COOLING FOR GEOTHERMAL WELL DRILLING

Abstract

One method for drilling a geothermal well in an underground zone involves drilling a wellhead into the geothermal zone using a drill string. The inherent temperature of the rock adjacent to a rock face at the bottom of the well is at least 250 degrees Celsius. During drilling, a drilling fluid is flowed into the rock face at a temperature such that the difference between the inherent temperature of the rock adjacent to the rock face and the temperature of the drilling fluid in the rock face is at least 100 degrees Celsius.

Description

This disclosure refers to the drilling of geothermal wells. Background of invention Wells drilled for geothermal systems can encounter high formation temperatures. These high temperatures can create challenges regarding the rate of penetration, the operation of downhole electronics, and other factors. Brief description of the invention This disclosure refers to the drilling of geothermal wells. Certain aspects of the subject matter of this document can be implemented as a method for drilling a geothermal well in an underground zone. The method includes drilling, with a drill string, a wellhead of the geothermal well in the underground zone. The inherent temperature of the rock adjacent to a rock wall at the bottom end of the well is at least 250 degrees Celsius. During drilling, a drilling fluid is flowed into the rock wall at a temperature such that the difference between the inherent temperature of the rock adjacent to the rock wall and the temperature of the drilling fluid in the rock wall is at least 100 degrees Celsius. An aspect that can be combined with any of the other aspects may include the following characteristics. The difference between the inherent temperature of the rock adjacent to the rock wall and the temperature of the drilling fluid in the rock wall causes a thermally induced stress in the rock in the rock wall that is greater than the tensile strength of the rock in the rock wall. An aspect that can be combined with any of the other aspects may include the following characteristics. The bottom end of the well is located at a measured depth of at least 4000 meters. An aspect that can be combined with any of the other aspects may include the following characteristics. The bottom end of the well is located at a vertical depth of at least 6000 meters. An aspect that can be combined with any of the other aspects may include the following characteristics. The difference between the inherent temperature of the rock adjacent to the rock wall and the temperature of the drilling fluid in the rock wall is at least 175 degrees Celsius. An aspect that can be combined with any of the other aspects may include the following characteristics. The inherent temperature of the rock adjacent to the rock wall is at least 350 degrees Celsius and the difference between the inherent temperature of the rock adjacent to the rock wall and the temperature of the drilling fluid in the rock wall is at least 200 degrees Celsius. ηίτζηη / ρζηζ / Ε / γίΛΐ An aspect that can be combined with any of the other aspects may include the following characteristics. The inherent temperature of the rock adjacent to the rock wall is at least 500 degrees Celsius, and the difference between the inherent temperature of the rock adjacent to the rock wall and the temperature of the drilling fluid in the rock wall is at least 350 degrees Celsius. An aspect that can be combined with any of the other aspects may include the following characteristics. The well is a lateral well. An aspect that can be combined with any of the other aspects may include the following features. The bottom end of the drill string comprises a rotating drill bit. An aspect that can be combined with any of the other aspects may include the following features. The bottom end of the drill string comprises a non-contact drill bit configured to break the formation material in the rock wall without requiring contact between the drill bit and the rock wall. An aspect that can be combined with any of the other aspects may include the following characteristics. A closed-loop geothermal well system is formed, which includes the well. An aspect that can be combined with any of the other aspects may include the following characteristics. The well is a lateral well. Establishing the closed-loop system involves drilling the lateral well from a first surface well and connecting, via the lateral well, the first surface well to a second surface well. An aspect that can be combined with any of the other aspects may include the following characteristics. The difference between the inherent temperature of the rock adjacent to the rock wall and the temperature of the drilling fluid in the rock wall induces radial tensile fractures in at least a portion of the wellbore wall. The method also includes sealing the radial tensile fractures with a sealing material. An aspect that can be combined with any of the other aspects may include the following characteristics. The drill string includes a plurality of tubular segments. At least one of the tubular segments includes a coating layer that at least partially covers a circumferential surface of the tubular segment. A standardized length thermal resistance of a coated wall portion of the pipe string is at least 0.002 meters Kelvin per watt. An aspect that can be combined with any of the other aspects may include the following characteristics. A standardized thermal resistance along the length of the coated wall portion is at least 0.01 meters Kelvin per watt. An aspect that can be combined with any of the other aspects may include the following characteristics. The plurality of tubular segments are connected to each other by connecting joints. The coating layer covers at least partially a circumferential surface of one or more connecting joints. An aspect that can be combined with any of the other aspects may include the following characteristics. The well is a first well. The method also includes the formation of a second well that intersects the first well. A second stream of drilling fluid flows through the second well, and this second stream provides at least a portion of the drilling fluid that flows into the rock face. In addition to, or instead of, the second stream, a return stream of drilling fluid is diverted from the bottom end of the first well into the second well. An aspect that can be combined with any of the other aspects may include the following characteristics. The method also includes placing an intermediate tubular string in the well and placing the drill string inside the intermediate tubular string. In this way, an internal annular space is formed between the outside of the drill string and the inside of the intermediate tubular string, extending at least partially along the bottom of the well along the length of the drill string. The method also includes at least partially filling the internal annular space with an insulating material. An aspect that can be combined with any of the other aspects may include the following characteristics. The insulating material is or includes a gas. An aspect that can be combined with any of the other aspects may include the following characteristics. The method also includes adding to the drilling fluid a specified phase-change material to undergo a phase change near the bottom end of the drill string. An aspect that can be combined with any of the other aspects may include the following characteristics. The drill string includes a well portion comprising a first plurality of tubular segments and a well portion comprising a second plurality of tubular segments. The majority of the first plurality of tubular segments have a tensile strength at least 25% greater than the tensile strength of the majority of the second plurality of tubular segments. The majority of the second plurality of tubular segments are at least 35% lighter than the majority of the first plurality of tubular segments. Certain aspects of the subject matter of this document can be implemented as a method for establishing a geotechnical system in an underground zone. The method includes drilling a first surface well and a second surface well. A lateral is drilled from the first surface well to connect it to the second surface well in the underground zone. Drilling the lateral includes installing a drill string in the lateral. The drill string defines a conduit for injecting drilling fluid into a rock face at the bottom of the lateral to displace fragmented formation material from the rock face. ηίτζηη / ρζηζ / Ε / γίΛΐ The method also includes drilling the lateral well deeper into the underground zone with the drill string. The inherent temperature of the rock adjacent to the rock face at the bottom of the lateral well is at least 250 degrees Celsius. The drilling fluid flows into the lateral well at a rock face temperature at least 100 degrees Celsius cooler than the inherent temperature of the rock adjacent to the rock face. The drill string is pulled from the lateral well, and a working fluid is circulated in a closed loop through the first surface well, the second surface well, and the lateral well. An aspect that can be combined with any of the other aspects may include the following characteristics. Thermal energy is extracted from the working fluid. Certain aspects of the subject matter of this document can be implemented as a system for drilling a well into a geothermal well in an underground zone. The inherent temperature of the rock adjacent to a rock wall at the bottom of the well is at least 250 degrees Celsius. The system includes a drill string with a drill bit to break through a formation in the rock wall, and a drilling fluid circulating in the rock wall at a temperature such that the difference between the