 feet, or about 90 feet from each other. The stimulation sites 710 may extend vertically about 30 feet to about 600 feet. In some embodiments, the stimulation sites may extend vertically about 30 feet to about 600 feet, about 40 feet to about 675 feet, about 50 feet to about 650 feet, about 60 feet to about 625 feet, about 70 feet to about 600 feet, about 80 feet to about 575 feet, about 90 feet to about 550 feet, about 100 feet to about 525 feet, about 110 feet to about 500 feet, about 120 feet to about 475 feet, about 130 feet to about 450 feet, about 140 feet to about 425 feet, about 150 feet to about 400 feet, about 160 feet to about 375 feet, about 170 feet to about 350 feet, about 180 feet to about 325 feet, about 190 feet to about 300 feet, about 200 feet to about 275 feet, or about 210 feet to about 250 feet. In some embodiments, each stimulation site may extend across the width of the entire field 700 of pipelines 701 and 702. In some embodiments, the stimulation site may be a single, continuous stimulation site zone across all of the pipelines. In another embodiment, the stimulation site 710may be created from and around each injection and production pipeline individually. For example, there may be a stimulation site zone 710 around injection pipeline 701, and/or a stimulation site zone 710 around production pipeline 702.

[0091] FIG. 8A depicts a cross-section of a zonal representation of a single set of stimulation sites 710 as illustrated in the field 700 of FIG. 7. In FIG. 8A, a stimulation site 710 from FIG. 7 is shown to include a plurality of elliptical stimulation zones 803 created around each production pipeline 802 and injection pipeline 801. Each stimulation zone 803 may be accessed using a packer (not shown) disposed in the relevant location in each pipeline 801 and 802. The packer (not shown) may be made of any material as described above, such as a non-elastomeric packer as described in FIG. 2. In some embodiments, a stimulation zone 803 may partially overlap an adjacent stimulation zone 803 of the pipeline 801 or 802 next closest to it. For clarity, a stimulation zone 803 of a desired size, shape, volume of gaps and detail is created around each injection pipeline 801 or production pipeline 802. A plurality of such overlapping stimulation zones 803 may be created around a plurality of pipelines 801 or 802 to form a single stimulation site. As can be seen in FIG. 8 A, the injection pipeline 801 and production pipelines 802 are along the same plane of the horizontal axis X.

[0092] FIG. 8A further shows a vertical axis, Y, to represent the directions vertically above and below a representative pipeline 801 or 802. A horizontal axis, X, is also shown in FIG. 8A to represent the direction across the width of the pipeline field. In some embodiments, the stimulation zone may be created using techniques and equipment known in the geothermal, oil and/or gas industries. The stimulation zone 803 may have an elliptical shape. The shape of the stimulation zone 803 may be created to be symmetrical on each side of the pipeline 801 or 802. The stimulation zone around each pipeline may extend horizontally across about 10%, about 20%, about 30%, about 40%, about 50%, or about 60% of the space between the injection pipeline 801 and production pipeline 802. For example, if there is about 1,500 feet of space between the injection pipeline 801 and the production pipeline 802, the stimulation around each pipeline may extend about 750 feet along each direction of the horizontal axis X. The stimulation zone 803 around each pipeline 801 or 802 may extend about 15 feet to about 300 feet in each direction along the vertical axis Y. In some embodiments, the stimulation zone 803 may extend about 15 feet to about 300 feet, about 25 feet to about 275 feet, about 35 feet to about 250 feet, about 45 feet to about 225 feet, about 55 feet to about 200 feet, about 65 feet to about 175 feet, about 75 feet to about 150 feet, or about 100 feet to about 125 along the vertical axis Y.

