Optimized CO2 sequestration and enhanced geothermal systems

Abstract

Disclosed herein are various embodiments of systems for drilling and operating a well that can have dual uses. The well can be drilled and operated as a geothermal well using a hybrid approach, in which a heat transfer fluid is injected into a hot rock formation but not removed, and a closed-loop approach is used to extract the heat. The geothermal well is then evaluated for use as a carbon dioxide sequestration well. In other embodiments, the well is drilled as a carbon dioxide sequestration well and then evaluated for its potential for generating geothermal energy using a hybrid approach, in which supercritical carbon dioxide is injected into a hot rock formation but not removed, and a closed-loop approach is used to extract the heat. Both horizontal and vertical wells in sedimentary rocks and basement granite are disclosed.

Description

[0001] CROSS-REFERENCE TO RELATED APPLICATIONS

[0002] This application claims the benefit of U.S. Provisional Patent Application No. 63 / 255,325, filed on October 13, 2021, entitled “Optimized CO2 Sequestration and Enhanced Geothermal System,” inventor William James Hughes, applicant Hughes Tool Company LLC, attorney case number HTC-P-107, the entire contents of which are incorporated herein by reference.

[0003] This application is related to U.S. Utility Patent Application No. 17 / 113,005, filed on December 5, 2020, entitled "Annular Pressure Cap Drilling Method," inventor William James Hughes, assignee Hughes Tool Company LLC, attorney docket HTC-101. Utility Patent Application No. 17 / 113,005 was published on June 10, 2021, as U.S. Utility Patent Application Publication No. US2021 / 0172273, and on February 22, 2022, as U.S. Patent No. 11,255,144, the entire contents of which are incorporated herein by reference. It is a continuation of U.S. Patent Application No. 17 / 556,825, filed on July 5, 2022, as U.S. Patent No. 11,377,919, the entire contents of which are incorporated herein by reference.

[0004] This application relates to PCT International Patent Application No. PCT / US2020 / 063522, filed on December 6, 2020, entitled “Annular Pressure Cap Drilling Method,” inventor William James Hughes, applicant Hughes Tool Company LLC, attorney case number HTC-PCT-101, and published as PCT International Application Publication No. WO 2021 / 119995, the entire contents of which are incorporated herein by reference. Technical Field

[0005] Various embodiments described herein relate to drilling wells for carbon dioxide sequestration and geothermal energy generation, and apparatus, systems, and methods associated therewith. Background Art

[0006] Background Technology - Geothermal Energy

[0007] Geothermal energy, energy generated within the Earth as heat, has been known and used for centuries. In many parts of the world, this energy reaches the surface in the form of geysers, hot springs, and natural steam vents. Water seeps through the earth until it reaches hot rock, where it becomes superheated and turns into steam. The superheated water and steam then reach the surface through natural faults and fissures. The most famous examples occur in areas such as Iceland, Napa Valley, and other regions where there are hot rocks close to the surface, or large areas of superheated rock deep beneath the surface (called hot spots). The most famous of these, at least in the United States, is the Yellowstone hot spot.

[0008] In recent years, geothermal energy has been used for small-scale projects (such as heating individual homes) and commercial-scale projects for heating entire housing developments or industrial buildings. These projects involve relatively shallow heat sources and rely on the fact that the earth maintains a relatively constant temperature a few feet below the surface. Larger-scale projects can tap into the earth's heat in much deeper layers, thousands of feet deep. The heat in the deeper layers is transferred to the surface by heating injected water and using the water in the form of steam to drive turbines and generators to generate electricity. At such depths, the temperature of the rock can reach hundreds of degrees.

[0009] With rising fossil fuel prices and predictions that fossil fuel reserves are rapidly depleting and will soon be exhausted, geothermal energy has gained increased attention. Recent developments in oil and gas production, particularly the ability to extract reserves from dense formations through hydraulic fracturing, have reduced the sense of urgency. These new technologies are essentially just delaying the inevitable. At some point in the future, recoverable hydrocarbon reserves will be depleted. Therefore, it makes sense to begin converting to geothermal energy now rather than waiting for hydrocarbon reserves to decline.

[0010] Concerns associated with global warming, of which fossil fuels are the primary cause, provide additional incentives for research into geothermal energy. Improving recovery rates through hydraulic fracturing ("fracing") and other techniques could help alleviate this problem in the short term, replacing coal-fired power stations with gas-fired ones. However, this coal will likely be burned somewhere, and some predict that due to the continued expansion of coal-fired power plants in China and India, coal could overtake oil as the world's leading fossil fuel within a few years. Anything that can offset the associated increase in emissions will help. Geothermal energy production does not add significant amounts of greenhouse gases to the atmosphere. Geothermal power generation can replace electricity generated by coal-fired power plants, thereby reducing emissions and slowing global warming.

[0011] While fracking makes it possible to extract previously unrecoverable hydrocarbon reserves, currently used fracking techniques require large quantities of water. Obtaining water rights can be an issue in many regions, particularly in the western United States, where water resources have long been a contentious issue. There's also the question of what to do with the water once the fracking procedure is complete and pumped back from the well. The impact of fracking on water supplies has raised environmental concerns. In some embodiments, including those described herein, geothermal energy production can be achieved without the use of large quantities of water.

[0012] Other patents and patent applications by the inventors of the technology described herein, in U.S. utility patent application publication US2021 / 0172273 (hereinafter referred to as the "'273 disclosure"), entitled "Annular Pressure Cap Drilling Method," inventor William James Hughes, applicant Hughes Tool Company LLC, show how oil and natural gas can be produced without the need for hydraulic fracturing and without the need for large amounts of water and chemical additives. Additional benefits of these technologies include better production and better consumption curves, as well as significantly reduced overall costs. As the world shifts to renewable energy, these technologies are also part of the near-term solution. However, the drilling techniques disclosed in those patents and patent applications, particularly the concept of not causing damage to the wellbore by using a near-balanced drilling method, are also applicable to drilling for geothermal energy projects.

[0013] Compared to other renewable energy sources like solar or wind, geothermal power generation offers the added benefit of providing a reliable energy supply at any time of day or night, independent of weather conditions. The amount of energy produced can be controlled and varied, making geothermal energy production a potential backup for other less consistent forms of energy, or where demand varies by season or time of day. In regions like the western United States, where large expanses of hot rock exist at relatively shallow depths, the potential for developing geothermal energy is enormous. Globally, few areas are inaccessible to geothermal energy development given the right methods and expertise.

[0014] The heat extracted from hot rocks through geothermal energy production is replaced by heat created by the decay of radioactive elements in the Earth's crust and by primordial heat flowing from deeper layers of the Earth. Therefore, the energy generated by geothermal technology, whether directly in the form of heat or indirectly in the form of electricity, is a renewable resource. This means that geothermal energy projects may be eligible for subsidies and tax credits and will be attractive to states and other organizations with a goal of generating a certain percentage of their total energy consumption from renewable sources.

[0015] Another advantage of geothermal energy production is that compared to other energy production methods, the amount of land dedicated to energy production is much smaller. The power generation equipment, pumps, and other components occupy relatively little space. Most of the hardware is underground, and it can be located just as easily beneath urban or suburban areas as it can beneath vast farmland or forests. This stands in stark contrast to solar and wind farms, both of which require large tracts of land dedicated to energy production. Furthermore, geothermal energy production has minimal visual impact. Solar farms have sparked some protests, and wind farms, with their massive arrays of turbines, are considered by many to be visually disruptive to the landscape and a threat to birds. Consequently, wind and solar farms are often located in remote areas, far from where the electricity is used. This increases the cost of generating and transmitting electricity and requires miles of transmission lines, which many consider visually polluting.

[0016] In some geothermal areas, steam-like or superheated water naturally emerges from fractures, forming geysers and hot springs. These heat sources are often intermittent and can be unreliable and inconsistent. Early geothermal projects drilled into hot water aquifers to extract energy. Many of these projects now produce far less energy than their peak capacity. In some cases, heat flow is insufficient to replenish the extracted heat, or the aquifer is depleting its hot water. In either case, pumping water from the aquifer is clearly unsustainable in the long term.

