Systems and methods for thermal reach enhancement

Abstract

To provide a thermal reach enhanced geothermal well bore.SOLUTION: The geothermal well bore 10 includes a well bore 12 extending from a topside surface 14 to a target location in a formation 16. The geothermal well bore 10 further includes a plurality of fissures 18 that distally extend from the target location into the formation 16 and that are at least partially filled with a compacted high-thermal conductivity material 20. The compacted high-thermal conductivity material 20 terminates at a proximal end to the target location of the well bore to be thermally coupled to a high-thermal conductivity grout or slurry through which heat is conducted to a working fluid accommodated in a casing 13 of a closed loop working fluid conduit embedded in the grout or slurry.SELECTED DRAWING: Figure 3

Description

[Technical field]

[0001] This application claims priority to co-pending U.S. Provisional Patent Application No. 63 / 305,658, filed February 1, 2022, which is incorporated herein by reference.

[0002] The field of the invention is systems and methods for heat harvesting in geothermal heat recovery, and more particularly, systems and methods for extending reach beyond the wellbore through highly thermally conductive materials that extend into fractures. [Background technology]

[0003] The background discussion contains information useful in understanding the present invention. No admission is made that any of the information provided herein is prior art or relevant to the presently claimed invention, or that any publication specifically or implicitly referenced is prior art.

[0004] All publications and patent applications herein are incorporated by reference to the same extent as if each individual publication or patent application was specifically and individually indicated to be incorporated by reference. If a definition or use of a term in an incorporated reference contradicts or is contrary to the definition of that term provided herein, the definition of that term provided herein shall apply and the definition of that term in the reference shall not apply.

[0005] Geothermal wells have been used to provide heating and cooling systems that transfer heat to and from the earth. In a typical vertical well closed loop system, two pipes joined with a U-shaped connector at the bottom, forming a continuous casing, are installed vertically in a well drilled into the earth (see U.S. Patent Application Publication No. 2012 / 0247766). This type of system is commonly used for heating and cooling residential and commercial buildings. In such systems, a conventional grout mixture, typically clay-based, is pumped into the well to fill the annular space between the casing and the formation. As a result, the grout forms a seal to prevent contamination of the groundwater and to prevent contamination of the subsurface from above ground. The grout mixture may further include a thermally conductive material that aids in the transfer of heat between the working fluid in the casing and the target location. For example, the working fluid may circulate in the well loop to transfer heat to and from a heat exchanger at the surface. Unfortunately, most, if not all, of these systems are not suitable for heat extraction in sufficient quantities to generate electricity.

[0006] In fact, the vertical design of conventional geothermal wells often limits their ability to reach target locations within the formation suitable for thermal energy extraction for power generation. To increase heat extraction, the length and width of the geothermal well must be increased to increase the surface area in contact with the formation. However, such solutions are typically expensive and technically challenging.

[0007] For example, US Patent No. 11,220,882 describes the recompletion of previously completed wells for hydrocarbon production using a high thermal conductivity proppant material that displaces reservoir fluids in existing fractures. To this end, a slurry containing a carrier fluid and graphite as a thermally conductive material is injected into the propped fracture, and the slurry dehydrates as the carrier fluid flows into the surrounding reservoir, which is expected to result in a porous graphite solid in the vicinity of the recompleted well. Similarly, US Patent Application No. 2020 / 0191444 teaches the use of carbon-based high thermal conductivity materials and particulates, as well as sedimentary materials, as thermally conductive materials in recompleted wells. In some embodiments, an existing hydrocarbon well can be further fractured and a high thermal conductivity material can be installed into the fracture after the fracture is formed. While such methods can advantageously utilize already existing wells, they are generally not suitable for high temperature target locations, especially where dry, hot rocks are present. As a result, geothermal power generation is generally not achieved with such methods. Moreover, such methods are limited to locations where hydrocarbon producing wells already exist, severely limiting their deployment in locations where heat extraction is desired. Furthermore, such methods require hydraulic isolation from adjacent reservoirs, and failure to provide such isolation can damage adjacent wells and adversely affect recompletion.

[0008] As another example, WO 2022 / 018674 teaches geothermal energy harvesting using both conductive and convective heat transfer, where a geothermal well has an inlet well, an outlet well, and a horizontally extending connecting well between them. Here, the connecting well is in fluid communication with a number of conduits, such as fractures, and heat is conductively and convectively transferred to the connecting well. However, construction of such a structure is relatively complex, as the connecting well must be sealed with a sealant that prevents fluid exchange between the geothermal well and the surrounding underground zone.

[0009] To simplify heat transfer in the formation, graphitic material can be used at the bottom of the borehole and additional conduits can be drilled adjacent to the borehole and filled with graphitic material as described in US 2011 / 0232858. While conceptually simpler, heat transfer from the formation to the working fluid in such systems is generally not as desirable.

[0010] To increase the heat transfer, the bottom of the borehole can be expanded in successive steps, as described in U.S. Pat. No. 4,912,941. Here, the bottom of the borehole is subjected to successive steps of blasting or crushing, after which the broken rock is washed away, resulting in newly generated passages in addition to those already present in the rock. These passages are then filled with a cementitious material, which may include siliceous gel and / or metal powder, and left to harden. The thus hardened material is then blasted or reamed to form a generally cylindrical chamber in which the casing of the heat exchanger is placed and grouted in place. Although such methods do at least somewhat increase the heat transfer, the placement of the thermally conductive material is tedious. Furthermore, placement of the grout surrounding the heat exchanger casing is usually problematic, especially when the temperature of the target location is high, as the high temperatures cause the grout to harden before it reaches the target location.

[0011] Thus, although various systems, compositions, and methods for enhancing thermal reach in geothermal wells are known in the art, all or nearly all of them suffer from several drawbacks. Thus, there remains a need for improved systems, compositions, and methods for enhancing thermal reach in geothermal wells. [Prior art documents] [Patent documents]

[0012] [Patent Document 1] US Patent Application No. 2012 / 0247766 [Patent Document 2] U.S. Patent No. 11,220,882 [Patent Document 3] US Patent Application No. 2020 / 0191444 [Patent Document 4] International Publication No. 2022 / 018674 [Patent Document 5] US Patent No. 2011 / 0232858 [Patent Document 6] U.S. Pat. No. 4,912,941 Summary of the Invention [Problem to be solved by the invention]

[0013] The subject matter of the present invention is directed to various systems, compositions, and methods for geothermal wells with enhanced thermal reach, and in particular methods of forming such enhanced wells, as well as methods of extracting heat from a formation using such enhanced wells. In a particularly contemplated embodiment, the geothermal well includes a compressed, highly thermally conductive material disposed in a fracture extending from the well, in particular a well utilizing a closed-loop geothermal system well for geothermal power generation. The compressed, highly thermally conductive material in the fracture, together with the large surface area of ​​the fracture, advantageously improves heat transfer from the target location. This improved heat transfer results in greater capture of thermal energy into the working fluid, increasing the revenue of the power generating well.