[0093] In FIG. 8B, an alternate embodiment of the stimulation sites discussed above is illustrated. As can be seen in FIG. 8B, the injection pipeline 801 may be disposed in rock formation 111 closer to the surface than the production pipelines 802. In such an alignment, the working fluid (e.g., water or well fluid) may have a slightly longer path to travel from injection pipeline 801 to production pipeline 802. Thus, additional energy absorption by the working fluid may occur prior to entry into the production pipeline 802 because the working fluid may be in contact with the rock formation for a longer time period before reaching the production pipeline. For example, additional energy absorption may increase through the stimulation zone or flashing area by increasing the injection rate of the working fluid. Thus, if additional energy absorption is desired, then the working fluid may be injected at a higher rate of about 400 gpm to about 2500 gpm, about 450 gpm to about 2450 gpm, about 500 gpm to about 2400 gpm, about 550 gpm to about 2350 gpm, about 600 gpm to about 2300 gpm, about 650 gpm to about 2250 gpm, about 700 gpm to about 2200 gpm, about 750 gpm to about 2150 gpm, about 800 gpm to about 2100 gpm, about 850 gpm to about 2050 gpm, about 900 gpm to about 2000 gpm, about 950 gpm to about 1950 gpm, about 1000 gpm to about 1900 gpm, about 1050 gpm to about 1850 gpm, about 1100 gpm to about 1800 gpm, about 1150 gpm to about 1750 gpm, about 1200 gpm to about 1700 gpm, about 1250 gpm to about 1650 gpm, or about 1300 gpm to about 1600 gpm. It is understood that the flashing area as described herein refers to an area where the working fluid is flashed and/or converted into steam. [0094] Referring to FIG. 9, an illustration of the fissures during the heating process is provided. In an embodiment of the present disclosure, fissures and/or stimulation sites may extend from each injection pipeline 901 and each production pipeline 902, such that the rock formation 111 is thermally and/or hydraulically stimulated. During thermal and/or hydraulic stimulation, cold water may be pumped into the rock formation to be stimulated. As understood herein, “cold water” refers to water at a temperature of about 60°F to about 220°F. The rock formation is that as described herein. That is, the rock formation may have a temperature of at least about 500°F, at least about 550°F, at least about 600°F, at least about 650°F, at least about 700°F, at least about 750°F, or at least about 800°F. The introduction of cold water into the rock formation having such temperatures, such as at least about 750°F or more, may place portions of the rock formation 111 under local stress. The local stress may be caused by contraction of parts of the rock that begin to cool when contacted with the cold water. At the same time, when the water is pumped into the rock formation creates pressure, which may cause parts of the rock formation 111 to thermally and mechanically fail and then separate. Through this process, a network of stimulation zones 910 from each injection pipeline 901 toward each production pipeline 902 and equally from each production pipeline 902 to each injection pipeline 901 may form in the rock formation 111.

