Optimized CO2 Sequestration and Enhanced Geothermal Systems

Abstract

Disclosed herein are various embodiments of a system for drilling and operating a dual-use well. The well is drilled and operated as a geothermal power well using a hybrid process where a heat transfer fluid is injected into the hot rock formation but not removed and the heat is extracted using a closed loop process. The geothermal power well is then evaluated for use as a carbon dioxide sequestration well. In another embodiment, the well is drilled as a carbon dioxide sequestration well and then evaluated for geothermal power potential using a hybrid approach where supercritical carbon dioxide is injected into the hot rock formation but not removed and the heat is extracted using a closed loop process. Both horizontal and vertical wells are disclosed and are located in sedimentary rocks and subsurface granite.

Description

[Technical Field]

[0001] [CROSS-REFERENCE TO RELATED APPLICATIONS] This application claims the benefit of U.S. Provisional Patent Application No. 63 / 255,325 (Attorney Docket No. HTC-P-107), filed October 13, 2021, by inventor William James Hughes, entitled "Optimized CO2 Sequestration and Enhanced Geothermal System," which is hereby incorporated by reference in its entirety.

[0002] This application is related to U.S. Utility Application No. 17 / 588,267, filed January 29, 2022, inventor William James Hughes, attorney docket number HTC-107, entitled "Optimized CO2 Sequestration and Enhanced Geothermal System," which is hereby incorporated by reference in its entirety.

[0003] This application is related to U.S. Utility Patent No. 11,255,144 (inventor: William James Hughes, attorney docket number HTC-101, issued February 22, 2022), entitled "Annular Pressure Cap Drilling Method," which is hereby incorporated by reference in its entirety.

[0004] This application is related to U.S. Utility Patent No. 11,377,919 (inventor: William James Hughes, attorney docket number HTC-101 C, issued July 5, 2022), entitled "Annular Pressure Cap Drilling Method," which is hereby incorporated by reference in its entirety.

[0005] Various embodiments described herein relate to drilled wells and related devices, systems and methods for carbon dioxide sequestration and geothermal energy production. [Background technology]

[0006] Geothermal energy Geothermal energy, or energy generated in the form of heat within the Earth, has been known and harnessed for centuries. In many places around the world, this energy reaches the surface in the form of geysers, hot springs, and natural steam vents. Water seeps through the earth and, upon encountering hot rocks, becomes superheated and turns into steam. The superheated water and steam reach the surface through natural faults and fractures. The best-known examples occur in areas with hot rocks near the surface, such as Iceland and Napa Valley, as well as in areas with widespread hot rocks deep within the Earth, known as hot spots. At least in the United States, the Yellowstone hot spot is the best-known.

[0007] In recent years, geothermal energy has been used for small-scale projects, such as heating individual homes, and for commercial-scale projects, such as heating entire residential areas or industrial buildings. These projects use relatively shallow heat sources and rely on the fact that the earth remains at a relatively constant temperature a few feet below the surface. Larger projects can harness heat from deeper layers of the earth, often thousands of feet deep. The deep heat is transferred to the surface by heating injected water, which is then converted into steam and used to drive turbines and generators to generate electricity. At these depths, the rocks can reach temperatures of several hundred degrees.

[0008] Geothermal energy has become more popular due to rising fossil fuel prices and predictions that fossil fuel reserves are rapidly depleting and will soon be depleted. Recent developments in oil and gas production, particularly hydraulic fracturing, which allows resources to be recovered from dense geological formations, have helped to ease the sense of crisis. However, these new technologies are actually only postponing the inevitable: at some point in the future, recoverable hydrocarbon reserves will be consumed. Therefore, rather than waiting for hydrocarbon reserves to decline, it makes sense to begin the switch to geothermal energy now.

[0009] The problem of global warming, largely caused by fossil fuels, is also driving interest in geothermal energy. Enhanced recovery through hydraulic fracturing and other technologies can help mitigate the problem in the short term, replacing coal-fired power plants with gas-burning ones. However, it's entirely possible that this coal will be burned elsewhere. In fact, as coal-fired power plants continue to expand in China and India, some predict that coal may replace oil as the world's leading fossil fuel within a few years. Anything we can do to offset the associated increase in emissions would be helpful. Geothermal power doesn't release significant greenhouse gases into the atmosphere. Electricity generated from geothermal energy can replace energy generated by coal-fired power plants, reducing emissions and slowing global warming.

[0010] Fracking has made it possible to extract previously inaccessible hydrocarbons, but the fracturing techniques currently used require large amounts of water. Obtaining water rights can be problematic in many regions, particularly in the western United States, where water has long been a contentious issue. There is also the issue of what to do with the water after the fracturing procedure is completed and the water is pumped from the well. There are also environmental concerns about the impact of hydraulic fracturing on water resources. Geothermal energy production, in some embodiments, including those described herein, can be achieved without using large amounts of water.

[0011] Other patents and patent applications by the inventors of the technology described herein, including U.S. Utility Patent No. 11,377,919, entitled "Annular Pressure Cap Drilling Method" (inventor: William James Hughes, assignee: Hughes Tool Company LLC, hereinafter also referred to as the "'919 Patent"), demonstrate how it is possible to produce oil and gas without hydraulic fracturing and without the need for large amounts of water or chemical additives. These techniques also offer advantages, including better production yields, a better depletion curve, and significantly reduced overall costs. These technologies are also part of the near-term solution as the world shifts to renewable energy sources. However, the drilling techniques disclosed in these patents and patent applications, specifically the philosophy of avoiding well damage by employing near-balance drilling methods, are also applicable to well drilling for geothermal energy projects.

[0012] Electricity generated by geothermal sources has the advantage over other renewable energy sources, such as solar and wind energy, of providing a reliable energy supply day and night, regardless of weather. Because the amount of energy produced can be controlled and varied, geothermal power can be used as a backup when other forms of energy are unstable or when demand varies with the seasons or time of day. In areas such as the Western United States, where hot rocks are located at relatively shallow depths, the potential for geothermal energy development is enormous. With the right methods and expertise, there are few areas worldwide where geothermal energy cannot be developed.

[0013] The heat extracted from hot rocks in geothermal energy production is replaced by heat generated by the decay of radioactive elements in the Earth's crust or primordial heat flowing from deep within the Earth. Thus, energy produced by geothermal technology, whether as direct heat or indirect electricity, is a renewable resource. This means that geothermal energy projects may be eligible for subsidies and tax breaks, making them appealing to states and other organizations with goals of achieving a certain percentage of their total energy consumption from renewable energy.

[0014] Another advantage of geothermal energy production is that it requires significantly less land than other energy production methods. The generating equipment, pumps, and other components take up relatively little space. Most of the hardware is underground, making it easy to install beneath urban and suburban areas, as well as under large tracts of farmland or forest. This contrasts with the large land requirements of solar and wind farms. Furthermore, geothermal power has a minimal visual impact. Solar power plants have their own arguments: many believe that wind farms, with their strings of gigantic turbines, are unsightly and pose a threat to birds. For this reason, wind and solar power plants are often located in remote areas, far from where the electricity is used. This increases the cost of generating and transmitting electricity, requiring kilometers of transmission lines.

[0015] In some geothermal areas, water in the form of steam or superheated water naturally emerges from fissures, forming geysers and hot springs. Such heat sources are often intermittent, unreliable, and inconsistent. Early geothermal power projects extracted energy by drilling deep into aquifers. Many of these projects produced far less energy than their current peak production. In some cases, the heat flow was insufficient to replenish the extracted heat, or the aquifer was depleted of hot water. In either case, it is clear that pumping water from aquifers is not sustainable in the long term.

[0016] The use of such natural hot water sources may be more appropriately described as "passive" geothermal, since it utilizes heat brought to the surface by natural water flows. In order to find geothermal energy in less favorable geological environments, various methods have been devised to extract heat from deep within the earth and bring it to the surface. These techniques typically involve pumping a heat-transfer fluid through hot rock formations, absorbing subsurface heat, and then pumping the fluid out. Thus, energy is required to produce energy. Such techniques can be called "active" geothermal energy.