[0014] In one aspect of the inventive subject matter, the inventors contemplate a method of enhancing thermal delivery in a geothermal wellbore. The method includes pumping a fluid (e.g., water) into the wellbore to reach a target location in the earth formation. In certain embodiments, the target location extends substantially vertically at least 500 feet underground and has a target temperature of at least 300° C., at least 400° C., or at least 500° C. Such a method further includes increasing the pressure of the fluid at the target location to a fracturing pressure sufficient to open a plurality of fractures in the earth formation. In various embodiments, the fractures extend distally from the wellbore for a distance of at least 3 feet.

[0015] Contemplated methods also include pumping a slurry containing a high thermal conductivity material dispersed in a carrier fluid into the well at or above the fracturing pressure, such that the slurry at least partially fills the fracture. The slurry can include water, and optionally a plasticizer, a surfactant, and / or an organic polymer. In some embodiments, the slurry does not include a cementitious material and can be placed at high temperatures without curing or setting. Suitable high thermal conductivity materials include graphite powder, flake graphite, pyrolytic graphite, desulfurized petroleum coke, graphene, fly ash, copper powder, aluminum nitride, and silicon carbide.

[0016] Contemplated methods further include the subsequent steps of reducing pressure at the target location and in the fracture by an amount sufficient to partially close the fracture and drain at least a portion of the carrier fluid from the slurry in the fracture, thereby forming a fracture containing a compressed high thermal conductivity material. The compressed high thermal conductivity material terminates at a proximal end of the wellbore and a distal end in the formation. The compressed high thermal conductivity material can have a solids content of at least 10% by volume or at least 25% by volume and a thermal conductivity of at least 20 W / m°K, at least 40 W / m°K, or at least 80 W / m°K.

[0017] Contemplated methods may also include placing a high thermal conductivity composition in the wellbore, the high thermal conductivity composition contacting a proximal end of the compacted high thermal conductivity material and an outer surface of the casing located in the wellbore. In one embodiment, the high thermal conductivity composition is a high thermal conductivity grout. In another embodiment, the high thermal conductivity composition is a compacted high thermal conductivity slurry. Thus, it should be understood that the high thermal conductivity composition in the wellbore has a different composition than the composition of the compacted high thermal conductivity material in the fracture.

[0018] As a result, the inventors also contemplate a geothermal well having enhanced thermal delivery. The geothermal well includes a well extending from the earth's surface to a target location in the formation. In certain embodiments, the target location is at least 500 feet below ground and the target temperature is at least 300° C., at least 400° C., or at least 500° C. The geothermal well further includes a plurality of fractures extending distally from the target location into the formation. In various embodiments, the fractures extend distally from the well for a distance of at least 3 feet.

[0019] It is envisioned that the fracture is at least partially filled with a compressed high thermal conductivity material, the compressed high thermal conductivity material terminating at a proximal end of the target location in the wellbore. In certain embodiments, the high thermal conductivity material includes graphite powder, flake graphite, pyrolytic graphite, desulfurized petroleum coke, graphene, fly ash, copper powder, aluminum nitride, and silicon carbide. Thus, the compressed high thermal conductivity material may have a thermal conductivity of at least 20 W / m°K, at least 40 W / m°K, or at least 80 W / m°K.

[0020] In various embodiments, the geothermal well further includes a casing having an exterior surface located within the well. In these and other embodiments, the well further includes a high thermal conductivity composition in contact with a proximal end of the compressed high thermal conductivity material and the exterior surface of the casing located within the well. In one embodiment, the high thermal conductivity composition is a high thermal conductivity grout. In another embodiment, the high thermal conductivity composition is a compressed high thermal conductivity slurry. In this manner, the high thermal conductivity grout or slurry has a different composition than the compressed high thermal conductivity material within the fracture.

[0021] In yet another aspect of the inventive subject matter, the inventors contemplate a method of extracting heat from an earth formation. The method includes installing a closed-loop working fluid conduit in a well having a target location in the earth formation. In certain embodiments, the target location is at least 500 feet below ground and has a target temperature of at least 300° C., at least 400° C., or at least 500° C. The closed-loop working fluid conduit is thermally coupled to a high thermal conductivity composition. In one embodiment, the high thermal conductivity composition is a high thermal conductivity grout. In another embodiment, the high thermal conductivity composition is a compacted high thermal conductivity slurry.

[0022] It is envisioned that the formation at the target location includes a plurality of fractures that may extend distally from the wellbore for a distance of at least 3 feet. The high thermal conductivity composition is then contacted with the compressed high thermal conductivity material that extends from the target location into the plurality of fractures in the formation. The envisioned method further includes transferring heat from the formation through the high thermal conductivity material in the fractures and the high thermal conductivity composition to the working fluid in the closed-loop working fluid conduit. In certain embodiments, the high thermal conductivity material includes graphite powder, flake graphite, pyrolytic graphite, desulfurized petroleum coke, graphene, fly ash, copper powder, aluminum nitride, and silicon carbide. Most typically, the compressed high thermal conductivity material has a solids content of at least 10% by volume or at least 25% by volume, and a thermal conductivity of at least 20 W / m°K, at least 40 W / m°K, or at least 80 W / m°K.

[0023] Various objects, features, aspects and advantages of the present subject matter will become more apparent from the following detailed description of preferred embodiments, taken in conjunction with the accompanying drawing figures in which like numerals represent like elements. [Brief description of the drawings]

[0024] [Figure 1] FIG. 1 is a schematic diagram of the steps of one exemplary method for placing a highly thermally conductive material into a fracture at a target location in an earth formation. [Diagram 2]FIG. 2 is a schematic diagram of steps of another exemplary method for placing a high thermal conductivity composition at a target location and thermally coupling the high thermal conductivity material to a casing of a closed-loop working fluid conduit. [Diagram 3] FIG. 3 is a schematic diagram illustrating the operation of an exemplary enhanced thermal delivery geothermal well in accordance with the present inventive subject matter. DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0025] The inventors have discovered that a geothermal well with enhanced thermal reach can be produced in a conceptually simple and effective manner. Advantageously, a contemplated geothermal well with enhanced thermal reach includes a compressed high thermal conductivity material located in a fracture at a target location in an earth formation, the fracture extending distally from the well. The compressed high thermal conductivity material in the fracture, together with the large surface area of ​​the fracture, significantly improves heat transfer from the target location to the well. In particular, the compressed high thermal conductivity material in the fracture does not require a hardening material (e.g., a cement-based material) and can therefore be placed in the fracture even at high temperatures. The contemplated well further includes a high thermal conductivity composition in heat exchange with the compressed high thermal conductivity material in the fracture on one side and with a casing of a closed-loop working fluid conduit in the well on the other side. As a result, it should be appreciated that a geothermal well with enhanced thermal reach can be produced in a simple and effective manner, and that such a geothermal well can increase the capture of thermal energy into the working fluid, thereby increasing the revenue of the power-generating well.