[0095] The stimulation sites/fissures that may be created in the rock formation 111 in FIG. 9 may take the form of long, narrow expansions or openings in the rock formation 111. Each fissure may create an opening from about 0.005 mm to about 8 mm in width. In some embodiments, the opening may be about 0.005 mm to about 8 mm, about 0.01 mm to about 7.5 mm, about 0.05 mm to about 7 mm, about 0. 1 mm to about 6 mm, about 0.5 mm to about 5 mm, about 1 mm to about 4 mm, or about 2 mm to about 3 mm. Thus, the fissures may have a narrow gap in which the ratio of the volume to the surface area is low. In some embodiments a ratio of the volume of working fluid injected per day relative to the surface area in the fractures may be about 1:9500 to about 1:3500, about 1:9000 to about 1 :4000, about 1 :8500 to about 1 :4500, about 1 :8000 to about 1:5000, about 1 :7500 to about 1 :5500, or about 1:7000 to about 1 :6000. The total volume of the fissures may be about 1%, about 2%, about 3%, about 4%, about 5%, about 6%, about 7%, about 8%, about 9%, or about 10% of the volume of the rock formation 111. [0096] As can be seen in FIG. 9, the working fluid, such as water or a well fluid, is pumped into the injection pipeline 901. The working fluid is then released into the rock formation through a plurality of packers (not shown) that are along the horizontal element of the injection pipeline 901. As the working fluid is exposed to the rock formation 111, it travels across the rock formation toward the production pipeline 902. As it travels across, the working fluid is heated and is flashed/vaporized so that it is converted into a steam. Thus, when the working fluid reaches the production pipeline 902, the production pipeline 902 is able to capture the vapor. The vapor may enter the production pipeline 902 through a plurality of packers (not shown) that are also along the horizontal element. The vapor is then able to travel through the production pipeline 902 up to the plant on the surface to be used as an energy source. [0097] In FIG. 10, a packer according to an embodiment of the present invention is shown. The packer 1001 may be made of a non-elastomeric material. In one embodiment, the packer 1001 may be made without elastomeric elements. It has been found that elastomeric elements may not be able to withstand temperatures of about 700°F or higher. A plurality of packers 1001 may be provided on each of injection pipeline and production pipeline of the system of the present application. The packers 1001 may be spaced about 25 feet, about 35 feet, about 50 feet, about 60 feet, about 75 feet, or about 90 feet apart along the length of the horizontal element of the pipelines. The spacing may vary depending on the rock formation that the system is being used in. Each packer 1001 includes a plurality of ports 1005 a-c. The ports 1005 a-c may permit either the outflow of water pumped in through the injection pipeline or the take up of high enthalpy steam/vapor to be taken up through the production pipeline. The ports 1005 a-c may be opened or closed to allow or prevent flow therethrough. In another embodiment of the packer, the ports may be spaced so that they are spaced circumferentially around the packer.

[0098] By opening and/or closing the ports on the packers, the system may control the extraction of heat from different sections of the rock formation 111. Thus, if one area of the rock formation is cooling at a quicker rate than another area, a port 1005 may be either fully or partially closed to slow the flow of water into that area. Thus, this allows the other regions of the rock formation that are hotter to be utilized for heat extraction. Being able to manage the rock formation in this manner may allow for the life expectancy of the rock formation to be extended. [0099] An embodiment of the system will now be described but should be understood as not being limited to. In the system, a horizontal element of the injection pipeline and production pipeline has a length of at most about 11,000 feet. The vertical element of the injection pipeline and production pipeline is extended into the rock formation until it reaches the desired depth. For example, the desired depth may be about 300 feet to about 30,000 feet. After the pipelines are set in the rock formation, a working fluid may be pumped through the system. The working fluid may be injected into the injection pipeline using an injection pump. The working fluid may be water, or a well fluid as understood as by one of skill in the art. The working fluid may be pumped at a rate of about 300 to about 3,000 gallons per minute per well. In some embodiments, the working fluid may be pumped at about 300 to about 3,000, about 400 to about 2,900, about 500 to about 2,800, about 600 to about 2,700, about 700 to about 2,600, about 800 to about 2,500, about 900 to about 2,400, about 1,000 to about 2,300, about 1,100 to about 2,200, about 1,200 to about 2,100, about 1,300 to about 2,000, about 1,400 to about 1,900, or about 1,500 to about 1,800 gallons per minute per well.

[00100] The working fluid may be pumped under a pressure of about 10 psi to about 8,000 psi. In some embodiments, the pressure may be about 10 psi to about 8,000 psi, about 50 psi to about 7,900 psi, about 100 psi to about 7,800 psi, about 200 psi to about 7,700 psi, about 500 psi to about 7,600 psi, about 1,000 psi to about 7,500 psi, about 1,500 psi to about 7,400 psi, about 2,000 psi to about 7,300 psi, about 2,500 psi to about 7,200 psi, about 3,000 psi to about 7,000 psi, about 3,500 psi to about 6,750 psi, about 4,000 psi to about 6,500 psi, about 4,500 psi to about 6,000 psi, or about 5,000 psi to about 5,500 psi. As the working fluid is pumped through the injection pipeline, it may be released into the rock formation through the plurality of ports on the horizontal element of the injection pipeline. The working fluid may be pumped through fissures through the rock formation. As the working fluid flows through the rock formation, it may be in contact with a surface of the rock which heats the working fluid. In some embodiments, the working fluid may be in conductive contact with a surface of the rock. When the fissure is narrower, the working fluid may be heated at a quicker rate. In some embodiments, when the working fluid flows through a narrow fissure and is under pressure, the working fluid may flow laminarly. It has been found that the turbulence and vorticity may be minimized in the system. It has also been found that the convection aids in heating the working fluid.