inherent temperature of the rock adjacent to the rock wall and the temperature of the drilling fluid in the rock wall is at least 100 degrees Celsius. An aspect that can be combined with any of the other aspects may include the following characteristics. The difference between the inherent temperature of the rock adjacent to the rock wall and the temperature of the drilling fluid in the rock wall causes a thermally induced stress in the rock in the rock wall that is greater than the tensile strength of the rock in the rock wall. An aspect that can be combined with any of the other aspects may include the following characteristics. The bottom end of the well is located at a measured depth of at least 4000 meters. An aspect that can be combined with any of the other aspects may include the following characteristics. The difference between the inherent temperature of the rock adjacent to the rock wall and the temperature of the drilling fluid in the rock wall is at least 175 degrees Celsius. An aspect that can be combined with any of the other aspects may include the following characteristics. The inherent temperature of the rock adjacent to the rock wall is at least 350 degrees Celsius and the difference between the inherent temperature of the rock adjacent to the rock wall and the temperature of the drilling fluid in the rock wall is at least 200 degrees Celsius. An aspect that can be combined with any of the other aspects may include the following characteristics. The well is a lateral well. Brief description of the drawings Figure 1A is a schematic illustration of a closed-loop geothermal system in accordance with the concepts of this document. Figure IB is a plan view of the closed-loop geotechnical system illustrated in Figure 1A. Figure 2 is a schematic illustration of a drilling system according to the concepts in this document. Figure 3A is a schematic illustration of a drill bit according to the concepts in this document. Figure 3B is a schematic illustration of a cross-section of a drill bit cone according to the concepts of this document. Figure 4A is a graphical representation of the temperature-pressure relationship for the brittle to semi-brittle transition in ductile or plastic rocks according to the concepts of this document. Figure 4B is a graphical representation of the brittle-semi-brittle transition in brittle igneous rocks according to the concepts of this document. Figure 5 is a graphical representation of the effect of deformation and stress on brittle and ductile rocks according to the concepts of this document. Figure 6A is a graphical representation of the relationship between rock fragility and penetration index. Figure 6B is an illustration of the relationship between rock damage from drilling operations and a cooling temperature differential. Figure 7 is a graphical representation of the results of laboratory penetration index tests as a function of the temperature difference between the drilling fluid and the rock being drilled. Figure 8A is an illustration of coated pipe segments of a drill string according to the concepts in this document. Figure 8B is an illustration of coated pipe segments of a drill string according to the concepts in this document. Figures 9A-9D are illustrations of the relationship between vertical depth and temperature of drill pipe, annular space and rock with pipe segments with different casing configurations according to the concepts of this document. Figure 10 is an illustration of the relationship between the maximum temperature of the drillable rock and the thermal gradient for different tubular segment lining configurations according to the concepts of this document. Figure 11 is a schematic representation of the resistance to heat transfer through the annular space and different pipe configurations according to the concepts of this document. Figure 12 is a schematic illustration of a well system with a second insulating annular space according to the concepts of this document. Figures 13A-13B are an illustration of the thermal effect of the second insulating annular space of Figure 12. Figure 14 is a schematic illustration of a well system for drilling with a second well serving as an inlet and / or outlet for drilling fluid according to the concepts of this document. Detailed description of the invention Figure 1A shows a closed-loop geotechnical system according to the concepts in this document. The closed-loop geotechnical well system could be, for example, a system like the one developed by Eavor Technologies Inc. of Calgary, Alberta, which includes a network of sealed horizontal wells that act as a radiator or heat exchanger with the downhole formation. Descriptions of the methods and apparatus used in some examples of such a closed-loop geotechnical system can be found, for example, in U.S. Patent Application Publication Numbers 20190154010A1, 20190346181A1, and 20200011151A1, the contents of which are incorporated herein by reference. With reference to Figure 1A, the closed-loop geotechnical system 100 includes an inlet surface well 104 and an outlet surface well 106 connected within the underground zone 108 by a network of lateral wells 110. The underground zone 108 is a geologic formation, a part of a geologic formation, or multiple geologic formations. In the illustrated example, the surface wells 104 and 106 are substantially vertical; in other examples in this disclosure, one or both surface wells may be other than substantially vertical. In the illustrated example, the lateral wells 110 connecting the surface wells 104 and 106 are substantially horizontal; in some examples in this disclosure, some or all of the laterals may not be substantially horizontal and may be substantially straight or wedge-shaped or have a spiral or other configuration.The lateral wells 110 can be sealed, and a working fluid can be added to the closed loop as the circulating fluid. The power generation station 112 is located at surface 114 between the inlet surface well 104 and the outlet surface well 106 to complete the closed-loop system. Heat from the underground zone 108 is recovered from the working fluid circulating in the loop circuit 116 and subsequently used to generate power with a generator (not shown) at the power generation station 112. In some examples in this disclosure, the lateral wells 110 can be anywhere from 2,000 meters to 8,000 meters or more in length and from 1,000 meters to 20,000 meters in depth from surface 114. ηίτζηη / ρζηζ / Ε / γίΛΐ Figure IB is a plan view of the lateral wells 110 that are part of the closed-loop geotechnical system 100 of Figure 1A. Referring to Figure IB, the lateral wells 110 are located within the underground zone 108 in a separate radial arrangement. Each of the lateral wells 110 is commonly connected to the inlet well 104 and the outlet well 106 in a closed loop. In some examples in this disclosure, some or all of the inlet wells 104 and outlet wells 106 are lined. In some examples in this disclosure, the lateral wells 110 are not lined but are sealed without the use of lining by forming an interface between the lateral well and the formation that is substantially impermeable to fluids. Although Figures 1A and 1B show inlet shaft 104 well separated from outlet shaft 106, in other examples in this disclosure, shafts 104 and 106 may be together and the network of side shafts 110 may be stacked or interleaved and cross at their ends. Drilling through a geotechnical system like the one shown in Figures 1A and 1B can involve drilling through very hard polycrystalline rock, such as granite, at very high temperatures (over 250°C and in some environments over 400°C or even over 800°C). Such hard, high-temperature rock can be encountered, for example, when drilling deep horizontal well segments, as illustrated in Figures 1A and 1B. Figure 2 is a schematic illustration of a well drilling system 200 according to an example in this disclosure, which may be suitable for drilling the inlet surface well 104, the outlet surface well 106, and / or the side wells 110 of Figures 1A and 1B. Referring to Figure 2, well 202 is formed in a subsurface zone 204 by drilling with the drill string 206 set in well 202. The drill string 206 includes a bottom hole assembly (BHA) 210 at its bottom-of-well end. The BHA 210 includes the drill bit 208 and may further include drill collars, directional drilling instrumentation, and various electrical and electronic components for operating and / or controlling the drill bit 208.The interior of drill string 206 defines a conduit for flowing drilling fluid 212 to the bottom end of the well to displace fragmented formation material from the rock wall 214, which is then carried upward by the drilling fluid 212 through the annular space 216 defined between the outside of drill string 206 and the inside surface of well 202. The drill string 206 includes a plurality of tubular segments 220 connected together at connection joints 222. In some examples in this disclosure, the connection joints 222 comprise threaded box and pin joints or other suitable connection. The heat transfer – illustrated by arrows 224 – can flow from the underground zone 204 to the annular space 216, as well as from the annular space 216 into the interior of the drill string 206 and into the drilling fluid 212 that flows down the drill string 206. Consequently, the heat transfer from the underground zone 108 to the annular space 216 and from the annular space 216 to the interior of the drill string 206 contributes to raising the temperature of the drilling fluid 212 before its delivery to the drill bit 208 by means of the countercurrent exchange mechanism. In some examples in this disclosure, the drill bit 208 is a contact-type drill bit, such as a polycrystalline diamond compact (PDC) drill bit, a rotary drill