[0026] 1-3, an enhanced thermal delivery geothermal well 10 includes a well 12 extending from an upper surface 14 to a target location within an earth formation 16. In typical examples, the target location has a target temperature of at least 300° C., at least 350° C., at least 400° C., at least 450° C., or at least 500° C., and / or the target location may be at least 500 feet, at least 600 feet, at least 700 feet, at least 800 feet, at least 900 feet, at least 1,000 feet, at least 1,250 feet, at least 1,500 feet, at least 1,750 feet, at least 2,000 feet, at least 2,500 feet, at least 3,000 feet, at least 4,000 feet, or at least 5,000 feet underground.

[0027] In certain embodiments, the target location extends in a substantially vertical direction. As used herein, the term "substantially" means that the target location extends toward the center of the Earth, but may be offset from the center by 15 degrees or less, 10 degrees or less, 5 degrees or less, or 1 degree or less. It should be understood that a geothermal well 10 may have multiple target locations, and thus may have both target locations that are substantially vertical and target locations that extend in a direction of at least 30 degrees.

[0028] The formation 16 is typically hot, dry rock (e.g., intrusive igneous or metamorphic rock) and includes a number of fractures 18 extending distally from the wellbore 12 at the target location into the formation 16. In various embodiments, the fractures extend distally from the wellbore a distance of at least 3 feet, at least 4 feet, at least 5 feet, at least 6 feet, at least 7 feet, at least 8 feet, at least 9 feet, or at least 10 feet or even more. The fractures 18 are at least partially filled with a compressed high thermal conductivity material 20. In various embodiments, at least 10%, at least 20%, at least 30%, at least 40%, at least 50%, at least 60%, at least 70%, at least 80%, or at least 90% or even more of the volume of each of the fractures 18 includes the compressed high thermal conductivity material 20.

[0029] In this context, it should be noted that the compressed highly thermally conductive material 20 typically terminates on a proximal end 22 at the target location of the wellbore 12 such that the compressed highly thermally conductive material 20 exchanges heat with the highly thermally conductive composition within the wellbore 12. Additionally, the compressed highly thermally conductive material 20 terminates at a distal end 24 within the formation 16. It should thus be appreciated that the compressed highly thermally conductive material 20 in the fractures 18 provides an additional thermally conductive surface for improving heat extraction from the target area within the formation as opposed to just the surface of the formation immediately adjacent to the wellbore 12. Viewed from another perspective, the compressed highly thermally conductive material in the fractures acts as a heat sink fin or heat exchange surface that significantly improves heat transfer per unit length of the wellbore 12, resulting in increased revenue for the power generating well.

[0030] With continued reference to FIGS. 1-3, the geothermal well 10 further includes a casing 13 of a closed-loop working fluid conduit, the casing having an outer surface located within the well 12 such that an annular space 26 is formed between the well 12 and the outer surface of the casing 13. Fluidly coupled to the closed-loop working fluid conduit is a circulation pump (not shown) on the topside 14 and a heat exchanger or other heat transfer device operably coupled to drive a generator (typically a generator via a turbine, not shown). In the example of FIGS. 1-3, the closed-loop working fluid conduit includes an inner conduit 28 that defines a return space 30. The inner conduit 28 is located within the casing 13, thus forming a second annular space 32. In various embodiments, the casing 13 and the inner conduit 28 cooperate to form the closed-loop working fluid conduit.

[0031] A geothermal well with enhanced thermal delivery is typically produced in a series of steps, after the well is installed to reach a target location in the formation, by pressurizing fluid in the well to a fracturing pressure, thereby opening a number of fractures at the target location in the formation. In most embodiments of the contemplated method, the pressure is then maintained at or above the fracturing pressure to keep the newly created fractures open. A slurry including a highly thermally conductive material dispersed in a carrier fluid is then pumped into the well at or above the fracturing pressure, such that the slurry at least partially fills the newly created fractures. Once the fractures are at least partially filled, the pressure is gradually reduced to at least partially close the fractures and drain at least a portion of the carrier fluid from the slurry in the fractures into the well. As a result, as the fractures settle, the highly thermally conductive material installed in the fractures is compressed and held in place by the weight of the rock mass. Viewed another way, the former voids within the open fracture are replaced with a highly thermally conductive material which is compressed by the reduction in pressure to form a continuous pathway extending distally into the formation.

[0032] Of note, the rock compresses and holds the high thermal conductivity material, eliminating the need for a cement-based material to hold the high thermal conductivity material in place. Additionally, the compressed high thermal conductivity material is more effective at conductive heat transfer compared to passively filled fractures, since the air and fluid content is minimized. Additionally, it should be understood that the compressed high thermal conductivity material terminates at the beginning of the fracture proximal to the wellbore. Thus, during installation of the compressed high thermal conductivity material, the compressed high thermal conductivity material can be placed in direct contact with the high thermal conductivity composition that transfers heat from the compressed high thermal conductivity material to the casing of the closed loop working fluid conduit.

[0033] The use of a second, compositionally different high thermal conductivity composition is particularly beneficial because the high thermal conductivity composition can be placed independently and have different thermal conductivity properties than the compressed high thermal conductivity material to optimize heat transfer from the target location to the working fluid. In addition, if desired, the high thermal conductivity composition may include a cement component to aid in grouting the closed-loop working fluid conduit in place while simultaneously thermally bonding directly to the proximal portion of the compressed high thermal conductivity material. Alternatively, the high thermal conductivity composition may be a non-cementitious slurry. Whatever the composition, it should be understood that the high thermal conductivity composition maintains intimate thermal contact with the casing of the closed-loop working fluid conduit at the target location while thermally bonding directly to the compressed high thermal conductivity material.