[00101] As described herein, the temperature of the rock formation may be at least about 500°F, at least about 550°F, at least about 600°F, at least about 650°F, at least about 700°F, at least about 750°F, at least about 800°F, at least about 850°F, at least about 900°F, or at least about 950°F. At such high temperatures, the working fluid may be vaporized to transform into steam. The steam may then travel between the rock formation to the production pipeline. As the steam travels, it may continue to take up heat as it contacts the surface of the rock. The length at which the steam may travel about 1,500 to about 4,000 feet, about 1,600 to about 3,900 feet, about 1,700 to about 3,800 feet, about 1,800 to about 3,700 feet, about 1,900 to about 3,600 feet, about 2,000 to about 3,500 feet, about 2,100 to about 3,400 feet, about 2,200 to about 3,300 feet, about 2,300 to about 3,200 feet, about 2,400 to about 3,100 feet, about 2,500 to about 3,000 feet, or about 2,600 to about 2,900 feet. In some embodiments, 100% of the working fluid injected into the system may be converted into steam. In another embodiment, about 100%, about 99%, about 95%, about 92%, about 90%, about 88%, about 85% about 80%, or about 75% of the working fluid injected into the system may be converted into the steam. The steam that is collected in the production pipeline is then sent to the plant above the surface of the earth to be used as an energy source.

EXAMPLES

[00102] Specific embodiments of the invention will now be demonstrated by reference to the following examples. It should be understood that these examples are disclosed solely by way of illustrating the invention and should not be taken in any way to limit the scope of the present invention.

[00103] Simulations of the power production of the system were performed to predict the production rate of the system over the course of 25 years.

[00104] All of the following simulations were conducted, where the vertical element of the system was fully encased from the surface to the bottom of the well. Each stimulation sleeve and packer on the horizontal element was spaced 30 feet apart. A total of six simulations were conducted (Examples 1-6 presented below), where three had a horizontal element of 9,000 feet and different injection rates, and the other three had a horizontal element of 11,000 feet and different injection rates.

Results of Example 1

[00105] Example 1 had a length of the horizontal element of 9,000 feet and an injection rate of 1,300 gpm. The results of the experiment are presented in Table 1 below.

Table 1 - Results of Example 1

Results of Example 2

[00106] Example 2 had a length of the horizontal element of 9,000 feet and an injection rate of 1,500 gpm. The results of the experiment are presented in Table 2 below.

Table 2 - Results of Example 2

Results of Example 3

[00107] Example 3 had a length of the horizontal element of 9,000 feet and an injection rate of 1,700 gpm. The results of the experiment are presented in Table 3 below.

Table 3 - Results of Example 3

Results of Example 4

[00108] Example 4 had a length of the horizontal element of 11,000 feet and an injection rate of 1,300 gpm. The results of the experiment are presented in Table 4 below.

Table 4 - Results of Example 4

Results of Example 5

[00109] Example 5 had a length of the horizontal element of 11,000 feet and an injection rate of 1,500 gpm. The results of the experiment are presented in Table 5 below. Table 5 - Results of Example 5

Results of Example 6

[00110] Example 6 had a length of the horizontal element of 11,000 feet and an injection rate of 1,700 gpm. The results of the experiment are presented in Table 6 below.

Table 6 - Results of Example 6

[00111] Another embodiment of the energy system was tested to predict the production rate and enthalpy of the system over 25 years. In the second embodiment, each packer on the horizontal element was spaced 60 feet apart. A total of three experiments were conducted, where two had a horizontal element of 9,000 feet and different injection rates, and the other had a horizontal element of 11,000 feet.