bit, and / or another type of drill bit that relies on contact with the rock to effect drilling. An example of a suitable contact-type drill bit is the trichorn bit 300 shown in Figures 3A and 3B. As shown in Figure 3A, the trichorn bit 300 includes three cones 302, each with a plurality of cutting elements 304. Figure 3B illustrates a detail of a section along line 305A–305B shown in Figure 3A. In this example, each cone 302 includes a plurality of separate cutting elements 304 in a specific separate arrangement on the face of each cone.To facilitate extended service life and prolonged uninterrupted drilling, a series of additional 306 cutting elements can be provided. In this example, the additional 306 cutting elements are positioned beneath the 304 cutting elements such that the vertices of the additional 306 cutting elements are adjacent to the contact point of the bases of the overlapping 304 cutting elements. In this arrangement, as the 304 elements wear, the vertices of the additional 306 cutting elements emerge. This process can be further accelerated by incorporating a material of different hardness, at least in the interstitial spaces 310 between the adjacent 304 and 306 elements. With this arrangement, the cutting face of each cone is self-renewing.Additional advantages of this feature include the benefit of more even wear of the 300 bit to reduce the progress of eccentric drilling and the possibility of getting stuck or becoming stuck / unrecoverable within the forming hole. In other examples in this disclosure, the drill bit 208 in Figure 2 may be a non-contact drill bit configured to break formation material in the rock wall 214 of the subsurface zone 204 at the downhole end of well 202 without requiring contact between the bit 208 and the rock wall 214, and in some examples in this disclosure, it may comprise an electro-shredding bit for electropulsed drilling. Examples of non-contact drilling systems include plasma drilling (such as the plasma drilling system developed by GA Drilling, AS).), laser drilling (such as the laser drilling system developed by Foro Energy), microwave drilling (such as the microwave drilling system developed by Quaise), thermal spallation techniques such as supercritical water jetting or flame jetting, and electropulse drilling (such as the electropulse drilling systems developed by Tetra Corporation). (It is understood that parts of a non-contact drill bit may periodically strike, rub against, or come into contact with the formation during the drilling process.) In electropulse drilling systems like the one developed by Tetra Corporation, an electro-titration bit with multiple electrodes is used to generate high-energy sparks that break up formation material, allowing it to be removed from the path of the drill string. The bit can generate multiple sparks per second using a specific excitation current profile that causes a transient spark and arc to form across the most conductive portion of the rock wall at the downhole end of the well. The arc causes the portion of the rock wall penetrated by the arc to disintegrate or fragment and be carried away by the flow of drilling fluid. A highly resistive drilling fluid is used for this type of electropulse drilling.Descriptions of some electropulse drilling bits, drilling fluids, and related systems and methods are found, for example, in U.S. Patent Number 4,741,405, U.S. Patent Number 9,027,669, U.S. Patent Number 9,279,322, U.S. Patent Number 10,060,195, U.S. Publication Number 20200299562A1, and PCT patent applications WO 2008 / 003092, WO 2010 027866, WO 2014 / 008483, WO 2018 / 136033, and WO 2020 / 236189, the contents of which are incorporated herein by reference. Because electropulse drilling and other forms of non-contact drilling fail in rock under tension (as opposed to compression or shear), there may be an additional synergistic effect with the cooling effects described in more detail below. The rate of penetration (ROP) can be reduced when the rock is under very high confining pressures and / or has ductile / plastic characteristics due to the high temperatures encountered when drilling in deep geotechnical environments, such as when drilling (for example) 110 lateral wells of a closed-loop system as illustrated in Figures 1A and 1B. These high temperatures can also interfere with the operation of downhole sensors and / or electronics. Furthermore, drilling multiple lateral wells, as shown in Figure 1B, may require the extensive use of directional drilling technology. Magnetometers and other downhole equipment used for such directional drilling can be negatively affected by the high downhole temperatures.Some downhole components for directional drilling systems have a temperature limit of 150-250°C. Other downhole components may have a different temperature limit or range (higher or lower). In some examples in this disclosure, as disclosed below, combinations of casing, wellbore geometries, downhole equipment, and / or additives are used to provide drilling fluid flow at the downhole end of the well at a temperature such that the difference between the inherent temperature of the rock adjacent to the rock wall (i.e., the temperature, except for the cooling effects of the drilling fluid, of the rock ahead of the drill bit to be drilled immanently) and the temperature of the drilling fluid at the rock wall is at least 100°C. The temperature of the fluid at the rock wall is the temperature of the bulk fluid where convective cooling of the rock wall occurs, for example, within approximately 1 cm of the rock wall being drilled.In some examples in this disclosure, this temperature difference may be in geothermal environments where the inherent temperature of the rock adjacent to the rock wall is at least 250°C at a measured depth of 4,000 meters or more; that is, the depth measured through the surface well and the side well. (As used herein, measured depth is the length along the path of a well and differs from the vertical depth of a well in all but a truly vertical well.) In some examples in this disclosure, the temperature difference may be greater. For example, in one example in this disclosure where the inherent temperature of the rock adjacent to the rock wall is at least approximately 500°C, the difference between the inherent temperature of the rock adjacent to the rock wall and the temperature of the drilling fluid in the rock wall may be at least about 350°C.In other examples in this disclosure, the temperature difference may be larger or smaller. Such a large temperature difference can increase the rate of penetration (ROP) due to the rapid cooling effect, which causes the rock wall to thermally contract. This puts the rock under tension and reduces the effective confining pressure within the rock wall. It can also create tensile microfractures within the rock matrix. For example, Figure 4A is a graphical representation of the temperature-pressure relationship for the brittle-to-semi-brittle transition in ductile or plastic rocks. Ductile rock transitions to a more brittle state when the temperature or pressure decreases. When a rapid thermal cooling treatment is applied to a hot, brittle rock, the rock's internal temperature decreases, and the rock transitions to a more brittle state relative to the untreated rock. Figure 4B generally illustrates this result. Consequently, this zonal change from ductile to semi-brittle, and any combination thereof, through temperature manipulation, causes the treated rock to become brittle relative to its initial untreated state. The strength of the rock (the stress required to cause irreversible deformation) does not necessarily change with an increase in brittleness, as shown in Figure 5. However, the deformation mode of a brittle rock is sudden failure and fracturing, whereas, for a more ductile rock, the failure mode is to undergo more plastic deformation before failure. As shown in Figure 6A, the penetration rate generally increases with the brittleness of the rock, regardless of the drilling method. In particular, pulsed electric drilling systems or other non-contact drilling systems may be especially suitable for brittle rocks. Figure 6B shows the relationship between internal rock damage and cooling temperature (e.g., in drilling operations). Note that internal damage is a separate and additional effect to the embrittlement mechanism described earlier. A higher cooling temperature differential is required to cause irreversible damage within the rock, rather than simple embrittlement. Irreversible damage manifests as microcracks, fractures, and displacement between rock grains due to differential thermal contraction. With sufficient thermal cooling, both embrittlement and subsequent irreversible damage can be induced in the rock being drilled. Figure 7 is a graphical representation of the results of laboratory penetration index tests as a function of the temperature difference between the drilling fluid and the rock being drilled. The laboratory tests were performed on 25.4 cm (10 in.) diameter granite blocks, which were heated in a furnace to the desired temperature. The blocks were then placed in a pressurized chamber, which was pressurized to simulate a depth of approximately 1000 m, both with respect to confining pressure (applied to a sleeve surrounding the rock sample) and hydrostatic pressure of the drilling fluid. The rock samples were then drilled with consistent weight on bit, rpm, and flow rate using drilling fluid at ambient temperature.As can be seen in Figure 7, the rate of penetration (ROP) increases substantially when the temperature difference between the rock being drilled and the drilling fluid temperature exceeds 175 degrees Celsius. With such a temperature differential, the thermally induced stress in the rock face can exceed