[0017] It might be appropriate to describe the use of these naturally hot water sources as "passive" geothermal energy, as all that is required is the heat brought to the surface by natural water flows. In less fortunate locations seeking geothermal energy, various methods have been devised to extract heat from deep underground and bring it to the surface. These techniques typically involve pumping a heat transfer fluid into the hot rock formations and then pumping it out after the fluid has absorbed the subsurface heat. Thus, energy is expended to generate it. We can characterize these techniques as "active" geothermal energy.

[0018] Modern active geothermal energy projects can be divided into two groups. The first group comprises methods in which a fluid (usually water) is pumped down into a hot rock formation from an injection well, allowed to migrate through the hot rock, collecting heat as it goes. The fluid is then captured by an extraction well located some distance vertically above the injection well and pumped back to the surface, where the heat is used directly or converted into electricity. Wells are now typically drilled horizontally to maximise the volume of hot rock exposed to the fluid and to take advantage of natural fractures in the earth, which are generally predominantly vertical. The hope is that the heated fluid will migrate upwards by convection, transferring the heat upwards. In practice, the fluid becomes dispersed throughout the natural fracture system and only a small fraction reaches the extraction well.

[0019] This is sometimes called the "plume" approach. It requires large amounts of fluid, and because the injected fluid is dispersed throughout the rock matrix, much of it cannot be recovered. Like smoke rising on a hot day, the plume becomes wider as it rises. So, while it might seem logical to increase the amount of heat captured by increasing the vertical distance between the injection and extraction wells, the greater the vertical distance, the more dispersed the plume becomes, and therefore less fluid reaches the extraction well.

[0020] It has been suggested that carbon dioxide (CO2) could be used as the injection fluid, and this does have some advantages. The thermal properties of CO2 are superior to those of water, and the fluid actually remains in the rock formation, which is a form of carbon sequestration.

[0021] In some geothermal operations, to create better fluid flow from injection wells to extraction wells, the rock between the wells is hydraulically fractured to strengthen the natural fracture system and increase flow rates between the injection and extraction wells. This technique is known as "enhanced" geothermal energy generation. Like hydraulic fracturing used in oil and gas production, hydraulic fracturing is typically applied after the natural fracture system has been disrupted when drilling a well using traditional overbalanced drilling techniques. There is also some question as to whether the hydraulic fracturing process actually strengthens the natural fracture system or simply pushes large volumes of drilling mud further into the fractures, actually reducing overall permeability.

[0022] While hydraulic fracturing of geothermal wells doesn't release methane like can happen when drilling for hydrocarbons, it still requires large amounts of water, and chemicals are often added to improve the effectiveness of the fracking operation. This is a serious drawback, especially in areas such as the American Southwest, where hot rock formations are accessible but water is a scarce and highly contested resource.

[0023] Geothermal energy generation has already had adverse effects on land stability. For example, subsidence has occurred in the Wairakei oil field in New Zealand. In some seismically active areas, injecting large amounts of water can cause earthquakes by lubricating existing faults and causing them to slip. A geothermal project in Basel, Switzerland, was suspended after more than 10,000 seismic events, some as high as 3.4 on the Richter scale, were observed during the first six days of drilling.

[0024] These effects can be exacerbated when hydraulic fracturing is used to enhance the flow of hot water. For these reasons, many places have included hydraulic fracturing of geothermal wells in comprehensive "fracking bans." In areas opposed to fracking, it can be nearly impossible to convince communities that some types of fracking are less harmful than others. These bans make the development of geothermal resources problematic and are often imposed in more densely populated areas where clean energy is most needed.

[0025] 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. Geothermal energy does produce much less carbon dioxide than using fossil fuels, but the problem cannot be ignored. Hydrogen sulfide and ammonia are dangerous in anything but trace amounts. These gases also contribute to the formation of acid rain. Therefore, geothermal power plants that use injection and recovery methods must be equipped with emission control systems and, in some cases, carbon sequestration systems should also be installed to reduce the amount of carbon dioxide introduced into the atmosphere.

[0026] Hot water pumped up from deep within the Earth can contain large amounts of dissolved minerals that can damage turbines and power generation equipment. Some of these substances include mercury, arsenic, boron, antimony, and salt (sodium chloride). As the water cools, these substances fall out of solution. These substances must be disposed of responsibly to prevent environmental damage. This is usually done by reinjecting them back into the Earth along with the water used for the geothermal process.

[0027] A second active geothermal energy production method uses water or other fluids pumped through pipes within hot rock formations. These are known as closed-loop systems because all fluids pumped into the well are contained within the underground pipes and can be recovered and reused. This method presents its own set of problems, one of which is the formation of vapor pockets, or the conversion of water to steam earlier than optimal within the pipe system. These vapor pockets block the flow of water and can significantly reduce the efficiency of the geothermal heat transfer process.

[0028] There are two variations of the closed-loop method. One uses a single well and concentric piping to deliver the heat transfer fluid down a vertical wellbore and then down a directional wellbore. At the end of the wellbore, the heat transfer fluid makes a U-turn and flows back up the wellbore within the concentric piping. The advantage of this method is that it requires only a single surface point and a single wellbore.

[0029] A second variation of the closed-loop approach also uses piping to transport the heat transfer fluid down a vertical wellbore and then down a directional wellbore, but the fluid is returned to the surface via a second vertical wellbore. Once the fluid reaches the surface, it is then pumped back to the injection wellbore via surface or shallow pipelines. Heat extraction typically occurs once the fluid reaches the surface. Of course, this approach requires two surface locations and introduces permitting issues for the return line.

[0030] The closed-loop approach does eliminate the issues of induced seismicity and contamination of extracted fluids. However, it does have two major weaknesses. The surface area of ​​the pipe in contact with the hot rock is relatively small, and the heat from the rock surrounding the pipe is rapidly depleted. In other words, heat is removed from the rock surrounding the pipe and transferred to the surface faster than it is replenished by heat flowing in from the surrounding rock. Operators have addressed the first issue by drilling longer wellbores and installing longer pipes. The second issue is still more problematic. One solution is to drill a series of wellbores radiating outward from the same surface location, then sequentially operate each well for a fixed period of time, so that one well is generating geothermal energy while the others are producing. This works well with a single vertical well approach, but a dual vertical well approach introduces further challenges. Of course, this significantly increases the cost and complexity of the installation, changing the project's economics. Other proposed solutions are even more complex, such as a parallel dual-well system with opposing flow directions and heat exchange facilities at both surface locations.

[0031] Background Technology - Carbon Sequestration

[0032] The second component of this invention involves carbon sequestration, the process of permanently storing carbon dioxide in geological formations, removing it from the atmosphere and preventing it from contributing to global warming. Scientists generally agree, and the public is increasingly accepting this, that converting energy use to renewable sources is insufficient. The Earth has reached a point where, to avoid a catastrophe, the warming process must be reversed and massive amounts of carbon dioxide removed from the atmosphere.

[0033] This fact sheet does not cover the technologies used to capture CO2. A wealth of information is available on this topic, and new methods are constantly being developed. For the purposes of this fact sheet, it is important to note that there are two main sources of CO2 for storage.

[0034] The first source is capturing CO2 at the point of generation. This includes obvious sources such as fossil fuel-burning power plants, cement plants, and steel mills. It can also include smaller CO2 generators, such as breweries. Ideally, CO2 would be sequestered at the point of generation, but currently, most captured gas is transported to sequestration facilities via dedicated pipelines. The amount of CO2 currently captured and sequestered is severely limited by a lack of on-site sequestration capacity and limited pipeline availability.

[0035] The second source is so-called direct air capture, which involves extracting carbon dioxide from the atmosphere. This is typically achieved by passing large volumes of air through machines similar to large air conditioners. Of course, these machines require some form of energy to power them, in some cases natural gas or natural gas-fired electricity. Naturally, the first step is to capture the carbon dioxide emitted while generating this energy.