Results of Example 7

[00112] Example 7 had a length of the horizontal element of 9,000 feet and an injection rate of 1,370 gpm. The results of the experiment are presented in Table 7 below. Table 7 - Results of Example 7

Results of Example 8

[00113] Example 8 had a length of the horizontal element of 9,000 feet and an injection rate of 1,400 gpm. The results of the experiment are presented in Table 8 below.

Table 8 - Results of Example 8

Results of Example 9

[00114] Example 9 had a length of the horizontal element of 11,000 feet and an injection rate of 1,400 gpm. The results of the experiment are presented in Table 9 below. Table 9 - Results of Example 9

Power Simulation

[00115] A simulation was also conducted to illustrate the power production of one embodiment of the system over time while injecting a well power fluid at various rates and at production pressure of 500 psi. The length at which the well fluid travels was also varied.

[00116] The conditions of the simulation are listed below in Table 10 and the results of the stimulation are presented in FIG. 12.

Table 10 - Conditions of Power Simulation

[00117] The present invention has been described with reference to specific exemplary embodiments thereof. The specification and drawings are, accordingly, to be regarded in an illustrative rather than a restrictive sense. Various modifications of the invention in addition to those shown and described herein will become apparent to those skilled in the art and are intended to fall within the scope of the appended claims.

[00118] For simplicity of explanation, the embodiments of the methods of this disclosure are depicted and described as a series of acts. However, acts in accordance with this disclosure can occur in various orders and/or concurrently, and with other acts not presented and described herein. Furthermore, not all illustrated acts may be required to implement the methods in accordance with the disclosed subject matter. In addition, those skilled in the art will understand and appreciate that the methods could alternatively be represented as a series of interrelated states via a state diagram or events.

Claims

WHAT IS CLAIMED IS:

1. A geothermal energy system comprising: a fluid, wherein the fluid comprises water or a working fluid; an injection pipeline, wherein the injection pipeline comprises a horizontal element and a vertical element; and a production pipeline, wherein the production pipeline comprises a horizontal element and a vertical element, and wherein the geothermal energy system is operable at temperatures of at least about 750°F.

2. The geothermal energy system of claim 1, wherein the system is placed in a rock formation.

3. The geothermal energy system of claim 2, wherein the rock formation is at a temperature higher than 750°F.

4. The geothermal energy system of claim 1, wherein the fluid is water.

5. The geothermal energy system of any of the preceding claims, wherein the injection pipeline is configured to deliver the fluid to the rock formation.

6. The geothermal energy system of claim 5, wherein the fluid is vaporized in the rock formation to form steam.

7. The geothermal energy system of claim 6, wherein the production pipeline is configured to collect the steam and deliver the steam to a plant.

8. The geothermal energy system of claim 6, wherein 100% of the fluid is vaporized into steam.

9. The geothermal energy system of claim 1, wherein the vertical element of the production pipeline and injection pipeline are drilled into a separate vertical borehole

32 from the surface to a rock formation, wherein the rock formation is at a depth at which the temperature is higher than 750°F.

10. The geothermal energy system of claim 9, wherein the depth is near the juncture of two tectonic plates.

11. The geothermal energy system of claim 9, wherein the depth is about 1,000 feet to about 30,000 feet.

12. The geothermal energy system of claim 9, wherein the depth is about 10 to about 12 miles.

13. The geothermal energy system of claim 9, wherein a horizontal borehole for each of the injection and production pipeline is attached at or near the bottom of the vertical borehole of each.

14. The geothermal energy system of claim 13, wherein the horizontal borehole extends at least about 5,000 feet to about 15,000 feet.

15. The geothermal energy system of claim 13, wherein the pipelines in the vertical boreholes are fully encased in cement.

16. The geothermal energy system of claim 13, wherein the pipelines in the vertical boreholes are partially encased in cement.