[0017] Modern active geothermal energy projects fall into two groups. In the first group, a fluid (usually water) is pumped into hot rock through an injection well, collecting heat as it moves through the hot rock. The fluid is then collected in an extraction well, located a short vertical distance from the injection well, and pumped back to the surface for direct use or conversion of the heat into electricity. Wells are typically drilled horizontally to maximize the amount of hot rock exposed to the fluid and to take advantage of the Earth's natural fractures, which are generally vertical. The heated fluid is expected to move upwards by relying on convection, which transfers heat upward. In reality, however, the fluid disperses throughout the natural fracture system, and only a small portion of it may reach the extraction well.

[0018] This is sometimes called the "plume" approach. It requires a large amount of fluid, and because the fluid disperses throughout the rock matrix, much of the injected fluid is not recovered. Just like smoke rising on a hot day, the plume widens as it rises. So, logically, one might expect to increase the amount of heat that can be captured by increasing the vertical distance between the injection and extraction wells. However, in reality, the greater the vertical distance, the more the plume disperses. Therefore, less fluid reaches the extraction well.

[0019] The use of carbon dioxide (CO2) as the injection fluid has been proposed, which has several advantages: for example, the thermal properties of CO2 are superior to those of water, and it is actually beneficial for the fluid to remain in the bedrock, a form of carbon sequestration.

[0020] To improve fluid flow from injection wells to production wells, some geothermal projects hydraulically fracture the rock between the wells. This strengthens the natural fracture system and increases the flow rate between the injection and production wells. This technique is called "enhanced" geothermal power. As with hydraulic fracturing for oil and gas production, it is often used after the natural fracture system has been damaged when drilling wells using conventional overbalanced drilling techniques. There is also some question as to whether hydraulic fracturing strengthens the natural fracture system or simply forces heavier drilling mud further into the fractures, actually reducing overall permeability.

[0021] Hydraulic fracturing of geothermal wells doesn't release methane like drilling for hydrocarbons, but it often requires large amounts of water laced with chemicals to improve fracking results. This is a serious drawback, especially in areas like the southwestern U.S., where hot rock formations are accessible but water is a scarce and highly contested resource.

[0022] Geothermal power generation has been noted to have a negative impact on land stability. For example, land subsidence has occurred in the Wairakei oil field in New Zealand. In seismically active regions, injecting large amounts of water can trigger earthquakes. This is because the injected water lubricates existing faults, causing them to slide. A geothermal power project in Basel, Switzerland, observed more than 10,000 seismic events within six days of the start of drilling. One earthquake measured magnitude 3.4, which led to the project being suspended.

[0023] This effect can be exacerbated when hydraulic fracturing is used to facilitate the flow of heated water. For these reasons, many municipalities include the hydraulic fracturing of geothermal wells in their "fracking bans." In areas that oppose hydraulic fracturing, it is virtually impossible to convince the community that some types of "fracking" are not as bad as other types. Such bans are often imposed in densely populated areas that call into question the development of geothermal resources and are most in need of clean energy resources.

[0024] Water pumped from deep rock formations can contain a variety of dissolved gases, including carbon dioxide, hydrogen sulfide, methane, and ammonia. Carbon dioxide and methane are well-known greenhouse gases. While geothermal energy produces far less carbon dioxide than fossil fuels, the problem cannot be ignored. Hydrogen sulfide and ammonia are dangerous in even small amounts. These gases also contribute to the formation of acid rain. Therefore, geothermal plants using injection and capture must be equipped with emission control systems and, in some cases, install carbon sequestration systems to reduce the amount of carbon dioxide introduced into the atmosphere.

[0025] Heated water pumped from deep underground can contain large amounts of dissolved minerals that can damage turbines and power generation equipment. These substances include mercury, arsenic, boron, antimony, and salt (sodium chloride). As the water cools, these substances fall out of solution. To prevent environmental damage, these substances must be disposed of responsibly. This is often achieved by reinjecting these substances into the ground along with the water injected for the geothermal process.

[0026] The second approach to active geothermal energy production uses water or other fluids pumped through pipes in hot rock formations. These are called closed-loop systems. In this system, all fluids pumped into the well are contained within underground pipes and are collected and reused. This method has its own problems. One of them is the formation of air pockets, which can cause water to turn to steam earlier than the optimal point in the pipe system. These air pockets can impede the flow of water and significantly reduce the efficiency of the geothermal heat transfer process.

[0027] There are two variations of the closed-loop method. The first variation uses a single well and concentric pipes to pump the heat transfer fluid into a vertical well and then along a directional well. At the end of the well, the heat transfer fluid makes a U-turn and flows back along the well in concentric tubing. The advantage of this method is that it requires only one surface site and one well.

[0028] A second variation on the closed-loop method also uses pipes to pump the heat transfer fluid into a vertical well and then along a directional well, but the heat transfer fluid is returned to the surface up a second vertical well. Once the fluid reaches the surface, it is pumped back to the injection well at the surface or through a shallow pipeline. Heat extraction usually occurs as the fluid reaches the surface. Of course, this method requires two surface locations and raises permitting issues for the return pipeline.

[0029] The closed-loop approach eliminates problems related to induced seismicity and contamination of the extracted fluid. However, it has two major weaknesses. The surface area of ​​the pipe in contact with the hot rock is relatively small, and heat is rapidly lost from the rock surrounding the pipe. In other words, heat is removed from the rock surrounding the pipe and transferred to the surface faster than it can be replenished by heat flowing in from the surrounding rock. Operators have addressed this problem by drilling longer wells and installing longer pipes. The second problem remains challenging. One solution is to drill a series of wells radially from the same surface location, rotating each well for a set period of time. This works well for single-well approaches, but creates more problems for dual-well approaches. Of course, this increases the cost and complexity of the installation, altering the economics of the project. Other proposed solutions are more complex, such as installing two parallel wells with opposing flow directions and installing heat exchangers at both surfaces.

[0030] Background - Carbon Sequestration The second component of this invention relates to carbon sequestration, the process of permanently storing carbon dioxide in geological formations so that it is removed from the atmosphere and does not contribute to global warming. There is general agreement among scientists, and the public is increasingly accepting, that simply shifting energy use to renewable sources is not enough. To avert catastrophe, the Earth must reverse the warming process and remove carbon dioxide from the atmosphere on a massive scale.

[0031] This document does not address technologies for capturing carbon dioxide. A wealth of information is readily available on this topic, and new approaches are currently being developed. For the purposes of this document, it is sufficient to note that there are two main sources of carbon dioxide for sequestration:

[0032] The first source is capturing carbon dioxide at the point of generation. This includes obvious sources like fossil fuel-burning power plants, cement plants, and steel mills. It also includes smaller-scale sources like breweries and cannabis farms. Ideally, carbon dioxide would be sequestered at the point of power generation. However, currently, much of the captured gas is sent to sequestration facilities via dedicated pipelines. A lack of on-site sequestration capacity and limited pipeline availability currently impose significant limitations on the amount of carbon dioxide that can be captured and sequestered.

[0033] This involves extracting carbon dioxide from the atmosphere. Often, this is accomplished by passing large amounts of air through machines similar to large air conditioners. Of course, these machines require some kind of energy to run, which may be natural gas or electricity generated from natural gas. Naturally, the first step is to capture the carbon dioxide emitted during the energy production process.

[0034] Once carbon dioxide is captured, it can be pumped underground into rock formations and stored permanently. This process is known as "carbon sequestration." It's important to note that the goal of sequestration is permanent disposal of carbon dioxide. This is distinct from injecting carbon dioxide into oil or gas wells for secondary or tertiary hydrocarbon recovery. Some operators inject more carbon dioxide underground than is needed for hydrocarbon recovery, which can be considered a form of sequestration.