[0036] Once the CO2 has been captured, it can be pumped into underground rock formations for permanent storage. This process is called "carbon sequestration." It's important to note that the goal of sequestration is to permanently dispose of the CO2. This is not entirely the same as injecting CO2 into oil and gas wells for secondary and tertiary recovery of more hydrocarbons (a process with a long and successful track record). Some operators do pump more CO2 underground than is needed for hydrocarbon recovery, and this can count as a form of sequestration.

[0037] Because initial sequestration attempts often used available oil and gas wells that had reached the end of their productive lives, this was often assumed to be the best, or even the only, approach. However, using the drilling techniques described in the referenced patent applications, wells can be efficiently and economically drilled solely for the purpose of carbon sequestration. Thus, no pipelines are required to transport the carbon dioxide from its generation point to its disposal site. For example, a cement plant or power plant not located near an oil or gas field could have its own dedicated carbon sequestration well.

[0038] In contrast, if an oil or gas field happens to be located several miles from any convenient method of transportation (such as a pipeline or transfer station), it can be developed for the purpose of generating energy to operate carbon capture machinery and dispose of the CO2 on-site, with the option of using some of it for secondary and tertiary recovery. The economics of remote hydrocarbon discoveries have changed significantly with the addition of carbon capture tax credits or carbon trading programs.

[0039] However, it's important to remember that using old oil and gas wells may not be ideal. Certainly, those who profit from them strongly advocate their use. But these wells are almost certainly drilled with large amounts of drilling mud, which clogs the rock formation. They may also be subjected to hydraulic fracturing, which causes further formation damage. They are largely cased, so that the only place where CO2 can contact the formation is in a limited section of the wellbore that has been perforated. Perforation also causes formation damage, including compaction of the rock surrounding the perforation zone. Over years of production, fines migration may have sealed off much of the permeability around the wellbore. And although these wells are close to pipelines that transport oil and gas, they may not have pipeline infrastructure in place to bring the CO2 to the wells. The cost of creating such infrastructure may offset the benefits of using these depleted wells, except in infrastructure-intensive areas such as the Permian Basin.

[0040] Background Technology - Drilling

[0041] Compared to traditional drilling techniques, both geothermal well drilling and carbon sequestration well drilling benefit significantly from the near-balanced drilling techniques described in the cited patent application, i.e., lower costs and faster drilling speeds. However, the greatest benefit is that these drilling techniques avoid formation damage during the drilling process. Natural fracture systems are not clogged by large amounts of drilling mud, and the permeability of natural fracture systems within the rock formation is maintained. This improves fluid flow and enhances heat transfer in geothermal applications. It also improves the well's ability to disperse carbon dioxide into the formation, increasing the well's sequestration capacity and extending its service life.

[0042] Using drilling techniques that don't compromise the permeability and storage capacity of the natural fracture system offers the added benefit of eliminating the need for hydraulic fracturing to undo the damage caused by traditional drilling techniques. This approach not only reduces overall costs but also eliminates the large amounts of water, sand, and chemicals required for hydraulic fracturing.

[0043] A method is desired that combines and optimizes both carbon sequestration capacity and geothermal energy generation, thereby achieving the greatest possible environmental and financial return on investment per well. Summary of the Invention

[0044] In one embodiment, a method for extracting geothermal energy from a well below the Earth's surface is provided, comprising: drilling a well down into a hot rock formation using a drill bit and a drill string, creating an outer annulus between the drill string and the formed wellbore; installing a concentric pipe inside the drill string to create an inner annulus and a closed-loop fluid flow path; injecting a first heat transfer fluid down the outer annulus into the hot rock formation to create a cloud of the first heat transfer fluid within the hot rock formation, wherein no first heat transfer fluid is recovered from the hot rock formation; pumping a second heat transfer fluid down the inner annulus into the closed-loop fluid flow path and back to the surface through the concentric pipe, and converting heat collected by the second heat transfer fluid into usable energy.

[0045] In another embodiment, a method for combining geothermal energy generation and carbon dioxide sequestration in the same well is provided, comprising: drilling a commercially viable geothermal well down into a hot rock formation using a drill bit and drill string, creating an outer annulus between the drill string and the formed wellbore; installing a concentric pipe inside the drill string to create an inner annulus and a closed-loop fluid flow path; injecting supercritical carbon dioxide down the outer annulus and into the hot rock formation to create a mass of supercritical carbon dioxide within the hot rock formation; pumping a heat transfer fluid down the inner annulus into the closed-loop fluid flow path and returning to the surface through the concentric pipe; converting heat collected by the heat transfer fluid into usable energy; and collecting data using at least one instrument positioned within the well to assess the amount of carbon dioxide captured within the hot rock formation, and if the amount of captured carbon dioxide is above a predetermined level, increasing the amount of supercritical carbon dioxide injected into the outer annulus to sequester carbon dioxide in commercially significant amounts.

[0046] In another embodiment, a method for combining carbon dioxide sequestration and geothermal energy generation in the same well is provided, comprising:

[0047] A commercially viable carbon sequestration well is drilled down into a hot rock formation using a drill bit and drill string, creating an outer annulus between the drill string and the formed wellbore; supercritical carbon dioxide is injected into the hot rock formation through the outer annulus to create a mass of supercritical carbon dioxide in a directional section surrounding the wellbore within the hot rock formation, thereby sequestering the supercritical carbon dioxide; data is collected using at least one instrument positioned within the well to measure heat flow and or; in the event that the heat flow rate exceeds a predetermined value, a concentric tube is installed within the drill string to create an inner annulus and a closed-loop fluid flow path surrounding the concentric tube; a heat transfer fluid is pumped down along the inner annulus into the closed-loop fluid flow path and returned to the surface through the concentric tube, and heat collected by the heat transfer fluid is converted into usable energy, or in the event that the heat flow rate is below a predetermined value, the well continues to be used solely as a carbon sequestration well.

[0048] Further embodiments are disclosed herein or will become apparent to those skilled in the art upon reading and understanding the specification and drawings. BRIEF DESCRIPTION OF THE DRAWINGS

[0049] Various aspects of various embodiments of the present invention will become apparent from the following description, drawings, and claims, in which:

[0050] Figure 1A shows the basic method of active heat extraction;

[0051] FIG1B shows heat extraction using a perforated section of casing;

[0052] FIG2 illustrates the plume method of geothermal extraction using a directional well;

[0053] FIG3 illustrates the plume method of geothermal extraction from a vertical well using a directional well;

[0054] Figure 4 shows a single-well closed-loop approach to geothermal extraction;

[0055] Figure 5 A radial system of multiple directional wells for geothermal extraction is shown;

[0056] Figure 6 shows a dual-well closed-loop method for geothermal extraction;

[0057] Figure 7 The first stage of drilling a geothermal well or a sequestration well is shown;

[0058] Figure 8 The final stages of drilling a geothermal or sequestration well are shown;

[0059] Figure 9shows a well configured for geothermal energy production and carbon sequestration; and

[0060] Figure 10 Shown is a vertical well drilled into a granite formation and configured for geothermal energy production and carbon sequestration.

[0061] The accompanying drawings are not necessarily drawn to scale. Throughout the accompanying drawings, like numbers refer to like parts or steps. DETAILED DESCRIPTION

[0062] In the following description, specific details are provided to provide a comprehensive understanding of the various embodiments of the present invention. However, upon reading and understanding the specification, claims, and drawings, one skilled in the art will understand that some embodiments of the present invention may be practiced without following some of the specific details set forth herein. Furthermore, to avoid obscuring the present invention, some well-known methods, processes, devices, and systems that find application in the various embodiments described herein have not been disclosed in detail.

[0063] With reference now to the accompanying drawings, embodiments of the present invention will be described. The present invention may be implemented in a variety of ways. Several embodiments of the present invention are discussed below. The accompanying drawings illustrate only typical embodiments of the present invention and, therefore, should not be considered limiting of its scope and breadth. The accompanying drawings illustrate some, but not all, possible embodiments, and may not be shown to scale.