[0034] FIG. 1 shows a schematic diagram of one exemplary method steps in which a highly thermally conductive material (e.g., flake graphite) is placed into fractures at a target location in an earth formation, where a plurality of fractures are first formed at the target location by pressurizing an aqueous solution of fracturing fluid at the target location. In the example of FIG. 1, the fracturing fluid is then preferably replaced at or above the fracture pressure by an aqueous slurry of flake graphite 34 by pumping the slurry through annular space 26. As can be readily seen from FIG. 1, an inner conduit 28 can be used to withdraw the fracturing fluid and slurry, typically by replacing it with new fluid through annular space 26. As can be readily understood, the specific fracture pressure will be determined to a large extent by the type of rock in the earth formation and the size or extent of the fractures.

[0035] The fracturing fluid may be held at the fracturing pressure for a time sufficient to generate fractures of the desired size / range, and one skilled in the art will readily recognize the occurrence of cracks. Thus, the fracturing fluid may be held at the fracturing pressure for at least 1 minute, at least 5 minutes, at least 10 minutes, at least 30 minutes, at least 60 minutes, at least 120 minutes, at least 240 minutes, or at least 24 hours, or even longer. The fracturing fluid may be held at the increased pressure for no more than 48 hours, no more than 24 hours, no more than 240 minutes, no more than 120 minutes, no more than 60 minutes, no more than 30 minutes, no more than 10 minutes, no more than 5 minutes, or no more than 1 minute, or even less. Thus, the fracturing fluid may be held at the increased pressure for at least 1 minute and no more than 48 hours, no more than 30 minutes and no more than 24 hours, or no more than 60 minutes and no more than 240 minutes.

[0036] Once the formation of the cracks is complete, the fracturing fluid is replaced with a slurry containing a highly thermally conductive material, typically at a pressure that maintains the cracks in an open configuration. As described above, the replacement is preferably performed through the annular space 26 and the inner conduit 28. The slurry is thus at least at the fracturing pressure, and most typically at least at a pressure somewhat higher than the fracturing pressure, for a time sufficient to allow circulation and infiltration of the highly thermally conductive material into the newly formed cracks. In various embodiments, at least 10%, at least 20%, at least 30%, at least 40%, at least 50%, at least 60%, at least 70%, at least 80%, or even more of the volume of each of the cracks 18 comprises the slurry.

[0037] Thus, it should be understood that the slurry may be held at elevated pressure for at least 1 minute, at least 5 minutes, at least 10 minutes, at least 30 minutes, at least 60 minutes, at least 120 minutes, at least 240 minutes, or at least 24 hours, or even longer. The slurry may be held at elevated pressure for not more than 48 hours, not more than 24 hours, not more than 240 minutes, not more than 120 minutes, not more than 60 minutes, not more than 30 minutes, not more than 10 minutes, not more than 5 minutes, or not more than 1 minute, or even less. The slurry can be held at elevated pressure for at least 1 minute and not more than 48 hours, at least 30 minutes and not more than 24 hours, or at least 60 minutes and not more than 240 minutes.

[0038] Upon completion of filling the fracture with the high thermal conductivity material, the pressure at the target location is reduced by an amount sufficient to partially close the fracture 18 and drain at least a portion of the carrier fluid from the slurry within the fracture 18, thereby forming a fracture 18 containing a compressed high thermal conductivity material 20. In this context, it should be understood that the formation pressure effectively closes voids in the high thermal conductivity material and reduces the water content in the high thermal conductivity material. As a result, such compressed material extends continuously from the proximal end 22 to the distal end 24.

[0039] In general, it is contemplated that the fracture geometry generally extends from the wellbore into the rock formation at the target location, with the fracture typically having a length of at least 1 m, or at least 2 m, or at least 5 m, or at least 5 m, or at least 15 m, or at least 20 m, or at least 25 m, or even more in some cases (measured as the distance between the wellbore and the distal end of the fracture). It should be further understood that in contemplated embodiments, the thickness (width) of the fracture is significantly smaller than rock fractures commonly used in oil and gas exploration. For example, suitable fracture thicknesses are 5-7.5 mm, or 7.5-15 mm, or 10-30 mm, or 30-50 mm, or in some cases somewhat wider. Thus, exemplary fracture structures may have widths of 5-30 mm, or 10-50 mm, or 25-80 mm. Most typically, the fracture width at the proximal end of the wellbore may be 10-50 mm. Furthermore, regardless of the specific configuration, in general, the fractures at the target location are preferably formed as a complex structure of fractures (such as a network or dendritic structure) rather than a single linear break in the rock formation. Advantageously, such a complex structure provides a greater surface area for heat exchange with the remainder of the unfractured rock at the target location. For example, the fractures may be formed to have a complex, longitudinal, multi-fracture geometry that is 10-50 mm wide and at least 10 m long, as measured from the wellbore.

[0040] Once the high thermal conductivity material is compressed into the fissure, the slurry in the annular space 26 can be replaced with a high thermal conductivity composition 36, as shown in FIG. 2. It is again noted that the high thermal conductivity composition 36 contacts the proximal end 22 of the compressed high thermal conductivity material 20 and the outer surface of the casing 22. As described in more detail below, the high thermal conductivity composition can be an in situ hardening cementitious composition or a non-cementitious slurry, both of which include materials having high thermal conductivity (e.g., graphite powder, flake graphite, pyrolytic graphite, desulfurized petroleum coke, graphene, fly ash, copper powder, aluminum nitride, and / or silicon carbide). In some embodiments, it is preferred (but not necessary) to place the high thermal conductivity composition 36 in a reverse circulation (e.g., as described in PROCEEDINGS, Thirty-Fifth Workshop on Geothermal Reservoir Engineering, Stanford University, Stanford, California, February 1-3, 2010).

[0041] With further reference to FIG. 2, in one embodiment, the high thermal conductivity composition 36 is a high thermal conductivity grout. The high thermal conductivity grout can include a cementitious material and a high thermal conductivity material. In a particular embodiment, the high conductivity grout further includes a retarder that allows the high conductivity grout to be placed in the well even under extreme temperature conditions (e.g., at least 300° C.). Without being bound by theory, the inventors envision that the retarder is present in an amount effective to delay the hardening of the grout mixture at a target location having a target temperature of at least 300° C., at least 400° C., or at least 500° C. for at least 2 hours. Particularly envisioned grout compositions are described in U.S. Provisional Application No. 63 / 305,599, filed 2 / 1 / 2022, which is incorporated herein by reference.

[0042] In another embodiment, the high thermal conductivity composition 36 is a compressed high thermal conductivity slurry. The compressed high thermal conductivity slurry may include high thermal conductivity material in the form of particles having a wide particle size distribution. In certain embodiments, the compressed high thermal conductivity slurry is substantially free of hardenable materials (e.g., cementitious materials) to minimize damage to the wellbore and to maintain mobility in the presence of substantial forces (e.g., earthquakes) to improve the workability of the slurry before compression, which allows for placement of the slurry in the wellbore even under extreme temperature conditions (e.g., at least 300° C.). Particularly contemplated grout compositions are described in U.S. Provisional Application No. 63 / 305,639, filed 2 / 1 / 2022, which is incorporated herein by reference.