[0035] Because early attempts at sequestration often used available oil and gas wells that had reached the end of their productive life, this is often considered the best, or even the only, approach. However, the drilling technology described in the referenced patent application allows wells to be drilled efficiently and cost-effectively solely for carbon sequestration, eliminating the need for pipelines to transport carbon dioxide from its source to a disposal site. For example, cement plants and power plants not located near oil or gas fields could have dedicated carbon sequestration wells.

[0036] Conversely, oil and gas fields located many kilometers from convenient transportation methods like pipelines and terminals could be developed to generate energy to run carbon capture machinery, disposing of the carbon dioxide on-site and using some of it for secondary and tertiary capture. The rise of carbon capture tax credits and carbon trading schemes will dramatically change the economics of hydrocarbon discoveries in remote locations.

[0037] However, it is important to keep in mind that utilizing old oil and gas wells is not always ideal. Indeed, the utilization of old wells has been actively promoted by those who profit from them. However, these wells were almost certainly drilled with heavy drilling muds, which blocked the formations. Hydraulic fracturing is also likely to have been used. Most wells are cased, meaning that CO2 can only come into contact with the formation in a limited area of ​​the well. Drilling also causes formation damage, including compaction of the rock around the perforation area. Fines may have migrated during years of production, blocking much of the permeability around the well. Furthermore, while these wells are located near pipelines that transport oil and gas, the pipeline infrastructure to transport CO2 to the well may not be in place. The cost of developing such infrastructure may make utilizing depleted wells unprofitable, except in areas with dense infrastructure, such as the Permian Basin.

[0038] Background - Excavation Drilling geothermal wells and carbon dioxide sequestration wells greatly benefit from the near-balanced drilling techniques described in the referenced patent applications, due to their lower cost and faster drilling speed than conventional drilling techniques. However, the greatest advantage is that these drilling techniques avoid formation damage during drilling. Natural fracture systems are not blocked by heavy drilling mud, and the permeability of the natural fracture systems in the rock formation is maintained. This improves fluid flow and heat transfer in geothermal applications. It also improves the well's ability to disperse carbon dioxide into the formation, enhancing the well's sequestration capabilities and extending the well's useful life.

[0039] Using drilling techniques that do not damage the permeability and isolation capabilities of the natural fracture system offers the added benefit of not having to resort to hydraulic fracturing to undo the damage caused by traditional drilling techniques. This approach not only reduces overall costs, but also avoids the large amounts of water, sand, and chemicals required for hydraulic fracturing. Summary of the Invention [Problem to be solved by the invention]

[0040] Methods are needed to combine and optimize both carbon sequestration and geothermal energy generation. [Means for solving the problem]

[0041] In one embodiment, a method for extracting geothermal energy from a well beneath the Earth is provided. The method includes the steps of: drilling a well down to a hot rock formation with a drill bit and a drill string; forming an outer annulus between the drill string and the well; installing concentric tubing inside the drill string to form an inner annulus and a closed-loop fluid flow path; injecting a first heat transfer fluid from the outer annulus into the hot rock formation to form a first heat transfer fluid cloud within the hot rock formation; pumping a second heat transfer fluid from the inner annulus into the closed-loop fluid flow path and returning the second heat transfer fluid through the concentric tubing to the surface; and converting heat extracted by the second heat transfer fluid into usable energy.

[0042] In another embodiment, a method for combining geothermal power generation and carbon dioxide sequestration in the same well is provided. The method includes the steps of: drilling a commercially viable well down to a hot rock formation with a drill bit and a drill string; forming an outer annulus between the drill string and the well; injecting supercritical carbon dioxide from the outer annulus into the hot rock formation to form a supercritical carbon dioxide cloud in a region within the hot rock formation surrounding a directional section of the well; collecting data with at least one instrument located in the well; forming an inner annulus and a closed-loop fluid flow path by installing concentric tubing inside the drill string if the heat flow rate exceeds a predetermined value; continuing to use the well exclusively for carbon dioxide sequestration if the heat flow rate is below a predetermined value; pumping a heat transfer fluid from the inner annulus into the closed-loop fluid flow path and returning the heat transfer fluid through the concentric tubing to the surface; and converting heat extracted by the heat transfer fluid into usable energy.

[0043] In another embodiment, a method for combining a carbon dioxide sequestration well with a geothermal energy production well is provided.

[0044] The method includes the following steps: drilling a carbon dioxide sequestration well down to a hot rock formation using a drill bit and a drill string; forming an outer annulus between the drill string and the carbon dioxide sequestration well; injecting supercritical carbon dioxide from the outer annulus into the hot rock formation to form a supercritical carbon dioxide cloud in an area within the hot rock formation surrounding a directional section of the carbon dioxide sequestration well; collecting data using at least one instrument located within the carbon dioxide sequestration well and, if a heat flow rate exceeds a predetermined value, forming an inner annulus and a closed-loop fluid flow path by installing a concentric tube inside the drill string; pumping a heat transfer fluid from the inner annulus into the closed-loop fluid flow path and returning the heat transfer fluid through the concentric tube to the surface; and converting the heat extracted by the heat transfer fluid into usable energy.

[0045] Further embodiments are disclosed herein or will become apparent to those skilled in the art after reading and understanding this specification and drawings. [Brief explanation of the drawings]

[0046] Different aspects of various embodiments of the present invention will become apparent from the following specification, drawings and claims.

[0047] [Figure 1A] FIG. 1 illustrates the basic approach to active geothermal extraction.

[0048] [Figure 1B] FIG. 10 illustrates heat extraction using perforated portions of the casing.

[0049] [Figure 2] FIG. 1 illustrates the plume method of geothermal extraction using directional wells.

[0050] [Figure 3]Figure 1 shows the plume method of extracting geothermal heat from a single vertical well using a directional well.

[0051] [Figure 4] FIG. 1 illustrates a closed-loop method for extracting geothermal energy from a single well.

[0052] [Figure 5] FIG. 1 illustrates a radial system of directional wells for extracting geothermal heat.

[0053] [Figure 6] FIG. 1 illustrates a two-well closed-loop geothermal pumping method.

[0054] [Figure 7] FIG. 1 illustrates the first stage of drilling a geothermal or isolation well.

[0055] [Figure 8] FIG. 1 illustrates the final stages of drilling a geothermal or isolation well.

[0056] [Figure 9] FIG. 1 illustrates a well configured for geothermal energy production and carbon sequestration.

[0057] [Figure 10] FIG. 1 shows a vertical well drilled into a granite formation for geothermal energy production and carbon sequestration.

[0058] The drawings are not necessarily to scale and like numbers refer to like parts or steps throughout the drawings. DETAILED DESCRIPTION OF THE INVENTION

[0059] Detailed Description of Some Embodiments

[0060] In the following description, specific details are provided to provide a thorough understanding of various embodiments of the present invention. However, those skilled in the art will understand, after reading the specification, claims, and drawings, that some embodiments of the present invention may be practiced without adhering to some of the specific details set forth herein. Moreover, to avoid obscuring the present invention, some well-known methods, processes, and apparatus and systems that find application in the various embodiments described herein are not disclosed in detail.

[0061] Embodiments of the present invention will now be described with reference to the drawings. The present invention can be implemented in numerous ways. Several embodiments of the present invention will be described below. The accompanying drawings depict only typical embodiments of the present invention and therefore should not be considered limiting of its scope and breadth. The drawings illustrate some, but not all, possible embodiments and may not be drawn to scale.

[0062] Any embodiments or applications of the invention provided herein are intended to be illustrative and not limiting.

[0063] Throughout this specification, the term "directional well" or "directional well" is defined to mean a well or wells that have a direction and are horizontal, substantially horizontal, offset, inclined, oblique, or along a particular subsurface rock formation. This term is used to distinguish such wells from wells that are substantially vertical.