17. The geothermal energy system of claim 1, comprising two production pipelines for each injection pipeline.

18. The geothermal energy system of claim 1, wherein the production pipeline is parallel to the injection pipeline.

33

19. The geothermal energy system of claim 1, wherein the production pipeline tapers from the injection pipeline, such that the production pipeline is about 10% further at one end than the other end.

20. The geothermal energy system of claim 1, wherein the production pipeline is about 750 to about 2,000 feet from the injection pipeline.

21. The geothermal energy system of claim 17, wherein each of the two production pipelines are placed about 750 to about 2,000 feet from the injection pipeline, such that the one of the two production pipelines are on either side of the injection pipeline.

22. The geothermal energy system of claim 1, wherein a plurality of the injection pipelines are included, wherein each injection pipeline has the production pipeline on each side of the injection pipeline.

23. The geothermal energy system of claim 1, where the injection pipeline and the production pipeline are included according to the following formula:

When there is n injection pipelines, there is (n+1 ) production pipelines, where n is an integer from 1 to 100.

24. The geothermal energy system of claim 22, wherein the plurality of the injection pipelines are stacked above each other, or are placed side-by side in a rock formation.

25. The geothermal energy system of claim 22, wherein the plurality of the injection pipelines are spaced about 50 feet to about 200 feet lower than the production pipeline.

26. The geothermal energy system of claim 1, wherein the horizontal element of the injection pipeline includes a plurality of packers.

27. The geothermal energy system of claim 26, wherein the plurality of packers are spaced evenly across the horizontal element.

28. The geothermal energy system of claim 26, wherein the plurality of packers are spaced about 25 feet to about 90 feet apart from each other.

29. The geothermal energy system of claim 26, wherein the horizontal element of the production pipeline includes a plurality of packers.

30. The geothermal energy system of claim 28, wherein the plurality of packers on the production pipeline and the plurality of packers on the injection pipeline align.

31. The geothermal energy system of claim 28, wherein the plurality of packers include a plurality of ports.

32. The geothermal energy system of any of the preceding claims, wherein the system is a heat exchanger.

33. The geothermal energy system of claim 7, wherein the steam is delivered to a heat exchanger above a surface in the plant.

34. The geothermal energy system of claim 33, wherein the heat exchanger is connected to a turbine in the plant.

35. The geothermal energy system of claim 1, wherein the ratio of the horizontal element of the production pipeline to the horizontal element of the injection pipeline is 1:2 to 2:1, 1:1.8 to 1.8:1, 1:1.6 to 1.6:1, 1:1.4 to 1.4:1, 1:1.2 to 1.2:1, or 1:1.

36. A method for collecting energy from the earth comprising: injecting a working fluid into an injection pipeline, releasing the working fluid into a rock formation under the Earth’s surface through the injection pipeline, wherein the working fluid is converted to steam collecting the steam through a production pipeline, delivering the steam to a system above the rock formation.

37. The method of claim 36, wherein the working fluid is water or a well fluid.

38. The method of claim 36, wherein the working fluid is water.

39. The method of claim 36, wherein the rock formation is at a temperature of at least about 750°F.

40. The method of claim 36, wherein the injection pipeline includes a plurality of packers.

41. The method of claim 40, wherein the plurality of packers have a plurality of ports.

42. The method of claim 36, wherein the production pipeline includes a plurality of packers.

43. The method of claim 42, wherein the plurality of packers have a plurality of ports.

44. The method of claim 36, wherein the working fluid is released at a pressure of about 6,000 psi to about 8,000 psi.

45. The method of claim 36, wherein the injecting is performed by pumping the working fluid.

46. The method of claim 45, wherein the pumping is performed at a rate of about 300 to about 3,000 gallons per well per minute.

47. The method of claim 36, wherein the system is a plant.

48. The method of claim 47, wherein the plant includes a heat exchanger and a turbine.

49. The method of claim 36, wherein the steam is delivered at a power of 50 MWe to about 70 MWe.

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