[0043] The compressed high thermal conductivity material 20 can be formed from any high thermal conductivity material known in the art that is suitable for thermal conduction and for filling the plurality of cracks 18. To this end, as described in more detail below, the high thermal conductivity material is compressed after being provided to the plurality of cracks to form the compressed high thermal conductivity material. The compressed high thermal conductivity material 20 can have a thermal conductivity of at least 20 W / m°K, at least 25 W / m°K, at least 30 W / m°K, at least 40 W / m°K, at least 50 W / m°K, at least 60 W / m°K, at least 70 W / m°K, or at least 80 W / m°K. Without wishing to be bound by any theory or hypothesis, it is envisioned that the compressed high thermal conductivity material 20 has an improved thermal conductivity compared to the high thermal conductivity material prior to compression.

[0044] Suitable high thermal conductivity materials used to form the compressed high thermal conductivity material include, but are not limited to, graphite, sand, quartz silica, carbon nanotubes, graphene, boron nitride, brass, brass alloys, chrome nickel steel, carbon steel, stainless steel, transition metals (e.g., copper, cadmium, cobalt, gold, silver, iridium, iron, molybdenum, nickel, platinum, zinc, etc.), transition metal alloys (e.g., copper alloys, cadmium alloys, cobalt alloys, gold alloys, silver alloys, iridium alloys, iron alloys, molybdenum alloys, nickel alloys, platinum alloys, zinc alloys, etc.), post-transition metals (e.g., lead, tin, etc.), post-transition metal alloys (e.g., lead alloys, tin alloys, etc.), alkaline earth metal alloys (e.g., beryllium alloys, magnesium alloys, etc.), or combinations thereof. In certain embodiments, the high thermal conductivity material is selected from the group consisting of graphite powder, exfoliated graphite, flake graphite, pyrolytic graphite, desulfurized petroleum coke, graphene, fly ash, copper powder, aluminum nitride, silicon carbide, and combinations thereof.

[0045] As will be appreciated, the compressed high thermal conductivity material 20 may be provided to the plurality of cracks 18 as a slurry including the high thermal conductivity material and a carrier (e.g., water). In some embodiments, the high thermal conductivity material may be present in the slurry in an amount sufficient to provide a desired amount of thermal conductivity to the plurality of cracks 18. The high thermal conductivity material may be present in the slurry in an amount of at least 10% by weight, at least 20% by weight, at least 30% by weight, at least 40% by weight, at least 50% by weight, at least 60% by weight, at least 70% by weight, at least 89% by weight, at least 90% by weight, at least 91% by weight, at least 92% by weight, at least 93% by weight, at least 94% by weight, at least 95% by weight, at least 96% by weight, at least 97% by weight, at least 98% by weight, or at least 99% by weight or more, based on the total weight of the slurry. Alternatively, the high thermal conductivity material may be present in the slurry in an amount of about 1 to about 99% by weight, about 5% to about 99% by weight, about 40% to about 99% by weight, or about 80% to about 99% by weight, based on the total weight of the slurry.

[0046] Furthermore, the high thermal conductivity material may be in any form known in the art, so long as the high thermal conductivity material is capable of being provided to the plurality of cracks 18 and compressed to form the compressed high thermal conductivity material 20. The term "compacted" as used herein means that the compacted slurry (a) has a reduction in moisture content in an amount of at least 1%, 2%, 3%, 4%, 5%, 10%, 15%, 20%, 30%, 40%, 50%, 60%, 70%, 80%, 90%, or 99% by weight compared to the slurry before compaction; (b) has an increase in density in an amount of at least 1%, 2%, 3%, 4%, 5%, 10%, 15%, 20%, 30%, 40%, 50%, 60%, 70%, 80%, 90%, 100% or more by weight compared to the slurry before compaction; or (c) has both (a) a reduction in moisture content and (b) an increase in density. In various embodiments, the highly thermally conductive material can have an average particle size of 0.1 μm to 5.0 mm. Additionally, the highly thermally conductive material can be in the form of a plurality of particles having a broad or narrow particle size distribution.

[0047] In further embodiments, when the high thermal conductivity material has a broad particle size distribution, the particle size distribution spans at least 2 log units, at least 2.5 log units, or at least 3 log units. In some embodiments, the broad particle size distribution of the high thermal conductivity material provides structural integrity to the shape or configuration of the compressed high thermal conductivity material without the use of hardenable materials (e.g., cementitious materials). In embodiments in which the high thermal conductivity material has a narrow particle size distribution, the particle size distribution spans 2 log units or less, 1.5 log units or less, or 1 log unit or less. Because the high thermal conductivity material is substantially free of certain hardenable materials (e.g., cementitious materials), the high thermal conductivity material remains mobile even in the presence of substantial forces (e.g., earthquakes) to minimize damage to the compressed high thermal conductivity material 20 within the multiple cracks 18. Furthermore, the slurry containing the high thermal conductivity material has improved workability that allows the high thermal conductivity material to be placed within the multiple cracks 18 even under extreme temperature conditions (e.g., at least 300°C) due to the slurry being substantially free of certain hardenable materials (e.g., cementitious materials).

[0048] It should be appreciated that in even further contemplated embodiments, the compressed high thermal conductivity material forms a fluid barrier, thereby protecting the wellbore and closed-loop operating fluid conduits when water or hydrocarbon fluids are present in the formation. However, most typically, the target location is a dry, hot rock formation, most often with significantly low or no permeability (e.g., intrusive igneous or metamorphic rocks). Furthermore, due to the large pressures exerted within the formation during the closing of the fracture, the fracture typically has less than 25%, less than 20%, less than 15%, less than 10%, or less than 5% porosity of the entire fracture space in the previously open configuration.

[0049] FIG. 3 illustrates, in schematic form, an exemplary operation of a geothermal well with enhanced heat delivery in accordance with the subject matter of the present invention, in which a closed-loop working fluid conduit, including a casing 13 and an inner conduit 28, is disposed in a well 12 at a target location in an earth formation 16. As discussed above and as can be seen in FIG. 3, the casing 13 of the closed-loop working fluid conduit is thermally coupled to a high thermal conductivity composition 36, which in turn is thermally coupled to a compressed high thermal conductivity material 20 extending distally from the target location into a plurality of fractures 18 in the earth formation 16. In this example, heat from the earth formation 16 is transferred through the compressed high thermal conductivity material 20 in the fractures 18, the high thermal conductivity composition 36, and the casing 13 to a working fluid flowing downward through a second annular space 32. The working fluid thus heated reverses direction at the bottom of the casing and enters a return space 30 defined by the inner conduit 28. A heat exchanger (not shown) on the topside 14 extracts heat from the working fluid and returns the cooled working fluid downhole via a second annular space 32 in the closed-loop working fluid conduit. In a less preferred embodiment, the direction of working fluid flow may be reversed.