[0064] Any embodiments or applications of the present invention provided herein are intended to be illustrative and not limiting.

[0065] Throughout this document, the term "directional well" or "directional wellbore" is defined to refer to a well or wellbore that can be described as oriented, horizontal, substantially horizontal, deviated, inclined, skewed, or following a particular subsurface formation. The term is used to distinguish such a well or wellbore from a substantially vertical well or wellbore.

[0066] Turning now to the figures, consider first a well drilled for geothermal energy generation using the plume method. FIG1A shows the simplest method of active geothermal extraction. It simply involves pumping a heat transfer fluid 100 (typically water) into a vertical injection well 102 using an injection pump 104 and injecting the heat transfer fluid 100 into a hot rock formation 106, where it will absorb heat. The heat transfer fluid 100 is then pumped out of a vertical extraction well 108 using an extraction pump 110, which is typically slightly higher in the hot rock formation 106 and, hopefully, at a much higher temperature. The heated fluid can be used directly to operate a steam turbine to generate electricity. In other embodiments, the heated fluid passes through a heat exchanger and the heat is used to create steam to drive a turbine generator. In theory, as indicated by flow arrows 112, most of the injected heat transfer fluid 100 will flow to the extraction well 108 and be captured by it. However, in practice, it will be apparent to one of ordinary skill in the art that when the injected heat transfer fluid 100 is released from the vertical injection well 102, it will quickly disperse through the natural fracture system, as indicated by the flow arrows 114, and very little of the heat transfer fluid will reach the extraction well 108. Therefore, this approach is not very effective.

[0067] There are ways to increase efficiency, such as surrounding the injection well with a ring of extraction wells, or vice versa. This increases complexity at the surface, as the heat transfer fluid may need to be pumped to a central heat extraction unit, or other steps may need to be taken to accumulate the extracted energy. Another enhancement might be to offset the injection wells so that the heat transfer fluid is injected directly below the extraction well, but again, dispersion through the natural fracture system will limit the amount of heat captured.

[0068] Another possible enhancement is shown in FIG1B , where only one well 120 is required, and heat extraction is accomplished using a perforated section of outer casing 122 that is concentric with a fluid injection pipe 124. A heat transfer fluid 126 is pumped downwardly into the hot rock formation 106 along the fluid injection pipe 124 as indicated by flow arrows 126, and as the heat transfer fluid flows upwardly around the perforated outer casing 122 as indicated by flow arrows 128, it is drawn by an extraction pump through the perforations and upwardly along the annulus between the outer casing 132 and the fluid injection pipe 124 as indicated by flow arrows 130.

[0069] With modern drilling technology, it makes sense to drill horizontal or near-horizontal wells to maximize exposure of the heat transfer fluid to the hot rock formation. One possible embodiment of this approach is shown in FIG2 . A heat transfer fluid 200 is pumped down an injection well 202 having a vertical section 204 and a directional section 206. The heat transfer fluid is released 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 toward the directional section 210 of the extraction well 212, as indicated by flow arrows 214. It is then pumped out of the vertical section 216 of the extraction well 212 and delivered to a turbine or heat exchanger to generate electricity.

[0070] 3 shows a variation of this approach that uses one 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 down the injection well 302 and up from the extraction well 304.

[0071] As mentioned above, it's common practice to attempt to achieve higher heat extraction rates through the use of hydraulic fracturing. The idea is that if the rock is more fractured, more water will flow from the injection well to the extraction well. The risk is that hydraulic fracturing will open up the natural fracture system, effectively diverting the heat transfer fluid away from the desired vertical path.

[0072] FIG4 illustrates the closed-loop method. In FIG4 , a vertical wellbore 400 is drilled, and a directional wellbore 402 is drilled from the vertical wellbore 400 into the hot rock formation 106. Concentric tubing 404 is installed so that a heat transfer fluid can be pumped down the vertical wellbore 400 and along the directional wellbore 402 to the end of the wellbore 406, as indicated by flow arrows 408. The fluid then makes a U-turn and returns upward along the annulus 410 between the concentric tubing 404 and the wellbore 400, as indicated by flow arrows 412. No heat transfer fluid is released into the surrounding hot rock formation 106. The theory behind this method is that the heat flow from the surrounding rock will be sufficient to supplement the heat extracted and transferred to the surface.

[0073] In practice, this doesn't seem to work as well as hoped, as heat from the surrounding hot rock layers is quickly dissipated, and various methods have been tried to enhance heat transfer. Extending 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 in the well, the more powerful the pumps must be to keep it circulating.

[0074] like Figure 5As shown, 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 well pad, utilizing a central pump and generator facility 500. This not only greatly increases the subsurface volume from which heat is extracted, but also allows some directional wells to recover from heat depletion while others remain in production. Note that the radial spacing of the wells and the length of the wells will not be the same from well to well, but will be determined by the geology and available hot rock zones. Figure 5 A plan view is shown, but one of ordinary skill in the art will appreciate that multiple injection and extraction wells may also be drilled at different depths.

[0075] FIG6 shows a different closed-loop approach, in which the injection well 602 and the extraction well 604 are spaced a considerable distance apart, allowing for a long directional component 606 to the wellbore, which should translate into more heat being collected by the heat transfer fluid 608 as it passes through the hot rock formations. Drilling the wells shown requires complex drilling techniques, which means high costs. A vertical well must be drilled at each location, with the drill bit deviated at 610 and 612 to drill horizontally, and the two wellbores must meet 614 with a precision that is difficult to achieve at the depth required for geothermal wells. The heat transfer fluid 608 is pumped down the injection well 602 by pump 620 and out of the extraction well 604 by pump 622. At 624, after the heat brought to the surface is used to generate electricity, the cooled heat transfer fluid 608 is pumped back along a pipe 626 and stored in a tank 628, from which it is pumped back around the loop.

[0076] The dual-well closed-loop approach can be applied to radial or grid systems, again with the goal of providing continuous power generation capability by using some loops while others recover from local heat losses.

[0077] Closed-loop methods sometimes encounter problems when using water as the heat transfer fluid. As superheated water approaches the surface, pressure decreases, and the water can then transform into steam, creating vapor pockets that impede flow and can adversely affect pump operation. Similar problems caused by cavitation can occur at the end of a directional wellbore when the fluid is forced to rapidly change direction.

[0078] While all of these approaches sound promising, geothermal energy generation has yet to truly impact the overall energy mix. For plume methods, dispersion of injected fluids is often overlooked or underestimated. In closed-loop methods, the most likely culprit is the rapid dissipation of heat in the rock near the wellbore, or in the area where fluids are injected and extracted. Ultimately, rock is an insulator. If heat is removed quickly, the rock cools and becomes subject to thermal stresses. In plume methods, this does promote more fractures and, therefore, more fluid flow, but the impact is relatively minor.

[0079] Consider now the present invention, which solves the previously discussed and other problems associated with previous geothermal technology. Additionally, various embodiments are disclosed in which geothermal wells are combined with carbon dioxide sequestration wells to maximize return on investment and extend the useful life of the wells.

[0080] As previously mentioned, some geothermal wells pump water or fluid into the rock formation and hope to reclaim some of the plume of heated fluid (which usually comes from different wells). Other geothermal technologies use closed-loop systems, in which heat transfer fluid is pumped down along a pipe and then returned to the surface through the same well or different connecting wells, but without the fluid being released into the rock. As outlined above, both methods have their shortcomings. In order to overcome these shortcomings, the present invention has adopted a hybrid approach.

[0081] The embodiments disclosed herein inject a heat transfer fluid into the surrounding rock formation, as is done in the plume method. A significant feature of this hybrid method is that the injected fluid is not recovered at any point in the process. It is allowed to fill the natural fracture system and form a mass around the wellbore, where it acts as a conductive heat transfer mechanism. In this method, there is no injected or naturally occurring fluid to be recovered from the subsurface. Therefore, there is no need for equipment to dispose of dissolved gases or minerals in the captured fluid, as occurs in the plume method.