the rock's tensile strength, weakening it and causing cracks that increase the rate of penetration. Larger increases in the temperature differential result in a greater improvement in ROP. Furthermore, rapid cooling can reduce the effective lithostatic confining pressure in the rock wall through thermal contraction. In bench-scale tests without rapid cooling, drilling typically exhibits a decreasing rate of penetration (ROP) with increasing confining pressure. Therefore, the rapid cooling effect alone can enable improved performance in deep rock under high confining pressure. In some examples in this disclosure, the difference between the inherent temperature of the rock adjacent to the rock wall and the temperature of the drilling fluid in the rock wall is sufficient to induce embrittlement of the formation in the rock wall. When an embrittled rock fails, it can break suddenly and without plastic deformation of the material. ηίτζηη / ρζηζ / Ε / γίΛΐ In some examples in this disclosure, the difference between the inherent temperature of the rock adjacent to the rock wall and the temperature of the drilling fluid in the rock wall is sufficient to reduce the tensile strength of the rock and / or damage the rock microstructure (which can reduce the rock's strength due to small microfractures and weaknesses within the rock matrix) and / or induce spalling in the rock wall due to thermal contraction of the rock. In some examples in this disclosure, the temperature difference is sufficient to reduce the confining pressure in the rock wall (by thermally contracting the rock and inducing fractures). If thermal contraction occurs to the point where fractures are created in the rock wall, it will lose confining pressure and become easier to break. In some examples in this disclosure, the difference between the inherent temperature of the rock adjacent to the rock wall and the temperature of the drilling fluid in the rock wall is sufficient to keep the bottom hole assembly (BHA) cool and at a relatively constant temperature even when drilling rock at temperatures of 250°C to 500°C or higher, and at depths of 2–14 km or more. Such cooling can be particularly advantageous in the case of electropulse drilling, since this technology inherently requires the generation and transmission of power in the BHA, and electrical resistance increases with increasing temperature. Regardless of the rock-breaking method, some downhole electronics, circuit boards, batteries, and other downhole components may have temperature limits of 150–200°C. (Some downhole components may have a different (higher or lower) temperature limit.)By using a cooling system as described in this disclosure, these components are kept below their temperature limits even when drilling through very hot rock. Furthermore, by cooling the magnetometers and other downhole components of directional drilling systems, some examples described in this disclosure may allow the use of directional drilling in rock environments at higher temperatures than was previously possible. Therefore, by providing a large temperature differential between the rock adjacent to the rock wall and the drilling fluid in the rock wall, the improved cooling methods and systems disclosed herein may allow the use of a drilling system (such as an electropulse drill) and directional drilling components to drill the multiple horizontal wells of a closed-loop geothermal system in a high formation temperature environment (such as that illustrated in Figure IB), with improved downhole electronic performance of the drill and a higher ROP. In some examples in this disclosure, enhanced cooling can be used to drill all the wells in the systems shown in Figures 1A and 1B. Because the highest temperature rock may be found in the formations through which the lateral wells 110 are drilled, in some examples in this disclosure, conventional cooling without advanced cooling can be used to drill the vertical well components of Figures 1A and 1B, and enhanced cooling can be used to drill some or all of the lateral wells 110. Rapid cooling can have a greater effect on the rate of penetration (ROP) when the rock is hot, for example, above 250°C; therefore, enhanced cooling may be particularly suitable for wells where most of the drilling is done within very hot rock.The ROP advantage can be reduced in a single vertical or deviated well; however, the advantage can be significant if a network of wells is drilled deep into the hot rock, as the examples shown in Figures 1A and 1B. Figure 8A illustrates cooling coatings applied to the tubular segments 220 of the drill string 206 of Figure 2 according to an example in this disclosure. The tubular segments 220 are connected to each other at the connecting joints 222 and comprise a main body 802. In some examples in this disclosure, the main body 802 comprises a carbon steel body. In other examples in this disclosure, the main body 802 may comprise an aluminum alloy, a titanium alloy, and / or a fiber composite (for example, a polymer binder composite with carbon fiber, aramid fiber, glass fiber, electrochromic glass, and / or other structural fiber), as described in more detail below. The inner coating layer 804 at least partially covers the inner circumferential surface of the tubular segments 220.In the illustrated example, the inner coating layer covers the entire length of the tubular segments 220 and also the inner surface of the connecting joint 222. In some examples in this disclosure, the connecting joints 222 can be a significant area of ​​heat transfer. Covering the inner surface of the connecting joint 222 with an inner coating layer 804 reduces heat transfer at the connecting joint 222. The outer casing layer 806 at least partially covers the outer circumferential surface of the tubular segment 220. In the illustrated example, the connecting joint 222 has a larger diameter than the main portion of the body 802 and, therefore, may be exposed to more contact and, as a result, greater friction against the wellbore wall or other well system components. In the illustrated example, the outer casing layer 806 covers the portion of the tubular segments 220 between the connecting joints 222 but not the larger diameter area around the connecting joints 222. In this way, the outer casing layer 806 is less exposed to the friction that occurs at the connecting joints 222. In some examples in this disclosure, the 804 inner coating layer comprises one or more novolac epoxy resins, TK340XT and CP-2060, and phenolic epoxy resins, TK34XT and CP-2050. TK products are available from NOV, Inc., while CP products are available from [unclear text - possibly "[ ... Aremco Produces Inc. The thickness of the inner lining layer 804 comprising the phenolic epoxy resin can range from 150 to 250 µm, while the thickness of the inner lining layer 804 comprising the novolac epoxy resin can range from 400 to 1270 µm. The phenolic epoxy resins can have an average thermal conductivity of ~0.8 K / Wm, while the novolac epoxy resin can have an average thermal conductivity of ~0.4 K / Wm. Insulating particles can be added to these or other resins to further reduce the thermal conductivity. In some examples in this disclosure, the outer coating layer 806 comprises an outer fiber composite (such as carbon fiber, an electrochromic glass composite, and / or another fiber composite) approximately 2540 µm thick. These coatings are available from ACPT Inc. and / or Seal for Life Industries. The electrochromic glass may have a thermal conductivity of approximately 0.288 W / mK, while the carbon fiber may have a thermal conductivity of approximately 0.8 W / km. In some examples in this disclosure, the length-normalized thermal resistance of a pipe string wall is at least approximately 0.002 meters Kelvin per watt. In some examples in this disclosure, the length-normalized thermal resistance of a pipe string wall is at least approximately 0.01 meters Kelvin per watt. Referring to Figure 8A, the wall thickness 810 is defined by the inner surface of the inner coating layer 804 and the outer surface of the outer coating layer 806. For the purposes of this disclosure, the length-normalized thermal resistance is the effective conductive thermal resistance of the string for radial heat transfer, considering the different materials along its length, and is the temperature difference required to transmit 1 watt of power over an axial length of 1 meter. The following shows the standardized technical strength in length of the pipe string wall. In some examples in this disclosure, the string has an inner body of steel 802 and an inner coating layer 804 of the materials and thicknesses indicated (but without an outer coating layer 806): ηίτζηη / ρζηζ / Ε / γίΛΐ Coating layer TK34(100 prn) TK34 (250 pm) TK340XT (250 prn) TK340XT (400 prn) Standardized thermal resistance in length 0.00062 0.0010 0.0017 0.0024 The following shows the standardized thermal resistance along the wall length of the pipe string. In some examples in this disclosure, the string has an inner body of steel 802 and an inner coating layer 804 of the materials and thicknesses indicated, plus an outer coating layer 806 (“coating”) of electrochromic glass of a thickness as indicated: ηίτζηη / ρζηζ / Ε / γίΛΐ Coating Layers Standardized Thermal Resistance in Length TK34 (100 pm) + 2.5 mm coating 0.0032 TK34 (100 pm) + 5 mm coating 0.0034 TK34 (250 pm) + 2.5 mm coating 0.0048 TK34 (250 pm) + 5 mm coating 0.0054 TK340XT (250 pm) + 2.5 mm coating 0.0070 TK340XT (250 pm) + 5 mm coating 0.0082 TK340XT (400 pm) + 2.5 mm coating 0.0092 TK340XT (400 pm) + 5 mm coating 0.011 In an example from this disclosure, the drill string 206 of Figure 2 comprises tubular segments 220 as illustrated in Figure 8A comprising an inner lining layer 804 of a novolac