[0064] Turning now to the drawings, let us first consider a well drilled for geothermal power generation using the plume approach. FIG. 1A illustrates the simplest method for actively extracting geothermal heat. This involves injecting a heat transfer fluid 100 (usually water) into a vertical injection well 102 using an injection pump 104 and into a hot rock formation 106, where the heat transfer fluid 100 picks up heat. The heat transfer fluid 100 is then pumped, preferably at a much higher temperature, out a vertical extraction well 108, typically located slightly higher above the hot rock formation 106, using an extraction pump 110. The heated fluid can be used directly to power a steam turbine to generate electricity. In another embodiment, the heated fluid is passed through a heat exchanger, and its heat is used to generate steam to drive a turbine-generator. Ideally, much of the injected heat transfer fluid 100 will flow toward and be captured by the extraction well 108, as indicated by flow arrows 112. However, in practice, as the injected heat transfer fluid 100 leaves the vertical injection well 102, it quickly diffuses through the natural fracture system, as indicated by the flow arrows 114, and very little of it reaches the extraction well 108. This will be apparent to those skilled in the art, and therefore this method is not very effective.

[0065] There are ways to enhance this effect, such as surrounding the injection wells with a ring of extraction wells, or vice versa. This adds complexity at the surface by requiring the heat transfer fluid to be routed to a central heat extraction unit and other steps to store the extracted energy. It is also possible to deviate the injection wells so that the heat transfer fluid is injected directly beneath the heat extraction wells. Again, distribution through the natural fracture system limits the amount of heat captured.

[0066] In this case, only one well 120 is required. Heat extraction is therefore achieved using perforations in the outer casing 122 concentric with a fluid injection tube 124. Heat transfer fluid 16 is pumped down the fluid injection tube 124 into the hot rock formation 106, as indicated by flow arrow 126, and as it moves up around the perforated outer casing 122, as indicated by flow arrow 128, it is drawn by an extraction pump through the perforations into the annulus between the outer casing 132 and the fluid injection tube 124, as indicated by flow arrow 130.

[0067] With modern drilling technology, it makes sense to drill a horizontal or near-horizontal well to maximize exposure of the heat transfer fluid to the hot rock formation. One possible embodiment of this method is shown in Figure 2. A heat transfer fluid 200 is pumped through an injection well 202 having a vertical section 204 and a directional section 206. The heat transfer fluid is discharged from the directional section 206 of the injection well 202 into the hot rock formation 106. The heat transfer fluid 200 collects heat from the surrounding hot rock formation 106 and rises, as indicated by flow arrow 214, toward the directional section 210 of an extraction well 212. The heat transfer fluid is then pumped back out the vertical section 216 of the extraction well 212 and sent to a turbine or heat exchanger to generate electricity.

[0068] 3 shows a variation of this method, using a single vertical well 300 from which both a directional injection well 302 and a directional extraction well 304 are drilled. Concentric casing 306 allows heat transfer fluid 308 to be pumped downward from the injection well 302 and upward from the extraction well 304.

[0069] As mentioned above, it is common to try to obtain higher heat extraction rates through the use of hydraulic fracturing. The idea is that the more fractured the rock, the more water will flow from the injection well to the extraction well. However, in this case, there is a risk that hydraulic fracturing will open up the natural fracture system, causing the heat transfer fluid to deviate from the desired vertical path.

[0070] Figure 4 illustrates a closed-loop approach. In Figure 4, one vertical well 400 is drilled, and a directional well 402 is drilled from the vertical well 400 into the hot rock formation 106. Concentric tubes 404 are installed to allow heat transfer fluid to be pumped down the vertical well 400 and along the directional well 402 to the end of the well 406, as indicated by flow arrow 408. The fluid then makes a U-turn and returns upward along an annulus 410 between the concentric tubes 404 and the well 400, as indicated by flow arrow 412. The heat transfer fluid is not discharged into the surrounding hot rock formation 106. The idea behind this approach is that heat flow from the surrounding rock is sufficient to replenish the heat extracted and transferred to the surface.

[0071] In practice, this does not work as well as hoped, as the heat from the surrounding hot rock formations is rapidly depleted, so various approaches have been tried to enhance heat transfer. For example, increasing the length of directional wells allows the heat transfer fluid more time to collect heat at depth before returning to the surface. The more heat transfer fluid there is in the well, the more powerful the pumps must be to keep it circulating.

[0072] As shown in Figure 5, in some projects, multiple directional wells 502-526 are drilled in multiple directions from a single vertical well, or even from multiple vertical wells on a single pad, using a central pump and generator facility 500. This not only significantly increases the underground volume from which heat is extracted, but also allows some directional wells to recover from heat depletion while other wells are still producing. Note that the radial spacing and length of the wells are not uniform between wells and are determined by the geology and available hot rock zone. While Figure 5 is a plan view, those skilled in the art will understand that multiple injection and extraction wells can be drilled at different depths.

[0073] Figure 6 shows a different closed-loop approach in which the injection well 602 and extraction well 604 are separated by a significant distance, allowing for a long directional component 606 to the well, resulting in more heat being collected by the heat transfer fluid 608 as it passes through the hot rock formation. Drilling wells in this manner requires sophisticated drilling techniques, which translates into high costs. A vertical well must be drilled at each location, the drill bit must be displaced to drill horizontally (610, 612), and the two wells 614 must be joined with precision that is very difficult to achieve at the depths required for geothermal wells. The heat transfer fluid 608 is pumped from the injection well 602 by pump 620 and from the extraction well 604 by pump 622. After the heat brought to the surface is used to generate electricity, the cooled heat transfer fluid 608 is pumped back along pipe 626 at 624 and stored in tank 628.

[0074] Again, the two-well closed-loop approach can be adapted to radial or grid systems to provide continuous power generation capability by using some loops while other loops recover from localized thermal depletion.

[0075] The closed-loop approach can encounter problems when using water as the heat transfer fluid: as the superheated water approaches the surface, pressure drops, causing the water to turn to steam, forming steam pockets that can impede flow and adversely affect pump operation. Similar problems due to cavitation can also occur at the end of a directional well, as the fluid is forced to change direction rapidly.

[0076] While all these approaches seem promising, geothermal power has yet to make a real impact on the overall energy mix. In plume approaches, dispersion of injected fluids is often ignored or underestimated. The problem with closed-loop approaches is most likely due to the rapid loss of heat from the rocks near the well and in the area where the fluids are injected and extracted. After all, rock is an insulator. If heat is lost quickly, the rock cools and is subjected to thermal stresses. This promotes more fractures and therefore more fluid flow than with plume methods, but the impact is relatively minor.

[0077] Considered herein, the present invention overcomes the above-mentioned and other problems associated with previous geothermal technologies, and provides various embodiments that combine geothermal wells with carbon dioxide sequestration wells to maximize return on investment and extend the useful life of the wells.

[0078] As previously mentioned, some geothermal wells aim to pump water or fluid into the bedrock and recover a portion of the heated fluid plume from a separate well. Other geothermal technologies use a closed-loop approach, pumping the heat transfer fluid through a pipe and returning it to the surface through the same well or another connected well, but the fluid is not released into the bedrock. These approaches have drawbacks, as discussed above. To overcome these drawbacks, the present invention employs a hybrid approach.

[0079] The embodiments disclosed herein inject a heat transfer fluid into the surrounding rock formation, as is done in the plume approach. A key feature of this hybrid approach is that the injected fluid is not recovered at any point in the process. The injected fluid fills the natural fracture system and forms a cloud surrounding the well, where it acts as a conductive heat transfer mechanism. With this method, neither the injected nor naturally occurring fluids are recovered from the subsurface. Therefore, no equipment is required to process the dissolved gases or minerals in the trapped fluid, as is done with the plume approach.