[0050] Returning to the slurry of compressed high thermal conductivity material 20, the slurry may optionally include at least one functional agent, such as a plasticizer, a surfactant, and / or an organic polymer. The functional agent may be used to modify the rheological properties of the slurry in response to various stimuli, such as temperature, pressure, contact with another material, or combinations thereof, or to improve the mixability of the slurry. The functional agent may be selected from the group consisting of plasticizers, surfactants, organic polymers, silica fillers, NaCl, KCl or other inorganic salts, clays, and combinations thereof.

[0051] A plasticizer may be present in the slurry to improve workability for ease of installation. In various embodiments, the term "plasticizer" refers to a substance that improves the flowability of the slurry, thereby improving the workability of the slurry or allowing the slurry to be made with less water while maintaining comparable workability. Suitable plasticizers include, but are not limited to, polycarboxylic ether plasticizers, phthalate plasticizers, terephthalate plasticizers, sulfonamide plasticizers, benzoate plasticizers, phosphate plasticizers, or combinations thereof.

[0052] In some embodiments, the plasticizer may be present in the slurry in an amount sufficient to provide the slurry with the desired workability. The plasticizer may be present in the slurry in an amount of at least 1%, 2%, 3%, 4%, 5%, 6%, 7%, 8%, 9%, or 10% by weight based on the total weight of the slurry. Alternatively, the plasticizer may be present in the slurry in an amount of 20% or less, 19%, 18%, 17%, 16%, 15%, 14%, 13%, 12%, 11%, or 10% by weight based on the total weight of the slurry. Alternatively, the plasticizer may be present in the slurry in an amount of about 1 to about 20%, about 5% to about 15%, or about 7% to 13% by weight based on the total weight of the slurry.

[0053] A surfactant may be present in the slurry to improve the surface properties of the slurry. Suitable surfactants include, but are not limited to, nonionic surfactants, anionic surfactants, cationic surfactants, zwitterionic surfactants, or combinations thereof.

[0054] Suitable nonionic surfactants include alkoxylates (e.g., alkoxylated nonylphenol condensates such as poly(oxy-1,2-ethanediyl), alpha-(4-nonylphenyl)-omega-hydroxy-branched), alkylphenols, ethoxylated alkylamines, ethoxylated oleates, tall oil, ethoxylated fatty acids, alkyl polyglycosides, These include, but are not limited to, sorbitan esters, methyl glucoside esters, amine ethoxylates, diamine ethoxylates, polyglycerol esters, alkyl ethoxylates, polypropoxylated and / or polyethoxylated alcohols, linear alcohol alkoxylates, dodecylbenzene sulfonate derivatives, linear nonyl-phenols, dioxane, ethylene oxide, polyethylene glycols, ethoxylated castor oil, polyoxyethylene nonylphenol ethers, tetraethylene glycol dodecyl ether, ethylene oxide, decylamine oxide, dodecylamine oxide, alkylamine oxides, ethoxylated amides, alkoxylated fatty acids, alkoxylated alcohols (e.g., lauryl alcohol ethoxylate, ethoxylated nonylphenol), ethoxylated fatty amines, ethoxylated alkylamines (e.g., coco alkylamine ethoxylate), any derivatives thereof, and any combinations thereof. As used herein, the term "derivative" refers to any compound prepared from one of the compounds, for example, by replacing one atom in the named compound with another atom or group of atoms, or by rearranging two or more atoms in the compound.

[0055] Suitable anionic surfactants include alpha sulfo fatty acid methyl ester salts. sulfonate), hydrolyzed keratin, polyoxyethylene sorbitan monopalmitate, polyoxyethylene sorbitan monostearate, polyoxyethylene sorbitan monooleate, alkyl ether sulfate, sodium 4-(1'heptylnonyl)benzenesulfonate, sodium dioctyl sulfosuccinate, sodium octylbenzenesulfonate, sodium hexadecyl sulfate, sodium laureth sulfate, quaternary ammonium compounds (e.g., trimethylcocoammonium chloride, trimethyltallowammonium chloride, dimethyldicocoammonium chloride, etc.), cetylpyridinium chloride, alkyl ester sulfonates, alkyl ether sulfonates, alkyl ether sulfates, alkali metal alkyl sulfates, alkyl sulfonates, alkylaryl sulfonates, sulfosuccinates, alkyl disulfonates, alkylaryl disulfonates, alkyl disulfates, alcohol polypropoxylated sulfates, alcohol polyethoxylated sulfates, any derivatives thereof, or any combinations thereof.

[0056] Suitable zwitterionic surfactants include, but are not limited to, alkylamine oxides, alkylbetaines, alkylamidopropylbetaines, alkylsulfobetaines, alkylsultaines, dihydroxyalkylglycinates, alkylamphoacetates, phospholipids, alkylaminopropionic acids, alkyliminomonopropionic acids, alkyliminodipropionic acids, dipalmitoyl-phosphatidylcholine, amine oxides, betaines, modified betaines, alkylamidobetaines (e.g., cocoamidopropyl betaine), and any combination thereof.

[0057] By way of example, surfactants that may exhibit viscoelastic properties include, but are not limited to, sulfosuccinates, taurates, amine oxides (e.g., amidoamine oxides), ethoxylated amides, alkoxylated fatty acids, alkoxylated alcohols, ethoxylated fatty amines, ethoxylated alkylamines, betaines, modified betaines, alkylamido betaines, quaternary ammonium compounds, alkyl sulfates, alkyl ether sulfates, alkyl sulfonates, ethoxylated esters, ethoxylated glycoside esters, alcohol ethers, any derivatives thereof, and any combinations thereof.

[0058] In some embodiments, the surfactant may be present in the slurry in an amount sufficient to impart a desired value of surface properties to the slurry. The surfactant may be present in the slurry in an amount of at least 1%, 2%, 3%, 4%, 5%, 6%, 7%, 8%, 9%, or 10% by weight based on the total weight of the slurry. Alternatively, the surfactant may be present in the slurry in an amount of 20% or less, 19%, 18%, 17%, 16%, 15%, 14%, 13%, 12%, 11%, or 10% by weight based on the total weight of the slurry. Alternatively, the surfactant may be present in the slurry in an amount of about 1 to about 20%, about 5% to about 15%, or about 7% to about 13% by weight based on the total weight of the slurry.