TK340XT epoxy resin with a thickness of approximately 400 microns and an outer coating layer of electrochromic glass 806 with a thickness of approximately 5 millimeters. In such a case, assuming a subsurface zone with a thermal gradient of approximately 60°C / km and a drill string with a length of approximately 8,000 m, a water-based drilling fluid with a circulation rate of approximately 3 m³ / min, and a rock wall temperature of approximately 490°C, such a drill string 206 composed of such pipe segments 220 may result in a temperature difference between the rock adjacent to the rock wall and the drilling fluid in the rock wall of approximately 346°C. In another example from this disclosure, the drill string 206 of Figure 2 comprises tubular segments 220 as illustrated in Figure 8A, comprising an inner lining layer 804 of a novolac TK34XT epoxy resin approximately 250 microns thick and an outer coating layer of electrochromic glass 806 approximately 2.5 millimeters thick. In this case, assuming an underground zone with a thermal gradient of 40°C / km and a pipe string approximately 9000 m long, water-based drilling fluid with a circulation rate of approximately 3.5 m³ / min, and a rock wall temperature of approximately 370°C such a drill string 206 composed of such pipe segments 220 can result in a temperature difference between the rock adjacent to the rock wall and the drilling fluid in the rock wall of about 196°C. In other examples in this disclosure, the inner coating layer 804 and / or the outer coating layer 806 may have a greater or lesser thickness and / or may comprise other types of coatings, for example, inorganic ceramic coatings such as silicate-bonded ceramic. Figure 8B illustrates cooling coatings applied to the tubular segments 220 of a drill string 206 of Figure 2 according to another example in this disclosure. In the example shown in Figure 8B, the pipe segments 220 are composite pipe segments comprising a composite main body 850 (which may be made of steel, titanium, aluminum, composite fiber, or other suitable material) connected at connecting joints 222 which may also comprise steel, titanium, aluminum, composite fiber, or other suitable material. Referring to Figure 8B, the inner lining layer 854 at least partially covers an inner circumferential surface of the tube segments 220. In the illustrated example, the inner lining layer 854 covers only the inner circumferential surface of the tube segments 220 at and near the connection joint 222. By covering the area of ​​the inner circumferential surface of the segment 220 at and near the connection joint 222 with an inner lining layer 854, heat transfer at the connection joint 222 is reduced. In other examples in this disclosure, the inner lining layer 854 covers the entire inner circumferential surface of the tube segments 220. In some examples in this disclosure, the inner lining layer 854 of Figure 8B may comprise the same materials and thicknesses as described with reference to the inner lining layer 804 of Figure 8A. In some examples in this disclosure, the inner lining layer 854 may comprise other suitable materials or thicknesses. In some examples in this disclosure, the pipe segments 220 may comprise vacuum-insulated pipe (VIT) wherein the insulation is provided by a vacuum layer within the pipe segment 220, instead of or in addition to the inner lining layer 804 (or 854) and the outer lining layer 806. In some examples in this disclosure, the main body 802 and / or the main body 850 may comprise high strength-to-weight ratio steel drill pipe, such as UD165 steel drill pipe available from NOV, Inc. In some examples in this disclosure, such steel drill pipe may be UD-165 steel drill pipe that may have a yield strength of approximately 165,000 psi (1138 MPa), a pipe tensile strength of approximately 1,000,000 lbf (4.45 MN), a standardized air weight joint length of 24.76 lbf / ft (361.3 N / m), and a joint strength-to-weight ratio of approximately 900 lbf / lbf (900 N / N) in a drill pipe of 5.875 inches (14.92 cm) outside diameter. In some examples in this disclosure, the main body 802 and the main body 850 may comprise drill pipe made of a titanium alloy. In some examples in this disclosure, such titanium alloy drill pipe may comprise TI-6A1-4V titanium alloy and may have a yield strength of approximately 827 MPa (120,000 psi), a pipe tensile strength of approximately 3.34 MN (750,000 lbf), a standardized air-weight joint length of 16 lbf ft (233.8 N / m), and a joint strength-to-weight ratio of approximately 1,000 lbf / lbf (1,000 N / N) in a drill pipe 5.875 inches (14.92 cm) outside diameter. In some examples in this disclosure, the main body 802 and / or the main body 850 may comprise drill pipe made of an aluminum alloy. In some examples in this disclosure, such aluminum alloy drill pipe may comprise Al-Zn-Mg II aluminum alloy and may have a yield strength of approximately 70,000 psi (483 MPa), a pipe tensile strength of approximately 600,000 lbf (2.67 MN), a standard length joint air weight of 15.5 lbf / ft (226 N), and a joint strength-to-weight ratio of approximately 825 lbf / lbf (825 N / N) in a 5.787-inch (14.699 cm) outside diameter drill pipe. In some examples, such an aluminum alloy pipe may comprise FarReach™ drill pipe available from Alcoa Energy Systems.In some examples in this disclosure, such aluminum alloy drill pipe may comprise aluminum drill pipe available from Aluminium Drill Pipe, Inc. In some examples in this disclosure, the main body 802 and / or the main body 850 may comprise carbon fiber composite drill pipe. In some examples in this disclosure, such carbon fiber composite drill pipe may comprise Advance composite drill pipe available from Advance Composite Products & Technology, Inc. In some examples in this disclosure, the drill string 206 of Figure 2 may comprise tubular segments 220, each comprising main bodies 802 and / or 250 of steel, titanium, aluminum, and / or fiber composite as described above. For example, in some examples in this disclosure, each segment of the drill string 206 comprises main bodies 802 and / or 250 of a single material, such as aluminum alloy. In other examples in this disclosure, the drill string 206 may comprise different parts, each comprising a plurality of segments 220 composed of a different material.For example, in some examples in this disclosure, some of the 220 pipe segments of drill string 206 may comprise one main body material (such as aluminum alloy), and the remaining 220 pipe segments of drill string 206 may comprise another main body material (such as steel). In some examples in this disclosure, drill string 206 may comprise two, three, or more parts, each of which comprises 220 pipe segments with main bodies composed of materials different from those of the other parts. In another example, most of the 220 segments in the portion near the 208 drill bit comprise main bodies of a lighter material than the portion above the 208 drill bit, on a length-normalized air weight basis. For the preceding examples, titanium drill pipe is approximately 35% lighter than steel drill pipe, and aluminum drill pipe is approximately 37% lighter. Those 220 segments above the 208 drill bit may comprise main bodies of a higher-strength material. For the preceding examples, UD-165 drill pipe has a tensile strength approximately 67% greater than that of aluminum, and titanium drill pipe has a tensile strength approximately 25% greater than that of aluminum.The difference in tensile strength and weight-to-length ratio can also be achieved with a single material, but with different thicknesses / diameters of drill pipe in the upper part of the well compared to the lower part in a telescopic fashion. In an example from this disclosure, most 220 segments near the drill bit are approximately 35% lighter than most 220 segments at the top of the well, and most 220 segments at the top of the well have approximately 25% greater tensile strength than most 220 segments near the drill bit.The use of different drill string materials allows drilling into much higher-temperature rocks found at greater depths, which require an insulated drill string with sufficient tensile strength to extend to such depths. The materials mentioned above, when properly combined, enable drilling to depths exceeding 9 km, and even up to 14 km or more. The Earth's geothermal gradient results in higher temperatures in deeper rocks. The present rapid cooling technology provides a method for increasing the penetration rate and drilling performance in high-temperature rocks. Therefore, a synergistic effect exists when combining deeper drilling, made possible by combining different weight / strength drill pipe segments, with the cooling technology described herein.Closed-circuit multilateral wells can be drilled to a sufficient depth (and therefore at the rock temperature) to allow the rapid cooling effect, which greatly reduces the time and cost of drilling multilateral wells. Figure 9A illustrates the results of a thermodynamic simulation of heat transfer in fluids flowing in a tabular downhole drill string comprising standard carbon steel pipes within a cased well in an underground zone. The simulation assumes a water drilling fluid pumped at 3.5 cubic meters per minute along the tabular drill string and a temperature gradient from the surface (i.e., from the surface location at the top of the well) to the rock wall (at the bottom of the well) of 50°C / km.With reference to Figure 9A, the curve labeled Drill Pipe is the temperature of the fluid flowing within the tabular drill string at a given depth, the curve labeled Annular Space is the temperature of the fluid flowing within the annular space between the pipe and casing at a given depth, and the curve labeled Rock is the inherent temperature of the