[0080] Instead of capturing heat within the injected fluid from its expanding plume, the present invention relies on extracting heat that is conducted toward the well through injected and / or naturally occurring fluids that fill or have filled the natural fracture system surrounding the well (i.e., formation water). Heat extraction is accomplished using a closed-loop system of concentric pipes, carrying the heat transfer fluid in one pipe to the end of the well and back along the other concentric pipe.

[0081] This combination of plume and closed-loop technology overcomes the typical problem of closed-loop systems: heat from the nearby surrounding rock is transferred to the fluid within the closed loop, and thus heat recovery rates decrease as it is transferred to the surface. In this system, the injected fluid serves as an effective heat transfer mechanism. The volume of the rock filled with the cloud of injected fluid constantly expands, increasing the available geothermal energy. The injected fluid flows outward from the well slower than the rate at which heat is transferred inward from the rock volume toward the well. While some heat is conducted through the rock, much of the heat reaching the well is transferred as the injected fluid fills the natural fracture system.

[0082] FIG. 7 illustrates the early stages of drilling a geothermal energy well 700. Employing techniques enabled by advances in directional well drilling, the well is drilled in a vertical section 702 with casing 704, transitioning through a curve 706 into a directional well 708, and drilled into a suitable rock formation. In a preferred embodiment of the present invention, the well is drilled into granite 710, a rock formation found at various depths. Granite is hard, brittle, and naturally highly fractured. Importantly, granite contains uranium and other heavy radioactive elements, which, upon decay, generate heat for geothermal energy projects. Of course, all of the techniques disclosed herein can also be used in sedimentary rock formations.

[0083] The vertical section 702 of the well 700 can be drilled using conventional drilling methods. At this point, there is no disadvantage to conventional techniques using drilling mud, as formation damage still needs to be avoided. The vertical section 702 of the well 700 uses industry standard casing 704, typically 9 5 / 8 inches in diameter in the United States. Once the target formation is reached, which in Figure 7 is granite 710, the well is drilled as a directional well. In some embodiments, the vertical section 702 and the curve 706 are drilled using an electric drilling motor.

[0084] As shown in Figure 8, the directional section 802 of the well 700 is always drilled underbalanced or near balanced to avoid the formation damage typically inflicted by using heavy drilling muds. See the '919 patent for a detailed description of how this is done safely using an annular pressure control diverter and near-balanced reservoir drilling (NBRD). The technology disclosed in the '919 patent is used to prevent fluids, including water, radon gas, or hydrocarbons, from escaping from the well during drilling. The NBRD method does not damage the natural fracture system of the hot rock formation, eliminating the need for hydraulic fracturing or other remedial treatments.

[0085] In the embodiment shown in FIG. 8, the directional section 802 of the well 700 is drilled using a drill-in liner 804 that is 5.5 inches in diameter, for example in the United States. The drill bit 806 has a much larger diameter, approximately 10 inches. In a technique known as open-hole drilling, no casing is placed in the directional section 802. Because the well 808 has the same diameter as the drill bit, an annulus 810 is formed between the horizontal section of the drill-in liner 804 and the surface of the well 808. There is also an annulus 818 between the casing 704 and the vertical section of the drill-in liner 804.

[0086] In some embodiments, a jet pump 820 is located behind the drill bit 806. The jet pump creates a powerful suction that removes cuttings from the area in front of the drill bit, allowing for high penetration rates. See U.S. Patent No. 11,168,526, "Jet Pump Drilling Assembly," inventor William James Hughes, assigned to Hughes Tool Company LLC, for a discussion of using a jet pump to create a vacuum in front of the drill bit, thereby creating a true imbalance in front of the drill bit and avoiding formation damage.

[0087] FIG. 9 shows a geothermal well after drilling is complete. In embodiments using a drill-in liner 804, the drill-in liner 804 is a critical component of the closed-loop system and is left in place once drilling is complete. Therefore, the drill bit 806 and jet pump 820 are also left in the well 808. This is done to eliminate the cost of retrieving the drill bit 806 and jet pump 820. The well may also be extended at a later date to extend geothermal energy production or prepare the well for carbon sequestration. A small-diameter concentric tube 902 is placed inside the drill-in liner 804, creating an inner annulus 904 between the drill-in liner 804 and the concentric tube 902. In some embodiments, the concentric tube 902 is vacuum-insulated tubing.

[0088] Once the well is drilled and the concentric tubes are installed, the next step is to operationalize the well. In some embodiments, a first heat transfer fluid 920 is pumped down the outer vertical annulus 818 into the directional annulus 810, where it comes into contact with the uncased well 808. Thus, the first heat transfer fluid 920 begins to move into the subsurface's natural fracture system, as indicated by flow arrows 921. As the first heat transfer fluid 920 expands in all directions, it forms a cloud 922 of first heat transfer fluid 920, filling the fracture system with an efficient means of conducting heat back from the rock formation to the well. In prior closed-loop systems, the outer surface of the concentric tube system is in contact with the insulating rock formation. In the present invention, using open-hole drilling means that the outer surfaces of the concentric tubes are surrounded by the first heat transfer fluid 920 in the directional annulus 810, which is in direct contact with the first heat transfer fluid 920 contained in the rock formation.

[0089] The closed-loop system is then initiated by pumping a second heat transfer fluid 940 into the inner annulus 904 between the drill-in liner 804 and the concentric tube 902. The second heat transfer fluid 940 is pumped to the end of the drill-in liner 804 where it makes a U-turn and flows back along the concentric tube 902 as indicated by flow arrows 924. This is the reverse of what is shown for the closed loop in FIG. 4, although the flow could have been reversed in that example. If the concentric tube 902 is a vacuum insulated tube, it is preferably used to contain the upward-flowing heated fluid and retain as much heat as possible as the second heat transfer fluid 940 returns to the surface.

[0090] Once the second heat transfer fluid 940 reaches the surface, the heat it carries can be used directly for heating or converted to electrical energy by a conventional system of heat exchangers and turbine-driven generators. Heat extracted from the surrounding hot rock formations is replenished by heat conducted along the fracture network by the injected first heat transfer fluid 920. In this way, these hybrid embodiments overcome the drawbacks of both the plume and closed-loop approaches.

[0091] To extend the life of wells and increase geothermal energy production, previously tested techniques can be modified and used, including drilling multiple directional wells, each extracting subsurface thermal energy for a period of time, followed by a recovery period to allow the injected first heat transfer fluid 920 to diffuse through the natural fracture system, and then injecting more first heat transfer fluid 920.

[0092] The injected first heat transfer fluid 920 that forms the cloud 922 can be water, brine, supercritical carbon dioxide, or captured exhaust gas, or a mixture of any of these fluids. Using supercritical carbon dioxide enhances heat transfer. Carbon dioxide can be brought to a supercritical state at relatively low temperatures and pressures (90°F and 1070 psi are sufficient). Therefore, supercritical carbon dioxide requires pressurization equipment, but like water, it is harmless to effluent, non-toxic, and non-flammable. As discussed below, the use of supercritical carbon dioxide makes commercial sense when geothermal wells have the potential for carbon sequestration, either concurrently with energy production or later in their lifecycle.

[0093] The second heat transfer fluid 940 of the closed loop may be the same fluid as the injected first heat transfer fluid 920, or it may be a different fluid. The injected fluid 920 and the second heat transfer fluid 940 do not have to be the same fluid. In some embodiments, supercritical carbon dioxide is used as both heat transfer fluids due to its excellent heat transfer properties. In various other embodiments, different fluids may be used. For example, water or saline solution, or various types of heat transfer oils may be used.

[0094] In some embodiments, the well is primed with an injected first heat transfer fluid 920 for a period of time to allow heat transfer before the process of generating geothermal energy begins. The first step in the priming process is pumping supercritical carbon dioxide into the well. The carbon dioxide in its supercritical state diffuses out of the well through natural fractures. Depending on the temperature and pressure of the rock surrounding the well, the carbon dioxide may drop out of its supercritical state, but as more carbon dioxide is pumped into the well, the pressure increases to the point where it becomes supercritical again. During the process of pumping carbon dioxide, the underground volume surrounding the well begins to fill with supercritical carbon dioxide, and the well is ready to be configured as a geothermal well.