[0059] Organic polymers may be present in the slurry to improve the properties of the slurry. Suitable organic polymers include, but are not limited to, natural compounds, synthetic compounds, or combinations thereof. Non-limiting examples of suitable natural compounds include polysaccharides, such as cold water soluble polysaccharides and polysaccharide ethers, such as cellulose ethers, starch ethers (amylose and / or amylopectin and / or their derivatives), guar ethers, dextrins, or combinations thereof. Non-limiting examples of suitable synthetic compounds include protective colloids, such as one or more of polyvinylpyrrolidone and / or polyvinyl acetate, polyvinyl alcohol, melamine formaldehyde sulfonate, naphthalene formaldehyde sulfonate, block copolymers of propylene oxide and ethylene oxide, styrene-maleic acid and / or vinyl ether-maleic acid copolymers.

[0060] In some embodiments, the organic polymer may be present in the slurry in an amount sufficient to impart a desired value of a property to the slurry. The organic polymer may be present in the slurry in an amount of at least 1%, 2%, 3%, 4%, 5%, 6%, 7%, 8%, 9%, or 10% by weight based on the total weight of the slurry. Alternatively, the organic polymer may be present in the slurry in an amount of 20% or less, 19%, 18%, 17%, 16%, 15%, 14%, 13%, 12%, 11%, or 10% by weight based on the total weight of the slurry. Alternatively, the organic polymer may be present in the slurry in an amount of about 1 to about 20%, about 5% to about 15%, or about 7% to 13% by weight based on the total weight of the slurry.

[0061] Optionally, a silica filler may be present in the slurry to improve the properties of the slurry. Suitable silica fillers may be pyrogenic silica or precipitated finely-divided silica. The silica filler may have a particle size of about 50 to 10,000 angstroms, about 50 to about 400 angstroms, or about 100 to about 300 angstroms. The silica filler may be present in the slurry in an amount of at least 1%, 2%, 3%, 4%, 5%, 6%, 7%, 8%, 9%, or 10% by weight based on the total weight of the slurry. Alternatively, the silica filler may be present in the slurry in an amount of no more than 20%, 19%, 18%, 17%, 16%, 15%, 14%, 13%, 12%, 11%, or 10% by weight based on the total weight of the slurry. Alternatively, the silica filler may be present in the slurry in an amount of from about 1 to about 20 weight percent, from about 5 to about 15 weight percent, or from about 7 to about 13 weight percent, based on the total weight of the slurry.

[0062] Inorganic salts may be present in the slurry to improve the mixing of the slurry. Suitable inorganic salts include, but are not limited to, NaCl, KCl, and the like. The inorganic salt may be present in the slurry in an amount of at least 1%, 2%, 3%, 4%, 5%, 6%, 7%, 8%, 9%, or 10% by weight based on the total weight of the slurry. Alternatively, the inorganic salt may be present in the slurry in an amount of 20% by weight or less, 19%, 18%, 17%, 16%, 15%, 14%, 13%, 12%, 11%, or 10% by weight based on the total weight of the slurry. Alternatively, the inorganic salt may be present in the slurry in an amount of about 1 to about 20% by weight, about 5% to about 15% by weight, or about 7% to about 13% by weight based on the total weight of the slurry.

[0063] Clays may be present in the slurry to modify the fluidity of the slurry. Suitable clays include smectite family clays, palygorskite-sepiolite phyllosilicate family clays, kaolinite-serpentine family clays, nontronite, bentonite, hectorite, attapulgite, fluormica, montmorillonite, beidellite, saponite, sepiolite, kaolinite, illite, cation exchanged versions thereof, or combinations thereof.

[0064] Of the suitable smectite group clays, including nontronite, montmorillonite, saponite, hectorite, and beederite, other smectite group clays suitable for use as aqueous swelling clays in the present disclosure include, but are not limited to, ariettite, ferrosaponite, sauconite, stevensite, swinefodite, volkonskoite, yahontovite, and any combination thereof. Suitable clays of the palygorskite-sepiolite phyllosilicic acid family include, but are not limited to, attapulgite, tupahsauchiite, windhaukite, yawfortierite, falconite, ferrisepiolite, raufrinite, and any combination thereof. Suitable clays from the kaolinite-serpentine family of aqueous swelling clays include, but are not limited to, kaolinite, greenalite, flypontite, halloysite, dickite, lizardite, manandonite, nacrite, cronstedtite, clinochrysotile, chrysotile, nepite, odinite, webskiite, pecoraite, orthochrysotile, parachrysotile, caryopilite, brindleyite, berthierine, amesite, antigorite, boehmite, and any combination thereof.

[0065] In some embodiments, the clay can be present in the slurry in an amount sufficient to impart a desired value of the property to the slurry. The clay may be present in the slurry mixture in an amount of at least 1%, 2%, 3%, 4%, 5%, 6%, 7%, 8%, 9%, or 10% by weight based on the total weight of the slurry. Alternatively, the clay may be present in the slurry in an amount of 20% or less, 19%, 18%, 17%, 16%, 15%, 14%, 13%, 12%, 11%, or 10% by weight based on the total weight of the slurry. Alternatively, the clay may be present in the slurry in an amount of about 1 to about 20%, about 5% to about 15%, or about 7% to about 13% by weight based on the total weight of the slurry.

[0066] In some embodiments, numerical values ​​expressing properties such as amounts and concentrations of ingredients, reaction conditions, etc., used to describe and claim certain embodiments of the present invention are understood to be modified in some cases by the term "about". Thus, in some embodiments, the numerical parameters set forth in the detailed description and the appended claims are approximations that may vary depending on the desired properties sought to be obtained by a particular embodiment. The recitation of ranges of values ​​herein is merely intended to serve as a shorthand method of individually referring to each individual value falling within the range. Unless otherwise stated herein, each individual value is incorporated herein as if it were individually set forth herein.

[0067] All methods described herein may be performed in any suitable order unless otherwise indicated herein or clearly contradicted by context. Any examples provided herein with respect to specific embodiments, or the use of exemplary language (e.g., "such as"), are intended merely to better illustrate the invention and are not intended to impose limitations on the scope of the otherwise claimed invention. No language in this specification should be construed as indicating any non-claimed element essential to the practice of the invention.

[0068] As used throughout this specification and the claims that follow, the meanings of "a," "an," and "the" include plural references unless the context clearly indicates otherwise. Also, as used herein, the meaning of "in" includes "in" and "on," unless the context clearly indicates otherwise. As used herein, and unless the context clearly indicates otherwise, the term "coupled to" is intended to include both direct coupling (wherein the two elements that are coupled to each other contact each other) and indirect coupling (wherein at least one additional element is disposed between the two elements). Thus, the terms "coupled to" and "coupled with" are used interchangeably.