rock at a given depth. As shown in Figure 9A, some insulation is provided against heat transfer, such that, at the bottom of the well, the temperature of the fluid in the rock wall is approximately 206°C, while the temperature of the rock is 260°C, representing a temperature difference of approximately 54°C.However, such a temperature difference may be insufficient to provide a sufficiently cool drilling fluid flow to cool downhole electronics or directional drilling equipment, or to provide a rapid cooling effect on the rock wall or other advantages of cold drilling fluid flow for drilling at the bottom of the wellbore as described above. In Figure 9A, the fluid temperature at the rock wall is equal to the annular space temperature at the bottom of the well after the fluid has exited the drill bit. The casings and casing geometries described with reference to Figures 8A and 8B can reduce heat exchange between the cooler fluid descending the drill string and the warmer fluid returning to the annulus during drilling. This can result in a difference between the inherent temperature of the rock adjacent to the rock wall and the temperature of the drilling fluid at the rock wall of at least 100°C, even in geothermal environments where the inherent temperature of the rock adjacent to the rock wall is at least 250°C. For example, Figures 9B–9D illustrate the results of a thermodynamic simulation of heat transfer to a tubular bottomhole, assuming tubular segments as illustrated in Figure 8A, in several examples in this disclosure, as described below.In the simulations illustrated in Figures 9B-9D, the inner casing layer 804 covers the entire length of the tabular segments, including the inner surface of the connecting joints. In Figures 9B-9D, the curve labeled "pipe" is the temperature of the fluid flowing inside the tubular drill string at a given depth, the curve labeled "casing" is the temperature of the fluid flowing within the annular space between the drill pipe and casing at a given depth, and the curve labeled "rock" is the inherent temperature of the rock at a given depth. The drilling fluid flows into the pipe at the surface, through the BHA, through the drill bit, past the rock wall, and into the annular space. The temperature of the drilling fluid at the rock wall is approximately equal to the temperature of the fluid within the annular space at the bottom of the well. Figure 9B illustrates a thermodynamic heat transfer simulation for an example comprising a standard carbon steel pipe with an inner lining 804 comprising a thickness of 400 pm of TK340XT novolac epoxy (and no outer lining 806). The simulation assumes a water drilling fluid pumped at approximately 3.5 cubic meters per minute and a temperature gradient from the earth surface to the rock surface of approximately 50°C / km. As shown in Figure 9B, this example provides a larger temperature differential compared to Figure 7; namely, approximately 91°C at 5000 meters. Figure 9C illustrates a thermodynamic heat transfer simulation for an example comprising a standard carbon steel pipe with an inner lining 804 comprising a 400 µm thickness of TK340XT novolac epoxy and an outer lining 806 comprising a 5 mm electrochromic glass coating. The simulation assumes a water drilling fluid pumped at approximately 3 cubic meters per minute and a temperature gradient from the surface to the rock face of approximately 60°C / km. As shown in Figure 9C, this example provides a temperature differential of approximately 346°C at 8000 meters. Figure 9D illustrates a thermodynamic heat transfer simulation for an example comprising a standard carbon steel pipe with an inner lining 804 comprising a 250 µm thickness of TK34 novolac epoxy and an outer lining 806 comprising a 2.5 mm electrochromic glass coating. The simulation assumes a water drilling fluid pumped at approximately 3.5 cubic meters per minute and a temperature gradient from the surface to the rock face of approximately 40°C / km. As shown in Figure 9D, this example provides a temperature differential of approximately 196°C at 9000 meters. Figure 10 illustrates the maximum rock temperature at which a well can be drilled for the examples described with reference to Figures 9C and 9D, as a function of the thermal gradient from the Earth's surface to the rock wall (at the bottom end of the well), assuming that the temperature of the drilling fluid exiting the drill bit at the rock wall must not exceed 150°C. The upper curve 1002 corresponds to the example described with reference to Figure 9C. For example, at point 1004, the temperature gradient is approximately 60°C / km and the maximum drillable rock temperature is approximately 483°C, using the example described with reference to 9C. The lower curve 1006 corresponds to the example described with reference to Figure 9D.For example, at point 1008, the temperature gradient is approximately 40°C / km and the maximum temperature of the drillable rock is approximately 335°C, using the example described in reference to 9D. In some examples in this disclosure, instead of or in addition to the casing layers 804 and 806 in the tubular segments 220, a phase-change material such as water ice or dry ice may be added to the drilling fluid of a drilling system (for example, the drilling fluid 212 in Figure 2). Phase-change materials can absorb thermal energy as they undergo a phase change (for example, melt). In some examples in this disclosure, the drilling fluid may be pumped at a rate sufficient for the phase-change materials to undergo a phase change near the drill bit. In some examples in this disclosure, a heat exchanger may be added to the system in Figure 2 to cool the drilling fluid 212 as it returns from well 202 and is recirculated at the bottom of the well. In some examples in this disclosure, such a heat exchanger may be located at the surface. Not all of the drilling fluid has to flow through the drill bit to achieve the results described herein. A portion of the drilling fluid can also flow from the drill pipe into the annulus through a port or other device located near the drill bit or near the bottom hole assembly (BHA). Such a configuration can allow for a higher flow rate if components within the downhole assembly have flow restrictions. Figure 11 illustrates the resistance to heat transfer, i.e., the thermal resistance, through the annulus and four different pipe configurations. When cold drilling fluid circulates downhole through the pipe and back through the annulus, the drilling fluid in the annulus is heated by the surrounding rock in the underground zone to Tannulus. The drilling fluid in the annulus, in turn, heats the drilling fluid inside the pipe to Tpipe. In each case, the primary mechanism of heat transfer through the drilling fluid-filled annulus is convection. The flowing drilling fluid, an imperfect convective medium, presents a thermal resistance Rconvection.Annular space. In the case of an uninsulated carbon steel pipe section (CARBON STEEL), steel is an imperfect conductor and exhibits an additive thermal resistance (series) Rconduction. steel. Finally, the main heat transfer mechanism within the drill fluid-filled pipe, which heats the flowing drill fluid itself, is convection. The drill fluid exhibits an additive thermal resistance (series) Rconvection. pipe - When the pipe is completely covered by an insulating coating (COATED CARBON STEEL), the coating represents an additive thermal resistance (series) Rconduction, coating. When composite pipe with steel collars (joints) is used (COMPOSITE and COMPOSITE + COATED COLLAR), the composite pipe and the carbon steel exhibit parallel thermal resistances (Rconduction, composite and Rconduction, steel collar, respectively).In other words, the material with the lowest thermal resistance (i.e., the least insulating material) has the greatest influence on the overall thermal resistance of the pipe segment. Since composite materials typically have higher thermal resistance than steel, coating only the steel collars can significantly increase the overall thermal resistance of the pipe segment. Figure 12 illustrates the creation of a second insulating annular space according to an example in this disclosure. The example in this disclosure described with reference to Figure 12 will be described with reference to the drilling system components 200 of Figure 2. With reference to Figure 12, well 202 is being drilled using a drill string 208 at the bottom end of a drill string 206. Drilling fluid 212 flows down the drill string 206 and out of drill bit 208. The annular space 216 is defined at the bottom of well 202 between the outside of the drill string 206 and well 202.An internal tubular string 1202 is placed inside the wellbore, such that the drill string 206 is placed inside the internal tubular string 1202, thereby forming an internal annular space 1204 between the outside of the drill string 206 and the inside of the internal tubular string 1202 and an external annular space 1206 between the outside of the internal tubular string 1202 and the wellbore 202, each of the internal annular space 1204 and external annular space 1206 extending to the bottom of the wellbore at least partially along the length of the drill string 206. In some examples in this disclosure, the internal annular space 1204 may be filled with an insulating material. In some examples in this disclosure, the insulating material is a gas, thereby creating a gas cap.In other examples in this disclosure, the inner annular space 1204 may be filled with insulating foam or oil or any fluid or material having low thermal conductivity, instead of or in addition to a gas. The inner annular space 1204 isolates the downward-flowing drilling fluid 212 from the heated upward-flowing fluid in the outer annular space 1206. Figures 