[0082] Rather than attempting to capture heat within an expanding plume of injected fluid, the present invention relies on extracting heat conducted toward the wellbore by injected and / or naturally occurring fluids that are filling or have already filled (i.e., formation water) the natural fracture system surrounding the wellbore. Heat extraction utilizes concentric pipes in a closed-loop method, carrying the heat transfer fluid to the end of the wellbore in one pipe and from there back along another concentric pipe.

[0083] This combination of plume and closed-loop technology overcomes a common problem with closed-loop systems, in which heat recovery rates decrease as heat from the nearby surrounding rock is transferred to the fluid in the closed loop and, therefore, to the surface. In this system, the injected fluid acts as an efficient heat transfer mechanism. The volume of rock filled with the injected fluid expands, increasing the available geothermal energy. The rate at which the injected fluid flows out of the wellbore is slower than the rate at which heat is conducted inward from the rock volume into the wellbore because heat is allowed to flow from hot to cold. While there is some heat conduction through the rock, the majority of the heat reaching the wellbore is transferred through the injected fluid fill, which was previously present in the natural fracture system.

[0084] Figure 7The initial stages of drilling a geothermal energy well 700 are shown. Using techniques made possible by advances in directional well drilling, a well is drilled in a suitable rock formation, wherein the well comprises a vertical section 702, a casing 704, and a bend 706 that transitions to a directional wellbore 708. The preferred embodiment of the present invention drills into granite 710 bedrock, which is found everywhere, albeit at varying depths. Granite is hard, brittle, and naturally highly fractured. Importantly, granite contains uranium and other radioactive heavy elements, which decay and, as they do, generate heat for geothermal energy projects. Of course, it is possible to use all of the techniques disclosed herein in sedimentary rock formations.

[0085] The vertical section 702 of the well 700 can be drilled using conventional drilling methods. In this regard, conventional techniques using drilling mud are not disadvantageous because there is no need to avoid formation damage. The vertical section 702 of the well 700 typically uses a US industry standard casing 704 having a diameter of 9 5 / 8". Once the target formation has been reached, Figure 7 In certain embodiments, the vertical section 702 and the curved section 706 are drilled using an electric drilling motor.

[0086] like Figure 8 As shown, the directional section 802 of well 700 is always drilled in an underbalanced or near-balanced condition to avoid the formation damage typically caused by using large amounts of drilling mud. For a detailed description of how to safely achieve this using annular pressure-controlled flow diverters and near-balanced reservoir drilling (NBRD), see the '273 publication. The techniques disclosed in the '273 publication are used to ensure that no fluids, including water, radon gas, or even hydrocarbons, escape from the well during drilling. Because the natural fracture system in the hot rock formation is not damaged during the NBRD method, hydraulic fracturing or other remedial treatments are not required.

[0087] exist Figure 8 In the illustrated embodiment, a directional section 802 of the well 700 is drilled using a drilled liner 804, which in the United States may have a diameter of 5.5 inches. A drill bit 806 has a significantly larger diameter, approximately 10 inches. In a technique known as open hole drilling, no casing is placed in the directional section 802. The wellbore 808 will have the same diameter as the drill bit, and thus an annulus 810 will be created between the horizontal section of the drilled liner 804 and the surface of the wellbore 808. An annulus 818 will also exist between the casing 704 and the vertical section of the drilled liner 804.

[0088] In some embodiments, a jet pump 820 is mounted behind the drill bit 806. The jet pump creates a strong suction force that clears debris from the area in front of the drill bit and enables high penetration rates. For a description of how a jet pump can be used to create a vacuum in front of the drill bit, thereby creating a true underbalanced condition in front of the drill bit to avoid formation damage, see U.S. Patent No. 11,168,526, entitled "Jet Pump Drilling Assembly," inventor William James Hughes, assignee Hughes Tool Company LLC, the entire contents of which are incorporated herein by reference.

[0089] Figure 9 A geothermal well is shown after drilling is complete. In embodiments using a drilled liner 804, the drilled liner 804 is a key component of the closed loop system and remains in place when drilling is complete. Therefore, the drill bit 806 and the jet pump 820 also remain in the wellbore 808. This is done in part to eliminate the costs associated with recovering the drill bit 806 and the jet pump 820. It also creates the possibility of extending the wellbore 808 at a later time to extend geothermal energy production or to prepare the well for carbon sequestration. A small diameter concentric pipe 902 is installed inside the drilled liner 804, creating an inner annulus 904 between the drilled liner 804 and the concentric pipe 902. In some embodiments, the pipe 902 is a vacuum insulated pipe.

[0090] Once the well is drilled and the concentric tubes are installed, the next step is to put the well into operation. In some embodiments, the first heat transfer fluid 920 is pumped downwardly into the directional annulus 810 along the outer vertical annulus 818. It will contact the wellbore 808 without cased tubing. Therefore, the first heat transfer fluid 920 will begin to migrate into the natural fracture system within the subsurface, as shown by flow arrows 921. When the first heat transfer fluid 920 expands in all directions, it will create a group 922 of the first heat transfer fluid 920, thereby filling the fracture system with an effective means of conducting heat from the rock formation back to the wellbore. In existing closed-loop systems, the outer surface of the concentric tube system is in contact with the rock formation, which is an insulator. In the present invention, using open hole drilling means that the outer surface of the concentric tube is surrounded by the first heat transfer fluid 920 in the directional annulus 810, and the directional annulus is in direct contact with the first heat transfer fluid 920 contained in the rock formation.

[0091] The closed loop system is then activated by pumping a second heat transfer fluid 940 downwardly along the inner annulus 904 between the drilled liner 804 and the concentric tube 902. The second heat transfer fluid 940 is pumped to the end of the drilled 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 the closed loop shown in FIG4 , although the flow may be reversed in this example. Where the concentric tube 902 is a vacuum insulated pipe, it is preferably used to contain the upwardly flowing heating fluid and retain as much heat as possible as the second heat transfer fluid 940 returns to the surface.

[0092] Once the second heat transfer fluid 940 reaches the surface, the heat it now carries is used directly for heating or converted into electricity through a traditional system of heat exchangers and turbine-driven generators. As heat is extracted from the surrounding hot rock formation, it is supplemented by heat conducted along the fracture network by the injected first heat transfer fluid 920. In this way, these hybrid embodiments overcome the shortcomings of both plume and closed-loop approaches by combining and utilizing the best aspects of both.

[0093] Some previously tested techniques can be used in modified form to increase the life of a well and its overall geothermal energy production. These techniques include drilling multiple directional wellbores and using each of them to extract subsurface heat energy for a set period of time, followed by a recovery period to allow the injected first heat transfer fluid 920 to disperse through the natural fracture system, and then injecting more first heat transfer fluid 920, and so on.

[0094] The first heat transfer fluid 920 that forms the injection of mass 922 can be water, brine, supercritical carbon dioxide or captured flue gas, or a mixture of any of these fluids. The use of supercritical carbon dioxide will enhance heat transfer. Carbon dioxide can be converted to its supercritical form at relatively low temperatures and pressures - 90 ° F and 1070 psi is enough. Therefore, supercritical carbon dioxide will require some pressurization equipment, but like water, it is harmless in the event of a spill. It is non-toxic and non-flammable. In the case where geothermal wells may have carbon sequestration potential, either while energy is being produced or later in its life cycle (as discussed below), the use of supercritical carbon dioxide will make commercial sense because it is easily available on site and is essentially free.

[0095] The closed loop second heat transfer fluid 940 can be the same as the injected first heat transfer fluid 920, or it can be a different fluid. It is not required that the injected fluid 920 and the second heat transfer fluid 940 are the same fluid. In some embodiments, supercritical carbon dioxide is used as the two heat transfer fluids due to its superior heat transfer properties. In various other embodiments, different fluids can be used. Water or salt water can be used, or various types of thermal oils can be used.