[0095] Now, if we turn to wells drilled for carbon sequestration, which pump carbon dioxide into permeable underground rock formations, a similar approach is used.

[0096] Let's consider the first well drilled as a carbon sequestration well. As mentioned above, many people assume that carbon sequestration requires existing depleted or abandoned oil or gas wells. This assumption is based on economic considerations, not technical ones. Using existing wells obviously avoids the cost of drilling new wells. However, this approach ignores several important factors. Because carbon dioxide is often produced or captured far from available oil or gas wells, a pipeline is needed to transport the carbon dioxide. Building such a pipeline would be extremely expensive, including obtaining permits from multiple landowners. Opposition to the pipeline is anticipated for a variety of reasons, and the entire construction process could take years, if it even occurs.

[0097] A second problem with utilizing depleted wells is that they were almost certainly not drilled with carbon sequestration in mind. They were likely drilled with conventional drilling techniques, including the use of heavy drilling muds, which would have blocked natural fracture systems and damaged the rock formations. This damage would have been exacerbated by flushing, which would have forced mud further into the fractures and pores. Typical trace wells have a relatively short productive lifespan, making them unsuitable for reuse as sequestration wells.

[0098] A third potential problem with utilizing depleted oil wells, at least in the United States, is ownership. Under U.S. law, ownership of surface rights is often separate from ownership of subsurface mineral rights. However, ownership of the void space beneath the surface is generally held by the surface rights owner. The void space has not been considered legally part of the mineral rights, but rather consists of a "mineral void." This means that mineral rights owners or lessees likely have the right to extract oil and gas, but not the right to fill the resulting void space with carbon dioxide or other substances. Sequestration would require entirely new agreements with surface rights owners.

[0099] All of these problems can be overcome by drilling wells specifically for the purpose of carbon sequestration. Using modern drilling techniques and technologies, wells can be drilled cost-effectively near the source of the carbon dioxide to be sequestered without damaging the formations, which would reduce the well's overall sequestration potential. The inventions described herein utilize the advanced NBRD drilling techniques described in the '005 patent application. These inventions focus on avoiding formation damage and leaving the natural fracture system intact.

[0100] If the goal is to drill a carbon dioxide sequestration well, the same process described above and illustrated in Figures 7 and 8 is followed. By using a drill-in liner 804, the entire directional well 808 acts as a distribution mechanism for the supercritical carbon dioxide being pumped into the annulus 810. As a result, much more of the supercritical carbon dioxide enters the rock formation than would be possible using a cased well, which has perforation spacing that severely restricts fluid flow. An added benefit is the elimination of the cost and time required to drill casing.

[0101] The concept of carbon sequestration is not new. Neither is generating electricity from geothermal energy. Combining the two in a single well is not new, but it has been problematic in that it has not been optimally designed. This invention is novel in that it combines these two objectives, using a single well for both purposes, potentially providing the benefits of both at little additional cost using a phased, integrated, and optimized approach.

[0102] Some researchers have proposed combining carbon dioxide sequestration and geothermal energy production in the same well. However, such approaches typically employ the inefficient plume method described above and attempt to utilize a geothermal well as a carbon dioxide sequestration well. One drawback of this forced combination is that the requirements for optimizing a sequestration well are not necessarily the same as those for optimizing a geothermal well. As described in more detail below, the present invention allows a well to be optimized for both uses.

[0103] Another drawback is that the project may not be economically successful if other aspects of the project do not quite deliver the expected results. Most of these projects seem to have started as geothermal CO2 projects, resulting in their rebirth as sequestration wells. In fact, the Achilles' heel of plume technology - dispersion of the injected fluid - is only a positive feature when considered as a means of delivering CO2 underground. Geothermal performance worsens the more CO2 is dispersed, while, more or less by chance, geothermal sequestration capabilities improve.

[0104] One of the earliest documents regarding the use of supercritical carbon dioxide is U.S. Patent No. 6,668,554 to Brown, entitled "Geothermal Energy Production with Supercritical Fluids." The technology described in this patent discloses a plume approach, in which carbon dioxide fills a subsurface volume and is then captured and returned to the surface where thermal energy is extracted. This suffers from the usual problem with plume approaches: the plume expands, and only a small portion of the injected fluid actually flows into the extraction well.

[0105] A more recent example of the plume approach can be found in U.S. Patent No. 8,316,995 to Saar et al., entitled "Carbon Dioxide-Based Geothermal Energy Generation Systems and Methods Related Thereto." This technology, as set forth in the claims, relies on the presence of an impermeable cap rock to contain the plume. This patent at least acknowledges the problem of injecting fluid into a rock formation and attempting to recover the fluid from the expanding plume some distance underground.

[0106] Because one well can potentially be used for both purposes, one embodiment of the present invention proposes a phased, integrated, and optimized approach to combining geothermal energy generation and carbon dioxide sequestration. Furthermore, these phases can be implemented in different orders depending on several factors, particularly the economics of the project.

[0107] In some embodiments of the invention, the well is first drilled as a geothermal well and evaluated for its long-term carbon sequestration potential. In other embodiments, the process begins with drilling a well for carbon sequestration purposes. Once carbon dioxide is pumped into the well and begins to fill the natural fracture system, the well is evaluated for its geothermal potential.

[0108] In either embodiment, an ideal project would be located in an area with known characteristics indicating that the well is suitable for both purposes. In such an undertaking, the definition of "suitable" is multi-factorial. The formation must be deep enough to ensure that the carbon dioxide remains sequestered and does not return to the surface. Unlike hydrocarbons (including fracturing fluids), carbon dioxide can migrate to the surface without significant environmental harm, but this would defeat the purpose of sequestration. The formation must be porous enough to absorb large amounts of carbon dioxide and permeable enough to allow the carbon dioxide to diffuse from the injection well into the formation. The long-term goal is for the carbon dioxide to react with the rock and become part of the formation, so the formation's chemical composition is important. However, if the rock reacts with carbon dioxide too quickly, the permeability of the formation surrounding the well may deteriorate, blocking flow and potentially rendering the well useless.

[0109] For purposes of this invention, "suitable" includes factors not normally considered critical for sequestration wells, including formation temperature and rock heat-flow properties, which are important for the well's use as a geothermal well, either concurrently with or subsequent to carbon dioxide sequestration.

[0110] It is also possible to evaluate existing geothermal wells for carbon dioxide sequestration and existing geothermal storage wells for their geothermal potential.

[0111] In some embodiments, a geothermal well is drilled and equipped with sensors for temperature, pressure, flow rate, etc. Measurements are taken before injecting the supercritical carbon dioxide, during injection, and during pauses in injection to determine the pressure drop caused by the supercritical carbon dioxide dispersing into the surrounding formations. These measurements may be combined with other data, including well logs from the geothermal well and other nearby wells. Active or passive seismic surveys can provide valuable insight into the extent and direction of the injected fluid cloud. In this way, the well's potential for use as a carbon dioxide sequestration well can be evaluated while also generating energy to cover the costs of the well.

[0112] As the supercritical carbon dioxide is injected into the well and dispersed, data can be collected indicating the rate of dispersion, heat transfer rate, and other factors. Some data can be obtained from sensors in the well. Other data, particularly data on the natural fracture system and the rate and extent of supercritical carbon dioxide dispersion, can be obtained using passive or active microseismic methods. Such studies can involve the use of surface sensor arrays or DAS cables in the well. For example, DAS cables can be attached to the outside of pipes used for heat transfer fluid flow. Analysis of seismic data obtained as the pumping of supercritical carbon dioxide begins and progresses can show how the fluid disperses through natural fractures. It can also confirm that the fluid is not leaking from the formations where it is supposed to be isolated. This is more important from a public perception perspective than a technical one.