13A and 13B are a comparison of wellbore fluid temperatures in a well system. Figure 13A illustrates the predicted drilling fluid temperatures at depth in a drilling system without an insulating inner tubular string, and Figure 13B illustrates the drilling fluid temperatures at depth in a drilling system with an insulating inner tubular string providing an inner annular space filled with an insulating gas as described with reference to Figure 12. Although the bottom of the well continues to heat up without insulation below the bottom of the gas cap, the temperature at the rock wall still cools dramatically.The internal annular space 1204 in this example only extends to the bottom of the last casing string; however, substantial cooling is still achieved at the rock wall (of a main well and / or a lateral drilled from a main well). The insulating fluid layer remains in place due to its much lower density and therefore essentially floats on top of the drilling fluid. Due to the lower density of the fluid cap, it is pressurized at the wellhead at the surface (not shown). Managed pressure drilling (MPD) technology is a system that maintains pressure in an annular space around a rotating drill pipe. The key challenge is sealing the fluid so that it does not escape beyond the rotating pipe. MPD systems have improved sufficiently recently to keep the pressurized fluid cap in place. Therefore, if the fluid cap is filling the internal annular space concentric to a rotating drill pipe, a modern MPD system may be preferable. A variation of this is to install another casing string to create two internal annular spaces (not shown). An internal annular space is placed concentrically and adjacent to a rotating drill pipe, a secondary internal annular space that can be filled with casing fluid, and an external annular space where the heated drilling fluid returns. This configuration requires the costs and complications of a larger borehole to make room for the additional annular space; however, it avoids the use of a high-pressure MPD system, since the internal annular space can be filled with drilling fluid. According to an alternative example in this disclosure, to reduce countercurrent heat transfer from the annulus to the tubing, a second well is used to serve as the inlet and / or outlet for drilling fluids. Figure 14 shows a schematic of this conduit well. With reference to Figure 14, as also described with reference to Figure 2, well 202 is being drilled using a drill bit 208 at the bottom end of a drill string 206. Drilling fluid 212 flows down from the drill string 206 to the drill bit 208. The annular space 216 is defined between the outside of the drill string and well 202. Well 202 may comprise a main well and / or a side well. In the example illustrated in Figure 14, well 202 is a first well, and a second well 1402 is drilled to intersect the first well 202. A second stream 1404 of drilling fluid flows through the second well 1402. The second stream of drilling fluid 1404 provides at least a portion of the drilling fluid flowing at the bottom end of well 202, i.e., at the rock wall near the drill bit 208. The second well 1402 is sufficiently far from the first well 202 to reduce or eliminate heat transfer such that the second stream of drilling fluid 1404 provides additional cooling at the bottom end of well 202. In some examples in this disclosure, the drilling fluid and cuttings can be directed back to the surface through the second well 1402. In this variation, there is no upward flow of heated fluid in the annulus 216, and therefore, countercurrent heat exchange is eliminated above the intersection point 1406. This directional flow is indicated by a dashed line numbered 1408. It will be appreciated that the second well 1402 can be drilled and used to cool any number of additional wells / pipes from the surface location. For example, a closed-loop geothermal well system can be constructed by drilling four corner wells. After one of the four corner wells is drilled, the pipe intersection section is capped and abandoned, and another intersection segment is drilled to intersect another of the corner wells. In this way, a single well can be used multiple times to cool other wells, and only the interconnection segment needs to be drilled each time. Rapid cooling of hot rock using the techniques described herein can lead to several challenges in the drilling process behind the bit. Cooling increases the wellbore's compressive strength but reduces its tensile strength. The significant temperature difference between the circulating drilling fluid and the wellbore wall can cause cooling-induced tensile fractures radially away from the wellbore. These tensile fractures may need to be sealed or controlled with wellbore reinforcement materials, such as graphite or calcium carbonate, or other lost circulation materials. Additionally, the fractures may need to be sealed with a chemical sealant, such as sodium silicate or potassium silicate.Operating the drilling process underbalanced is another method that can be used alone or in conjunction with the other techniques disclosed to mitigate the effects of pull fractures behind the bit. A system design particularly well-suited for electropulse drilling would utilize a pressure-managed drilling system and an oil-based drilling fluid with high electrical resistance and a circulation density equivalent to below hydrostatic pressure. This would allow flexibility in wellbore pressure control while still delivering a drilling fluid suitable for electro-crushing. Another challenge associated with rapid cooling is the potential for induced tension fractures to propagate into shear fractures or create greater complexity, resulting in significant cuts or the removal of varying-sized rock fragments from the wellbore wall behind the drill bit. Combining the other methods with a viscous drilling fluid and a high flow rate (>2.5 nrVmin) can remove the additional fragments generated during the rapid cooling process. In some examples in this disclosure, the drilling fluid may have a Marsh funnel viscosity of at least 80 to 100 seconds. Multiple water additions or sweeps of high-viscosity fluid volumes through the system will also help remove additional fragments.Successful circulation of larger fragments to the surface can be a function of two main parameters: annular fluid velocity (driven by flow rate and annular capacities) and fluid rheology (plastic viscosity / yield point (PV / YP) to add load-carrying capacity / reduce slip velocity, and gel strength to suspend fragments while connections are made). Regular circulation of low-volume / high-viscosity sweeps can transport and suspend larger fragments to the surface. In some examples in this disclosure, fragments can be trapped (i.e., filtered and removed) at the surface to avoid or reduce contamination of the base drilling fluid. By reducing heat exchange between the cooler fluid descending through the pipe string and the warmer fluid returning to the annulus during drilling, the casings and casing geometries described with reference to Figures 8A and 8B, and the methods and systems described with reference to Figures 12 and 14 can also reduce the negative impact of higher formation temperatures on the fraction strength and other properties of pipe segments in the pipe string (such as the tubular segments 220 of drill string 206 in Figure 2). The methods, systems, and devices described above for improving the cooling of the drilling fluid can be used alone or in combination with each other. In this disclosure, the terms "a," "one," or "the" are used to include one or more of the same, unless the context clearly indicates otherwise. The term "or" is used to refer to one or not exclusively, unless otherwise stated. The statement "at least one of A and B" has the same meaning as A, B, or A and B. Furthermore, it should be understood that the phrasing or terminology employed in this disclosure, and not defined otherwise, is for descriptive purposes only and not for limitation. Any use of section headings is intended to facilitate readability of the document and should not be construed as a limitation; information that is relevant to a section heading may appear within or outside that particular section. While this disclosure contains many implementation-specific details, these should not be interpreted as limitations on the subject matter or on what may be claimed, but rather as descriptions of features that may be specific to particular implementations. Certain features described in this disclosure in the context of separate implementations may also be implemented, in combination or in a single implementation. Conversely, several features described in the context of a single implementation may also be implemented in multiple implementations, separately or in any suitable subcombination.Furthermore, although the features described above may be described as acting in certain combinations and even initially claimed as such, one or more features of a claimed combination may, in some cases, be removed from the combination, and the claimed combination may be directed to a subcombination or variation of a subcombination. Specific implementations of the subject matter have been described. However, it is understood that various modifications, substitutions, and alterations may be made. Although the operations are depicted in the drawings or claims in a particular order, this should not be construed as requiring that these operations be performed in the particular order shown or in sequential order, or that all of the illustrated operations be performed (some operations may be considered optional) to achieve the desired results. Accordingly, the example implementations described above do not define or restrict this disclosure.