[0096] In some embodiments, before the well is brought online to generate geothermal energy, the well is charged with an injected first heat transfer fluid 920 for a period of time to achieve heat transfer. The first step in the charging process is to pump supercritical carbon dioxide into the well. The supercritical carbon dioxide will begin to flow through the natural fracture system and disperse outward from the well. Depending on the temperature and pressure in the rock surrounding the well, the carbon dioxide may fall out of the supercritical state, but as more carbon dioxide is pumped into the well, the pressure will rise to a point where the carbon dioxide becomes supercritical again. Once the process of pumping carbon dioxide has reached a point where the subsurface volume surrounding the well begins to fill with supercritical carbon dioxide, the well is ready to be configured as a geothermal well.

[0097] Turning now to wells drilled for carbon sequestration, where CO2 is pumped into permeable underground rock formations, a similar approach is used.

[0098] The wells that were originally drilled are now considered carbon sequestration wells. As mentioned above, many people have assumed that carbon sequestration requires existing depleted or abandoned oil or gas wells. This assumption is based on economic considerations rather than technical considerations. Obviously, using existing wells avoids the cost of drilling. However, this approach fails to take into account several important factors. Carbon dioxide is often generated or captured at considerable distances from available oil or gas wells, so a pipeline is needed to transport the CO2. The cost of building such a pipeline (including obtaining permits from multiple landowners) can be enormous. Opposition to the pipeline is to be expected for various reasons, and if it does occur, the entire construction process may take several years.

[0099] A second problem with using depleted wells is that they were almost certainly not drilled with carbon sequestration in mind. They were likely drilled using conventional drilling techniques, including the use of large amounts of drilling mud, which damages the rock formation by plugging the natural fracture system. Fracturing then pushes the mud further into the fractures and pores, exacerbating the damage. Typical fracturing wells have relatively short productive lives and are unsuitable for reuse as sequestration wells.

[0100] A third potential issue with using depleted oil wells, at least in the United States, is the question of ownership. Under U.S. law, ownership of surface rights is generally separate from ownership of subsurface mineral rights. However, it is generally accepted that ownership of the subsurface pore space belongs to the owner of the surface rights. Pore space is legally considered to consist of "absent minerals" and is not part of the mining rights. This means that while the owner or lessee of the mining rights may have the right to extract oil and gas, they may not have the right to fill the resulting pore space with CO2 or anything else. Before sequestration can proceed, a completely new set of agreements with the surface rights holders is required.

[0101] All of these problems can be overcome by drilling wells specifically for carbon sequestration. The use of modern drilling techniques and technologies allows for cost-effective drilling of wells close to the source of the carbon dioxide to be sequestered, without causing damage to the formation that would reduce the well's overall storage potential. The inventions described herein utilize the advanced NBRD drilling techniques described in the '005 patent application. These inventions emphasize avoiding formation damage and maintaining the integrity of the natural fracture system.

[0102] When the goal is to drill carbon sequestration wells, follow the same Figure 7 and Figure 8 The same process is shown. The use of a drilled liner 804 allows the entire directional wellbore 808 to act as a dispersion mechanism for supercritical carbon dioxide to be pumped into the annulus 810. As a result, much more supercritical carbon dioxide is flowed into the formation than would be possible using a cased well with spaced perforations, which severely restricts fluid flow. Eliminating the cost and time required to perforate the casing is an additional benefit.

[0103] The concept of carbon sequestration is not new. Using geothermal energy for electricity generation is not new either. Combining the two in a single well is not new, but its design is not ideal. This invention is novel in that it combines these two purposes, using a single well for both, but using a phased, integrated, and optimized approach, potentially providing dual benefits at very little additional cost.

[0104] While others have proposed combining carbon sequestration and geothermal energy production in the same well, their approaches typically employ the inefficient plume method described above and attempt to compel geothermal wells to function as sequestration wells. One drawback of this forced combination is that the requirements for optimizing a sequestration well may differ from those for optimizing a geothermal well. As described in detail below, the present invention optimizes wells for both uses.

[0105] Another disadvantage is that if one or other aspect of the project fails to achieve the expected results, the project may not be financially successful. It seems that most of these projects began as geothermal projects using CO2 that produced less-than-expected results. They were then recharacterized as sequestration wells. In fact, the plume method's Achilles' heel—the dispersion of the injected fluid—can only be described as a positive characteristic if it is considered a means of pumping CO2 underground. The more dispersed the CO2, the worse the geothermal performance, but the better the sequestration capacity, more or less by chance.

[0106] One of the early references to the use of supercritical carbon dioxide is U.S. Patent No. 6,668,554 to Brown, entitled "Geothermal Energy Production with Supercritical Fluids," which is incorporated herein by reference in its entirety. The technology described in this patent discloses a plume process in which carbon dioxide is allowed to fill a volume below the surface and is then captured and returned to the surface where thermal energy is extracted. This suffers from a common problem with plume processes, namely that the plume expands and only a small portion of any injected fluid actually flows into the extraction well.

[0107] A more recent example of the plume method is 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 patent relies on the presence of an impermeable caprock, as specified in the claims, to capture the plume. It at least acknowledges the problem of attempting to inject fluid into a rock formation and then recover the fluid from the expanding plume at some distance within the subsurface.

[0108] Given the potential of using a single well for both purposes, certain embodiments of the present invention propose a phased, integrated, and optimized approach to combining geothermal energy generation and carbon sequestration. Furthermore, the phases can be implemented in a different order depending on several factors, and in particular the economics of the project.

[0109] In some embodiments of the present invention, a well is initially established as a geothermal well and then evaluated for its carbon sequestration potential over the long term. In other embodiments, the process begins with drilling a well for carbon sequestration purposes. Once CO2 is pumped into the well and begins to fill the natural fracture system, the well is evaluated for its potential as a geothermal well.

[0110] In either case, the ideal project would be conducted in an area with known properties that indicate the well is suitable for both purposes. For such a project, the definition of "suitable" has multiple factors. The formation must be at a sufficient depth to ensure that the CO2 will remain sequestered and will not migrate back to the surface. Unlike the hydrocarbons included in the fracking fluid, doing so would not cause significant environmental harm, but would negate the purpose of sequestration. The formation must also have sufficient porosity to absorb significant amounts of CO2 and sufficient permeability to allow the CO2 to disperse into the formation from the injection well. The chemical composition of the formation is important because the long-term goal is for the CO2 to react with the rock and become part of the formation. However, if the rock reacts with the CO2 too quickly, the permeability of the formation surrounding the well may deteriorate, blocking flow and rendering the well useless.

[0111] For purposes of this invention, "suitable" includes factors not typically considered critical for sequestration wells. These include the temperature of the formation and the heat flow properties of the rock. These factors are important for a well to be used as a geothermal well, whether concurrently with carbon sequestration or subsequently.

[0112] It is also potentially feasible to assess the carbon sequestration potential of existing geothermal wells and the geothermal potential of existing sequestration wells, although doing so is less likely to produce optimal results than when wells are intended to have dual use from the outset.

[0113] In certain embodiments, geothermal well is drilled and equipped with sensor, comprises sensor such as temperature, pressure, flow rate.Before injecting supercritical carbon dioxide and during and during the period of suspending injection, measure, to determine that the pressure drop caused by supercritical carbon dioxide is dispersed into surrounding stratum.In certain embodiments, these measured values ​​can be combined with other data (comprising the well logging record from geothermal well and other wells in this area).Active or passive seismic survey (surveys) can provide valuable insights into the scope and directionality of the group of injected fluid.In this way, even when generating energy to cover well cost, also can assess the potentiality of well as carbon dioxide sequestration well.

[0114] When supercritical carbon dioxide is pumped into the well and dispersed, data can be collected that shows the dispersion rate, heat transfer rate and other factors. Some of the data comes 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 surveys can include surface sensor arrays or DAS cables in the well. For example, the DAS cable can be attached to the outside of the pipe used to flow the heat transfer fluid. Analysis of the seismic data obtained when the pumping of supercritical carbon dioxide begins and proceeds will show how the fluid is dispersed through the natural fractures. It will also be confirmed that the fluid has not leaked from the stratum where it should be present. From the perspective of public awareness, this may be more important than for technical reasons.