[0113] In some embodiments, options exist for sequestering carbon dioxide while generating geothermal energy. In other embodiments, carbon dioxide continues to be sequestered after the well has reached the end of its geothermal well life. In still other embodiments, geological conditions and economics may dictate that carbon dioxide sequestration begin only after the well is no longer a productive geothermal well. These options depend largely on factors such as the availability of sequestered carbon dioxide, tax credits and other incentives, and whether and how the carbon dioxide needs to be transported to the site.

[0114] Even if the analysis of measurements indicates that it is possible to create an underground volume filled with supercritical carbon dioxide for geothermal heat transfer, the geological conditions in some wells may not allow for complete carbon sequestration, and this possibility must be taken into account when considering the economics of geothermal projects.

[0115] Some other embodiments reverse the approach described above: the well is drilled for the purpose of using it for carbon sequestration and recoups the project costs through that use alone. Once supercritical carbon dioxide is injected into the well, instrumentation within the well provides the basis for a detailed evaluation of the well's potential as a geothermal well. If the formation is highly fractured, the supercritical carbon dioxide may dissipate quickly and not form a desirable cloud around the well for geothermal conduction. If the formation proves suitable for geothermal energy production, the concentric tubes of a closed-loop system are installed in the well.

[0116] Again, both technical considerations and market conditions and other economic factors will determine whether the well will be used simultaneously for sequestration and geothermal energy generation, or whether the geothermal stage will occur when the well nears the end of its useful life as a sequestration well.

[0117] In a sequestration well, the carbon dioxide will eventually fill the fracture system to the point that much higher pressures than would be desirable would be required to pump the carbon dioxide into the well. The carbon dioxide will also react with the rock, forming carbonate precipitates over time that will plug the natural fracture system. At that point, the well's useful life as a sequestration well will be over, but it may still be usable as a geothermal well.

[0118] When a combined-use well reaches its isolation capacity, it can be converted into a geothermal-only well by periodically injecting supercritical carbon dioxide and maintaining a cloud of heat-transfer fluid near the well as the fluid diffuses outward away from the well.

[0119] As mentioned above, ideal well conditions differ for geothermal power generation and carbon dioxide sequestration, so the phased approach described here requires careful analysis of factors such as directional well length, well diameter, and the presence or absence of casing.

[0120] An added benefit of using drill-in liners and leaving the drill bit in the well is that the well can be extended by simply adding more drill-in liners at the surface and restarting drilling as needed. This method can be used to extend the useful life of the well. The same approach applies if, after a geothermal well has been drilled and is in operation, the well needs to be extended to serve as an isolation well, or if an isolation well needs to be extended for geothermal use. Thus, the embodiments described herein offer flexibility not available with conventional drilling techniques.

[0121] It is easy to see that there is no problem if the CO2 sequestration well is drilled first, and then the closed-loop geothermal concentric tube is designed to be shorter than the CO2 sequestration well.The well can also be plugged at the end of the closed loop so that the supercritical CO2 injected thereafter continues to flow only underground around the closed loop.

[0122] The geothermal industry uses plume approaches to maximize heat gain. Also, drilling boreholes for closed-loop systems is easier when there is a suitable hot sedimentary rock formation and it is substantially horizontally oriented. However, the present invention is equally applicable to hot sedimentary rock formations as it is to the granite underlying the sedimentary rock. As mentioned above, granite contains decayed radioactive material and is part of the geothermal source. Therefore, drilling into the granite allows that heat to be utilized. Heat rising from the Earth's core is another source of geothermal heat, and naturally, the deeper the well, the closer it is to that heat. Once the well reaches the granite, it can continue drilling vertically for thousands of feet while remaining within the granite.

[0123] Therefore, some embodiments of the present invention use only vertical wells drilled using the drilling techniques described above, drilled thousands of feet into the granite rock, deeper than most geothermal wells. Because granite is highly fractured, these deep wells will intersect multiple natural fracture systems. This is in contrast to sedimentary hot rock formations, which are measured in feet of thickness and have only one major fracture system.

[0124] Another embodiment employs a directional well to drill from an offset location down to the granite formation. Drilling a vertical or directional well can result in significant cost savings compared to drilling a curve. Compared to drilling a horizontal well, it eliminates the need for a directional drilling crew and saves at least two trips of the bit.

[0125] 10, a well 1000 is drilled to the top of granite 1002 and cased 1004, after which a well 1006 is drilled through the granite 1010 using open-hole techniques and a drill-in liner 1008 to form an outer annulus 1012. Jet pumps 1020 and drill bits 1022 are used in some embodiments because they provide high penetration rates and are relatively low cost. The jet pumps 1020 and drill bits 1022 are left in the well because the cost of recovering them exceeds the cost of the units themselves.

[0126] Similar to previous embodiments, the concentric tubes 1024 are arranged to form a closed-loop system with the inner annulus 1028. In some embodiments, a first heat transfer fluid 1030 is pumped through the outer annulus 1012, as indicated by flow arrows 1032. It comes into contact with the uncase well 1006. Thus, the first heat transfer fluid 1030 begins to migrate into the natural fracture system within the granite 1010. As it expands in all directions, it forms a cloud 1034 of first heat transfer fluid 1030, filling the fracture system with an efficient means of transferring heat back from the rock formation to the well.

[0127] The closed-loop system then begins by pumping a second heat transfer fluid 1040 through the inner annulus 1028 between the drilled-in liner 1008 and the concentric tubes 1024, as indicated by flow arrow 1042. The second heat transfer fluid 1040 is pumped to the closed end 1010 of the drilled-in liner 1008, where it makes a U-turn and flows back up the concentric tubes 1024, as indicated by flow arrow 1044. Once the second heat transfer fluid 1040 reaches the surface, the heat carried by the heat transfer fluid can be used directly for heating or converted to electrical energy by a conventional system of heat exchangers and turbine-driven generators.

[0128] Whether the well is vertical, inclined, or directional, it is necessary to prevent the second heat transfer fluid 1040 from flowing out of the drill bit 1022, thus forcing the second heat transfer fluid 1040 to flow back up the concentric tubes 1024. In some embodiments, if the jet pump 1020 is installed directly behind the drill bit 1022, a plug 1046 is installed after the jet pump 1020 to force the second heat transfer fluid 1040 back up the concentric tubes 1024. In some other embodiments, where a jet pump 1020 is not used or is not present, a plug 1046 of rubber or similar material is installed in the well 1006, as the case may be, behind the drill bit 1022 or behind the jet pump 1020 to seal off the drill bit 1022 and prevent fluid loss.

[0129] These vertical or near-vertical embodiments have legal rather than technical advantages over horizontal wells. As previously mentioned, the laws of the United States and some other countries hold that pore space belongs to surface rights holders. Whether using the plume approach or the hybrid approach disclosed herein, the heat transfer fluid is injected into the pore space. By injecting fluid, horizontal wells may occupy pore space that is subject to the rights of multiple landowners. Clearly, vertical wells only require surface and pore space rights for a relatively small distance around the well.

[0130] By eliminating the complex issues of pore rights and the potentially high legal costs associated with securing them, the vertical-well approach to geothermal power generation becomes less expensive and more practical for smaller operations—an advantage that is even greater when it is desirable to locate geothermal plants close to urban or suburban areas where surface land ownership is highly fragmented.

[0131] Consider, for example, a natural gas-fired power plant. By some estimates, capturing the carbon dioxide emitted by the plant would require 10-15% of the energy it produces. Yet, the lack of a pipeline to transport the carbon dioxide to a sequestration facility makes such a project impractical in many cases. However, drilling a vertical well on land where the power plant already stands could not only sequester the plant's carbon dioxide emissions but also generate electricity using geothermal heat. In this way, the plant would produce the same amount of electricity as before, but that electricity would be carbon-neutral. Sequestering the carbon dioxide in horizontal wells on adjacent land would likely shut down such operations or be prohibitively expensive.