[0069] It will be apparent to those skilled in the art that many more modifications than already described are possible without departing from the inventive concepts herein. Accordingly, the subject matter of the present invention is not limited except as by the appended claims. Moreover, in interpreting both the specification and the claims, all terms should be interpreted in the broadest possible manner consistent with the context. In particular, the terms "comprises" and "comprising" should be interpreted as referring to elements, components, or steps in a non-exclusive manner, indicating that a referenced element, component, or step may be present, utilized, or combined with other elements, components, or steps not expressly referenced. When the specification or claims refer to at least one selected from the group consisting of A, B, C...... and N, the sentence should be interpreted as requiring only one element from the group, and not A+N, B+N, etc.

Claims

1. 1. A method for enhancing thermal delivery in a geothermal well, comprising: pumping the fluid down the well to a target location in the formation; increasing the pressure of the fluid at the target location to a fracturing pressure sufficient to open a plurality of fractures at the target location in the earth formation; pumping a slurry comprising a highly thermally conductive material dispersed in a carrier fluid into the wellbore at or above the fracturing pressure to at least partially fill the fracture with the slurry; and reducing pressure at the target location and in the fracture, thereby partially closing the fracture and displacing at least a portion of the carrier fluid from the slurry in the fracture, thereby forming a fracture containing compressed high thermal conductivity material, the compressed high thermal conductivity material terminating at a proximal end of the wellbore and extending to a distal end within the formation; A method comprising:

2. The method of claim 1 , wherein the fluid is water.

3. The method of claim 1 , wherein the target location is at least 500 feet underground.

4. The method of claim 1 , wherein the target location has a target temperature of at least 300° C.

5. the fracture extends distally from the wellbore a distance of at least three feet; The method of claim 1.

6. 2. The method of claim 1, wherein the high thermal conductivity material is selected from the group consisting of graphite powder, flake graphite, pyrolytic graphite, desulfurized petroleum coke, graphene, fly ash, copper powder, aluminum nitride, and silicon carbide.

7. The method of claim 1 , wherein the slurry comprises water, the high thermal conductivity material, and optionally a plasticizer, a surfactant, an organic polymer, or a combination thereof.

8. The method of claim 1 , wherein the compressed high thermal conductivity material has a solids content of at least 10% by volume.

9. The method of claim 1 , wherein the compressed high thermal conductivity material has a solids content of at least 25% by volume.

10. The method of claim 1 , wherein the compressed high thermal conductivity material has a thermal conductivity of at least 20 W / m°K.

11. The method of claim 1 , wherein the compressed high thermal conductivity material has a thermal conductivity of at least 40 W / m°K.

12. The method of claim 1 , wherein the compressed high thermal conductivity material has a thermal conductivity of at least 80 W / m°K.

13. 13. The method of any one of claims 1 to 12, further comprising placing a high thermal conductivity composition in the wellbore, the high thermal conductivity composition contacting a proximal end of the compressed high thermal conductivity material and an outer surface of a casing disposed in the wellbore.

14. The method of claim 13 , wherein the highly thermally conductive composition is a highly thermally conductive grout.

15. The method of claim 13 , wherein the high thermal conductivity composition is a compressed high thermal conductivity slurry.

16. The method of any one of claims 1 to 15, wherein the target location has a target temperature of at least 400°C.

17. The method of any one of the preceding claims, wherein the target location has a target temperature of at least 500°C.

18. The method according to any one of the preceding claims, wherein the target locations extend in a substantially vertical direction.

19. 1. A geothermal well having enhanced heat delivery, comprising: a wellbore extending from an upper surface to a target location in an earth formation, a plurality of fractures extending distally from the target location into the earth formation and at least partially filled with a compressed high thermal conductivity material, the compressed high thermal conductivity material terminating at a proximal end of the wellbore to the target location; Geothermal wells, including

20. 20. The well of claim 19, wherein the target location is at least 500 feet below ground.

21. The wellbore of claim 19 , wherein the target location has a target temperature of at least 300° C.

22. 20. The wellbore of claim 19, wherein the fracture extends distally from the wellbore a distance of at least 3 feet.

23. 20. The well of claim 19, wherein the high thermal conductivity material is selected from the group consisting of graphite powder, flake graphite, pyrolytic graphite, desulfurized petroleum coke, graphene, fly ash, copper powder, aluminum nitride, and silicon carbide.

24. 20. The wellbore of claim 19, wherein the compressed high thermal conductivity material has a thermal conductivity of at least 20 W / m°K.

25. 20. The wellbore of claim 19, wherein the compressed high thermal conductivity material has a thermal conductivity of at least 40 W / m°K.

26. The wellbore of any one of claims 19 to 25, wherein the wellbore further comprises a high thermal conductivity composition in contact with a proximal end of the compressed high thermal conductivity material and an outer surface of a casing disposed within the wellbore.

27. 27. The wellbore of claim 26, wherein the highly thermally conductive composition is a highly thermally conductive grout.

28. 30. The wellbore of claim 27, wherein the high thermal conductivity composition is a compressed high thermal conductivity slurry.

29. 1. A method for extracting heat from a geological formation, comprising: installing a closed-loop working fluid conduit in a wellbore having a target location in an earth formation, the target location having a target temperature of at least 300° C., the closed-loop working fluid conduit being thermally coupled to a high thermal conductivity composition in contact with a compressed high thermal conductivity material, the compressed high thermal conductivity material extending from the target location to a plurality of fractures in the earth formation; transferring heat from the formation through the high thermal conductivity material and the high thermal conductivity composition in the fracture to a working fluid in the closed loop working fluid conduit; A method comprising:

30. 30. The method of claim 29, wherein the target location is at least 500 feet underground.

31. 30. The method of claim 29, wherein the target location has a target temperature of at least 400 degrees Celsius.

32. 30. The method of claim 29, wherein the fracture extends distally from the wellbore a distance of at least 3 feet.

33. 30. The method of claim 29, wherein the high thermal conductivity material is selected from the group consisting of graphite powder, flake graphite, pyrolytic graphite, desulfurized petroleum coke, graphene, fly ash, copper powder, aluminum nitride, and silicon carbide.

34. 30. The method of claim 29, wherein the compressed high thermal conductivity material has a thermal conductivity of at least 40 W / m°K.

35. A method according to any one of claims 29 to 34, wherein the highly thermally conductive composition is a highly thermally conductive grout.

36. The method of any one of claims 29 to 34, wherein the high thermal conductivity composition is a compressed high thermal conductivity slurry.

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