[0115] In some embodiments, there may be an option to sequester CO2 while generating geothermal energy. In other embodiments, CO2 can continue to be sequestered long after the well has reached the end of its useful life as a geothermal well. In other embodiments, geological and economic conditions may dictate that CO2 sequestration begin only after the well is no longer productive as a geothermal well. This depends largely on various factors, such as the availability of CO2 to be sequestered, tax credits and other incentives, and whether and, if so, how the CO2 must be brought on-site.

[0116] Sometimes there are wells where analysis of the measurements leads to the conclusion that, while it might be possible to create a subsurface volume filled with supercritical CO2 for geothermal heat transfer, the geological conditions may not support a complete carbon sequestration project. This possible outcome must be taken into account when calculating the economics of a geothermal project.

[0117] In some other embodiments, the reverse approach is used. That is, the well is drilled with the sole purpose of using it for carbon sequestration, with project costs recovered based solely on that use. Once supercritical CO2 is injected into the well, in-well instrumentation provides the basis for a detailed assessment of the well's potential as a geothermal well. If the formation is highly fractured, the supercritical CO2 may disperse rapidly and not form a cluster around the well, as would be desirable for geothermal heat transfer. If the formation proves suitable for generating geothermal energy, the concentric tubes of a closed-loop system are installed in the well.

[0118] Again, both technical considerations and market conditions, as well as other economic factors, will determine whether a well is used for both sequestration and geothermal energy generation, or whether a geothermal phase should be implemented when the well reaches the end of its useful life as a sequestration well.

[0119] In a sequestration well, CO2 will eventually fill the fracture system, reaching a point where the pressure required to pump more CO2 into the well is significantly higher than is reasonable. The CO2 will also react with the rock, forming carbonate deposits over time, which will block the natural fracture system. At that point, the well has reached the end of its useful life as a sequestration well. However, it may still be usable as a geothermal well.

[0120] If a well in combined use reaches the point where its sequestration capacity reaches its limit, it can be converted to a geothermal-only well with periodic injections of supercritical carbon dioxide to maintain a bolus of heat transfer fluid close to the well as the fluid disperses further outward from the well.

[0121] As mentioned earlier, the ideal well requirements for geothermal energy generation and carbon sequestration may differ. Therefore, the phased approach described here requires careful analysis of factors such as the length of directional wellbores, their diameters, and whether they are cased.

[0122] One of the added benefits of using a drilled liner and leaving the drill bit in the wellbore is that the wellbore can be extended simply by adding more drilled liners at the surface and restarting drilling as needed. This approach can be used to extend the life of the well. If a geothermal well is drilled and operated and it is later determined that it should be extended to serve as a retention well, or if a retention well needs to be extended for geothermal use, the same technique applies. Thus, the embodiments described herein provide a degree of flexibility not found in conventional drilling techniques.

[0123] Obviously, there is no problem when a well is first drilled for carbon sequestration and the geothermal closed loop concentric pipe is later designed to be shorter than the sequestration well. It is even possible to seal the wellbore at the end of the closed loop so that from then on the injected supercritical CO2 will continue to flow only into the subsurface section surrounding the closed loop.

[0124] The above embodiments describe the use of directional wells (typically horizontal wells) because the geothermal industry has adopted this approach to maximize heat gain in plume methods. It also makes drilling a closed-loop system easier when a suitable sedimentary hot rock layer is available and oriented substantially horizontally. However, the present invention is equally applicable to both sedimentary hot rock layers and the granite underlying the sedimentary rock. As previously mentioned, granite contains radioactive materials that are decaying and is the source of some geothermal heat. Therefore, drilling into the granite provides access to heat. Heat rising from the Earth's core is another source of geothermal heat, and of course, the deeper the well, the closer to this heat. Once the well has reached the granite, it is possible to continue drilling vertically for thousands of feet while still remaining in the granite.

[0125] Therefore, some embodiments of the present invention use only vertical wells, which are drilled deeper than most geothermal wells, using the drilling techniques previously described, penetrating thousands of feet into granite. Granite is highly fractured, and therefore, this deep wellbore will pass through multiple natural fracture systems. This is in contrast to sedimentary thermal rock formations, which may be measured in feet thick and have only one major fracture system.

[0126] Other embodiments utilize deviated wells drilled from offset locations into granite formations. Drilling vertical or deviated wells offers significant cost savings compared to drilling curved sections. Compared to drilling horizontal wells, it eliminates the need for a directional drilling crew and saves at least two drill trips.

[0127] like Figure 10 As shown, in some embodiments, a well 1000 is drilled to the top of granite 1002 and cased 1004, and then a wellbore 1006 is drilled through the granite 1010 using open hole techniques and a drilled liner 1008, thereby creating an outer annulus 1012. In some embodiments, a jet pump 1020 and an electric drill bit 1022 are used because they provide high penetration rates and are relatively low cost. The jet pump 1020 and drill bit 1022 are left in the wellbore because the cost of recovering them exceeds the cost of the units themselves.

[0128] As with the previous embodiments, concentric tubes 1024 are installed to form a closed loop system with an inner annulus 1028. In some embodiments, a first heat transfer fluid 1030 is pumped downwardly along the outer annulus 1012, as indicated by flow arrows 1032. It will come into contact with the uncased wellbore 1006. As a result, the first heat transfer fluid 1030 will begin to migrate into the natural fracture system within the granite 1010. As it expands in all directions, it will create a slug 1034 of the first heat transfer fluid 1030, thereby filling the fracture system with an efficient means of transferring heat from the formation back into the wellbore.

[0129] The closed loop system is then initiated by pumping a second heat transfer fluid 1040 downwardly along the inner annulus 1028 between the drilled liner 1008 and the concentric tube 1024, as indicated by flow arrows 1042. The second heat transfer fluid 1040 is pumped to the closed end 1010 of the drilled liner 1008, where it makes a U-turn and flows back upwardly along the concentric tube 1024, as indicated by flow arrows 1044. Once the second heat transfer fluid 1040 reaches the surface, the heat it now carries is either used directly for heating or converted into electrical energy through a conventional system of heat exchangers and turbine-driven generators.

[0130] Regardless of 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, thereby ensuring that it flows back up along the concentric tube 1024. In some embodiments, where the jet pump 1020 is in place just behind the drill bit 1022, a plug 1046 is placed behind the jet pump 1020 to force the second heat transfer fluid 1040 back up along the concentric tube 1024. In some other embodiments, where the jet pump 1020 is not used or present, a plug 1046 of rubber or similar material is installed in the wellbore 1006 behind the drill bit 1022 to seal the drill bit 1022 and prevent fluid loss.

[0131] These vertical or near-vertical embodiments offer advantages over horizontal wellbores that are legal rather than technical. As previously mentioned, the laws of the United States and some other countries provide that the pore space belongs to the owner of the surface rights. Whether using the plume method or the hybrid method disclosed herein, the heat transfer fluid is injected into the pore space. Horizontal wellbores can inject fluid and thereby occupy pore space subject to the rights of multiple landowners. Vertical wellbores obviously only require rights to the surface and pore space within a relatively small distance around the well.

[0132] Eliminating the complexities of pore space rights and the potentially high legal costs associated with securing those rights makes vertical well geothermal energy generation both more affordable and practical for smaller-scale projects. The benefits are even greater when geothermal power plants are desired near urban and suburban areas, where surface land ownership is highly fragmented.

[0133] For example, consider a natural gas-powered power plant. According to some estimates, sequestering the CO2 generated by the power plant would require 10-15% of the energy produced by the plant. Even so, such projects are often impractical due to the lack of pipelines to move the CO2 to the sequestration facility. However, vertical wells drilled on the land already occupied by the power plant have the potential to not only sequester CO2 from the power plant but also generate electricity from geothermal capture, making up for the electricity lost in the sequestration process. Thus, the power plant would generate the same amount of electricity as before, but that electricity would be carbon-neutral. If the CO2 were sequestered in horizontal wells extending into adjacent properties, such operations might cease or become prohibitively expensive.