[0132] If the available well pad site is toward the property boundary, a deviated well can be utilized to inject the heat transfer fluid below the center of the property, thereby preventing the fluid from leaking beyond the property boundary into the pore space.

[0133] The vertical well embodiment, like the directional well embodiment described above, can be applied to geothermal-only wells using a hybrid method of injecting fluid into the pore space but not recovering it, as well as isolation wells and combined geothermal and isolation wells using a staged approach.

[0134] Various researchers have shown that granite not only contains multiple fractures, but that these fractures are interconnected, allowing fluids to flow underground. See, for example, Lihu Liu et al., "CO2 injection to granite and sandstone in experimental rock / hot water systems," Pergamon, Energy Conversion and Management 44 (2003) 1399-1410. This paper suggests on page 1 that "granite and / or sandstone may be capable of 'capturing' CO2 under hydrothermal conditions, and underground disposal may be a viable solution for reducing CO2 atmospheric emissions." This paper uses a plume approach to geothermal energy generation, injecting CO2 along with geothermal wastewater, which is far less efficient than the embodiments disclosed herein.

[0135] See also, Nohara Tsuyoshi et al., "Enhancement of Permeability Activated by Supercritical Fluid Flow through Granite," Wiley, Geofluids, Volume 2019, Article ID 6053815, https: / / d0i.0rg / l 0.1155 / 2019 / 6053815, which is incorporated herein by reference in its entirety.

[0136] In any of the above-described embodiments, whether a geothermal well or an isolation well is first, thermoelectric power generation can be added by taking advantage of the temperature difference between the surface of the well, or between near the surface and deep within. The Seebeck effect is the voltage that develops when there is a temperature difference at the contact point of two dissimilar conductive materials. For a discussion of this effect and how it can be used to generate power in geothermal environments, see "A Novel Approach for Downhole Power Generation in Geothermal Wells Using Thermoelectric Generator" by Jainish Shingala and Manan Shah, PROCEEDINGS, 45th Workshop on Geothermal Reservoir Engineering, Stanford University, Stanford, California, February 10-12, 2020 SGP-TR-216.

[0137] Thermoelectric power generation can be used in conjunction with various embodiments of the present invention to generate electricity to run pumps, direct carbon capture machines, and other devices. The potential for this additional power becomes apparent when considering operation in remote environments or where grid power is not fully reliable.

[0138] The above disclosure defines numerous embodiments of the present invention, which are described in detail in connection with the accompanying drawings. Those skilled in the art will appreciate that various changes, modifications, alternative constructions, arrangements, and other embodiments are possible in light of the teachings of the present invention without departing from the scope of the invention, which is defined in the following claims.

Claims

1. 1. A method of extracting geothermal energy from a well beneath the earth, comprising: drilling a well down to the hot rock formation with a drill bit and a drill string; forming an outer annulus between the drill string and the well; placing concentric tubing inside the drill string to form an inner annulus and a closed-loop fluid flow path; injecting the first heat transfer fluid from the outer annulus into the hot rock formation to form a first heat transfer fluid cloud within the hot rock formation; pumping a second heat transfer fluid from the inner annulus into the closed-loop fluid flow path and returning the second heat transfer fluid through the concentric tubes to the surface; converting the heat extracted by the second heat transfer fluid into usable energy; Including, The method, wherein the first heat transfer fluid is not withdrawn from the hot rock formation.

2. 10. The method of claim 1, wherein the injected first heat transfer fluid is water, brine, supercritical carbon dioxide, trapped exhaust gas, trapped exhaust gas dissolved in water, or trapped exhaust gas dissolved in supercritical carbon dioxide.

3. 10. The method of claim 1, wherein the first heat transfer fluid and the second heat transfer fluid are both supercritical carbon dioxide.

4. 2. The method of claim 1, further comprising priming the well with the first heat transfer fluid for a predetermined period of time prior to commencing geothermal extraction using the second heat transfer fluid, thereby forming a cloud of the first heat transfer fluid within the hot rock formation.

5. 10. The method of claim 1, wherein the hot rock formation well is drilled with formation-safe drilling techniques to prevent formation damage, including the use of lightweight drilling fluids.

6. 1. A method for combining geothermal power generation and carbon dioxide sequestration in the same well, comprising: drilling a commercially viable well down to the hot rock formation with a drill bit and drill string; forming an outer annulus between the drill string and the well; placing concentric tubing inside the drill string to form an inner annulus and a closed-loop fluid flow path; injecting the supercritical carbon dioxide from the outer annulus into the hot rock formation to form a cloud of supercritical carbon dioxide within the hot rock formation; pumping a heat transfer fluid from the inner annulus into the closed-loop fluid flow path and returning the heat transfer fluid to the surface through the concentric tubes; converting the heat extracted by the heat transfer fluid into usable energy; collecting data using at least one instrument located in the well to assess the amount of carbon dioxide trapped in the hot rock formation, and if the amount of trapped carbon dioxide exceeds a predetermined level, increasing the amount of supercritical carbon dioxide injected into the outer annulus to sequester a commercially significant amount of carbon dioxide; A method comprising:

7. 7. The method of claim 6, wherein the well is used for simultaneous geothermal power generation and carbon dioxide sequestration until geothermal power generation falls below a predetermined level, after which the well is used solely for carbon dioxide sequestration.

8. 7. The method of claim 6, wherein the well is used for simultaneous geothermal power generation and carbon dioxide sequestration until the well reaches its carbon dioxide sequestration life, after which the well is used exclusively for geothermal power generation.

9. 7. The method of claim 6, wherein the well is used solely for geothermal power generation for a period of time, and thereafter for simultaneous geothermal power generation and carbon dioxide sequestration.

10. 7. The method of claim 6, wherein the well is used exclusively for geothermal power generation until geothermal power generation falls below a predetermined level, after which the well is used exclusively for carbon dioxide sequestration.

11. 7. The method of claim 6, including priming the well with the supercritical carbon dioxide for a predetermined period of time prior to commencing geothermal extraction to form a cloud of the supercritical carbon dioxide within the hot rock formation.

12. 10. The method of claim 6, wherein the well is drilled with formation-safe drilling techniques to prevent formation damage, including the use of lightweight drilling fluids.

13. 1. A method for combining carbon dioxide sequestration and geothermal power generation in the same well, comprising: drilling a commercially viable well down to the hot rock formation with a drill bit and drill string; forming an outer annulus between the drill string and the well; injecting the supercritical carbon dioxide from the outer annulus into the hot rock formation to form a cloud of supercritical carbon dioxide in a region surrounding a directional section of the well within the hot rock formation; collecting data using at least one instrument located within the well; and if the heat flow exceeds a predetermined value, installing a concentric tube inside the drill string to form an inner annulus and a closed-loop fluid flow path. pumping a heat transfer fluid from the inner annulus into the closed-loop fluid flow path and returning the heat transfer fluid to the surface through the concentric tubes; converting the heat extracted by the heat transfer fluid into usable energy; A method comprising:

14. 14. The method of claim 13, wherein the well is used for simultaneous carbon dioxide sequestration and geothermal power generation until the well reaches its useful carbon dioxide sequestration life, after which the well is used exclusively for geothermal power generation.

15. 14. The method of claim 13, wherein the well is used for simultaneous carbon dioxide sequestration and geothermal power generation until the well reaches its useful life for geothermal power generation, after which the well is used solely for carbon dioxide sequestration.

16. 14. The method of claim 13, wherein the well is used solely for carbon dioxide sequestration for a period of time, and thereafter for simultaneous carbon dioxide sequestration and geothermal power generation.

17. 14. The method of claim 13, wherein the well is used exclusively for carbon dioxide sequestration until it reaches its useful carbon dioxide sequestration life, after which it is used exclusively for geothermal power generation.

18. 14. The method of claim 13, wherein the well is drilled with formation-safe drilling techniques to prevent formation damage, including the use of lightweight drilling fluids.

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