Claims

1. A method for drilling a geothermal well in an underground zone, comprising: drilling, with a drill bit, a geothermal well in the underground zone, wherein the inherent temperature of the rock adjacent to a rock wall at the bottom end of the well is at least 250 degrees Celsius; and flowing, during drilling, a drilling fluid at a temperature in the rock wall such that the difference between the inherent temperature of the rock adjacent to the rock wall and the temperature of the drilling fluid in the rock wall is at least 100 degrees Celsius.

2. The method according to claim 1, wherein the difference between the inherent temperature of the rock adjacent to the rock wall and the temperature of the drilling fluid in the rock wall causes a thermally induced stress in the rock in the rock wall that is greater than the tensile strength of the rock in the rock wall.

3. The method according to claim 1, wherein the bottom end of the well is at a measured depth of at least 4000 meters.

4. The method according to claim 1, wherein the bottom end of the well is at a vertical depth of at least 6000 meters.

5. The method according to claim 1, wherein the difference between the inherent temperature of the rock adjacent to the rock wall and the temperature of the drilling fluid in the rock wall is at least 175 degrees Celsius.

6. The method according to claim 1, wherein the inherent temperature of the rock adjacent to the rock wall is at least 350 degrees Celsius and the difference between the inherent temperature of the rock adjacent to the rock wall and the temperature of the drilling fluid in the rock wall is at least 200 degrees Celsius.

7. The method according to claim 1, wherein the inherent temperature of the rock adjacent to the rock wall is at least 500 degrees Celsius and the difference between the inherent temperature of the rock adjacent to the rock wall and the temperature of the drilling fluid in the rock wall is at least 350 degrees Celsius.

8. The method according to claim 1, wherein the well is a side well.

9. The method according to any of claims 1-7, wherein the bottom end of the drill bit comprises a rotating drill bit.

10. The method according to any of claims 1-7, wherein the bottom end of the drill hole comprises a non-contact drill bit configured to break the formation material in the rock wall without requiring contact between the drill bit and the rock wall.

11. The method according to any of claims 1-7, further comprising forming a closed-circuit geothermal well system, wherein the closed-circuit geothermal well system comprises the well.

12. The method according to claim 11, wherein the well is a lateral well and wherein forming the closed circuit system comprises drilling the lateral well from a first surface well and connecting, by means of the lateral well, the first surface well with a second surface well.

13. The method according to any of claims 1-7, wherein the difference between the inherent temperature of the rock adjacent to the rock wall and the temperature of the drilling fluid in the rock wall induces radial tensile fractures in at least a portion of the well wall, and further comprising sealing the radial tensile fractures with a sealing material.

14. The method according to any of claims 1-7, wherein the drill string comprises a plurality of tubular segments, wherein at least one of the tubular segments comprises a coating layer that at least partially covers a circumferential surface of the tubular segment, and wherein a standardized length thermal resistance of a coated wall portion of the pipe string is at least 0.002 meters Kelvin per watt.

15. The method according to claim 14, wherein the standardized thermal resistance along the length of the coated wall portion is at least 0.01 meters Kelvin per watt.

16. The method according to claim 14, wherein the plurality of tubular segments are connected to each other at connection joints, and wherein said coating layer covers at least partially a circumferential surface of one or more of the connection joints.

17. The method according to any one of claims 1-7, wherein the well is a first well and further comprises: forming a second well intersecting with the first well; and at least one of: flowing a second stream of drilling fluid through the second well, wherein the second stream provides at least a portion of the drilling fluid flowing in the rock wall, and diverting a return stream of drilling fluid from the bottom end of the first well to the second well.

18. The method according to claim 1, further comprising: placing an internal tubular string in the well; placing the drill string inside the internal tubular string; thereby forming an internal annular space between the outside of the drill string and the inside of the internal tubular string, which extends at least partially along the bottom of the well; and at least partially filling the internal annular space with an insulating material.

19. The method according to claim 18, wherein the insulating material comprises a gas.

20. The method according to any of claims 1-7, further comprising adding to the drilling fluid a phase change material specified to undergo a phase change near the bottom end of the drill string.

21. The method according to claim 1, wherein the drill string comprises a bottom-of-well portion comprising a first plurality of tubular segments and a bottom-of-well portion comprising a second plurality of tubular segments, and wherein most of the first plurality of tubular segments have a tensile strength at least 25% greater than the tensile strength of most of the second plurality of tubular segments, and most of the second plurality of tubular segments are at least 35% lighter than most of the first plurality of tubular segments.

22. A method for forming a geothermal system in an underground zone, comprising: drilling a first surface well and a second surface well; drilling a lateral well from the first surface well to connect the first surface well with the second surface well in the underground zone, wherein drilling the lateral well comprises: placing a drill string in the lateral well, wherein the drill string defines a conduit for flowing a drilling fluid to a rock wall at a bottom-hole end of the lateral well to displace fragmented formation material from the rock wall; drilling with the drill string the lateral well deeper into the underground zone, wherein the inherent temperature of the rock adjacent to the rock wall at a bottom-hole end of the lateral well is at least 250 degrees Celsius;and flow the drilling fluid into the side well at a temperature in the rock wall at least 100 degrees Celsius cooler than the inherent temperature of the rock adjacent to the rock wall; withdraw the drill string from the side well; and circulate a working fluid in a closed circuit in the first surface well, the second surface well, and the side well; 23. The method according to claim 22, further comprising extracting thermal energy from the working fluid.

24. A system for drilling a well in a geotechnical well in an underground zone, in which the inherent temperature of the rock adjacent to a rock wall at the bottom end of the well is at least 250 degrees Celsius, comprising: a drill string comprising a drill bit for breaking a formation in the rock wall; and a drilling fluid circulating in the rock wall at a temperature such that the difference between the inherent temperature of the rock adjacent to the rock wall and the temperature of the drilling fluid in the rock wall is at least 100 degrees Celsius.

25. The system according to claim 24, wherein the difference between the inherent temperature of the rock adjacent to the rock wall and the temperature of the drilling fluid in the rock wall causes a thermally induced stress in the rock in the rock wall that is greater than the tensile strength of the rock in the rock wall.

26. The system according to claim 24, wherein the bottom end of the well is at a measured depth of at least 4000 meters.

27. The system according to claim 24, wherein the difference between the inherent temperature of the rock adjacent to the rock wall and the temperature of the drilling fluid in the rock wall is at least 175 degrees Celsius.

28. The system according to claim 24, wherein the inherent temperature of the rock adjacent to the rock wall is at least 350 degrees Celsius and the difference between the inherent temperature of the rock adjacent to the rock wall and the temperature of the drilling fluid in the rock wall is at least 200 degrees Celsius.

29. The system according to claim 24, wherein the well is a side well.

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