[0134] Where available well sites are located towards the property boundary, deviated wells allow the heat transfer fluid to be injected below the center of the property, thereby preventing leakage of the fluid into the pore space beyond the property boundary.

[0135] As with the directional well embodiment described above, the vertical well embodiment can be applied to geothermal-only wells using a hybrid approach of injecting fluid into the pore space without recovering the fluid. It can also be applied to sequestration wells and combined geothermal-sequestration wells using a staged approach.

[0136] Various researchers have shown that granite not only contains multiple fractures, but that these fractures are interconnected and allow fluids to flow through the subsurface. See, for example, Lihui Liu et al., "CO2 injection to granite and sandstone in experimental rock / hot water systems," Pergamon, Energy Conversion and Management 44 (2003) 1399–1410, the entire contents of which are incorporated herein by reference. The publication states on page 1: "Our results suggest that it may be possible for granite and / or sandstone to 'capture' CO2 at hydrothermal conditions and that underground disposal may be a feasible solution to reducing atmospheric emission of CO2." The publication uses a plume method to generate geothermal energy, in which CO2 is injected along with geothermal waste fluids, which is much less efficient than the embodiments disclosed herein.

[0137] See also Tsuyoshi Nohara et al., “Enhancement of Permeability Activated by Supercritical Fluid Flow through Granite,” Wiley, Geofluids, Vol. 2019, Article ID 6053815, https: / / doi.org / 10.1155 / 2019 / 6053815, the entire contents of which are incorporated herein by reference.

[0138] In any of the above embodiments, whether a geothermal well or a sequestration well is the primary well, thermoelectric generation can be added to take advantage of the temperature difference between the surface or near-surface and the deeper section of the well. The Seebeck effect is the voltage generated between the contact points of two dissimilar conductive materials when a temperature difference exists between them. For a discussion of this effect and how it can be used to generate power in geothermal environments, see Jainish Shingala and Manan Shah, “A Novel Approach for Downhole Power Generation in Geothermal Wells Using Thermoelectric Generator,” PROCEEDINGS, 45th Symposium on Geothermal Reservoir Engineering, Stanford University, Stanford, CA, February 10–12, 2020, SGP-TR-216.

[0139] Thermoelectric generation can be used in combination with various embodiments of the present invention to generate electricity to operate pumps, direct carbon capture machines, and other equipment. The potential for using this additional electricity is clear when considering operations in remote environments or where grid power is not completely reliable.

[0140] The above disclosure has set forth several embodiments of the present invention, which are described in detail with reference to the accompanying drawings. It will be appreciated by those skilled in the art that various changes, modifications, other structural arrangements and other embodiments may be practiced under the teachings of the present invention without departing from the scope of the invention as set forth in the appended claims.

Claims

1. A method for extracting geothermal energy from a well below the surface of the Earth, comprising: drilling a well down into the hot rock formation using a drill bit and a drill string, creating an outer annulus from the earth's surface between the drill string and the formed wellbore; installing a concentric tube within the drill string to create an inner annulus and a closed-loop fluid flow path; injecting a first heat transfer fluid downwardly into the hot rock formation along the outer annulus to create a bolus of the first heat transfer fluid within the hot rock formation, wherein no first heat transfer fluid is withdrawn from the hot rock formation; pumping a second heat transfer fluid down the inner annulus into the closed-loop fluid flow path and back to the surface through the concentric tubes, and The heat collected by the second heat transfer fluid is converted into usable energy.

2. The method of claim 1, wherein the injected first heat transfer fluid is selected from the group consisting of water, brine, supercritical carbon dioxide, captured flue gas, captured flue gas dissolved in water, and captured flue gas dissolved in supercritical carbon dioxide.

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

4. The method of claim 1 , wherein the well is filled with the first heat transfer fluid for a predetermined period of time to create the bolus of the first heat transfer fluid within the hot rock formation prior to commencing geothermal extraction using the second heat transfer fluid.

5. The method of claim 1, wherein the wellbore section in the hot rock formation is drilled using a non-destructive reservoir drilling technique, further comprising using a lightweight drilling fluid to avoid formation damage.

6. A method for combining geothermal energy generation and carbon dioxide sequestration in the same well, comprising: drilling a commercially viable geothermal well down into a hot rock formation using a drill bit and a drill string, creating an outer annulus from the Earth's surface between the drill string and the formed wellbore; installing a concentric tube within the drill string to create an inner annulus and a closed-loop fluid flow path; injecting supercritical carbon dioxide down the outer annulus and into the hot rock formation to create a cloud of supercritical carbon dioxide within the hot rock formation; pumping a heat transfer fluid down the inner annulus into the closed-loop fluid flow path and back to the surface through the concentric tube; converting heat collected by the heat transfer fluid into usable energy; collecting data using at least one instrument positioned within the well to assess the amount of carbon dioxide trapped within the hot rock formation, and If the amount of captured carbon dioxide is above a predetermined level, the amount of supercritical carbon dioxide injected into the outer annulus is increased, thereby sequestering carbon dioxide in commercially significant amounts.

7. The method of claim 6, wherein the well is used for simultaneous geothermal energy generation and carbon dioxide sequestration until the amount of geothermal energy production falls below a predetermined level and is then used only for carbon dioxide sequestration.

8. The method of claim 6, wherein the well is used for simultaneous geothermal energy generation and carbon dioxide sequestration until the well has reached the end of its useful life for carbon dioxide sequestration and is then used only for geothermal energy generation.

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

10. The method of claim 6, wherein the well is used only for geothermal energy generation until the amount of geothermal energy production drops below a predetermined level, and then used only for carbon dioxide sequestration.

11. The method of claim 6, wherein prior to commencing geothermal heat extraction, the well is charged with supercritical carbon dioxide for a predetermined period of time to create a cloud of supercritical carbon dioxide within the hot rock formation.

12. The method of claim 6, wherein the wellbore section in the hot rock formation is drilled using a non-destructive reservoir drilling technique, further comprising using a lightweight drilling fluid to avoid formation damage.

13. A method for combining carbon dioxide sequestration and geothermal energy generation in the same well, comprising: drilling a commercially viable carbon sequestration well down into the hot rock formation using a drill bit and a drill string, creating an outer annulus from the Earth's surface between the drill string and the formed wellbore; injecting supercritical carbon dioxide into the hot rock formation through the outer annulus to create a mass of supercritical carbon dioxide within the hot rock formation surrounding a directional section of the wellbore, thereby sequestering the supercritical carbon dioxide; collecting data using at least one instrument positioned within the well to measure heat flow; installing a concentric tube within the drill string to create an inner annulus and a closed-loop fluid flow path around the concentric tube when the heat flow rate exceeds a predetermined value; A heat transfer fluid is pumped down the inner annulus into the closed-loop fluid flow path and returned to the surface through the concentric tubes, and heat collected by the heat transfer fluid is converted to usable energy.

14. The method of claim 13, wherein the well is used for simultaneous carbon dioxide sequestration and geothermal energy generation until the well has reached the end of its useful life for carbon dioxide sequestration and is then used only for geothermal energy generation.

15. The method of claim 13, wherein the well is used for simultaneous carbon dioxide sequestration and geothermal energy generation until the well has reached the end of its useful life for geothermal energy generation and is then used solely for carbon dioxide sequestration.

16. The method of claim 13, wherein the well is used for carbon dioxide sequestration only for a period of time and then used for simultaneous carbon dioxide sequestration and geothermal energy generation.

17. The method of claim 13, wherein the well is used only for carbon dioxide sequestration until the well has reached the end of its useful life for carbon dioxide sequestration and is then used only for geothermal energy generation.

18. The method of claim 13, wherein the wellbore section in the hot rock formation is drilled using a non-destructive reservoir drilling technique, further comprising using a lightweight drilling fluid to avoid formation damage.

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