Cooling for geothermal well drilling

Abstract

A method for drilling a geothermal well in a subsurface region, the method comprising drilling a borehole of the geothermal well in the subsurface region with a drill string. The intrinsic temperature of rock adjacent to a rock face at a downhole end of the borehole is at least 250 degrees Celsius. While drilling, drilling fluid flows at a temperature at the rock face such that the difference between the intrinsic temperature of rock adjacent to the rock face and the temperature of the drilling fluid at the rock face is at least 100 degrees Celsius.

Description

Technical Field

[0001] This disclosure relates to geothermal well drilling. Background Technology

[0002] Wells drilled for geothermal systems may encounter high formation temperatures. These high temperatures can pose challenges to drilling speed, the operation of downhole electronic equipment, and other factors. Summary of the Invention

[0003] This disclosure relates to geothermal well drilling.

[0004] Certain aspects of the subject matter of this paper can be implemented as a method for drilling geothermal wells in subsurface areas. The method involves drilling a wellbore for the geothermal well in a subsurface area using a drill string. The inherent temperature of the rock face adjacent to the bottom end of the wellbore is at least 250 degrees Celsius. During drilling, drilling fluid is circulated at a temperature at the rock face such that the difference between the inherent temperature of the rock face and the temperature of the drilling fluid at the rock face is at least 100 degrees Celsius.

[0005] An aspect that can be combined with any other aspect may include the following characteristic: The difference between the inherent temperature of the rock adjacent to the rock face and the temperature of the drilling fluid at the rock face results in thermally induced stress in the rock at the rock face being greater than the tensile strength of the rock at the rock face.

[0006] An aspect that can be combined with any other aspect may include the following feature: The downhole end of the wellbore is located at a measurement depth of at least 4,000 meters.

[0007] An aspect that can be combined with any other aspect may include the following feature: The downhole end of the wellbore is located at a vertical depth of at least 6,000 meters.

[0008] An aspect that can be combined with any other aspect may include the following feature: The difference between the inherent temperature of the rock adjacent to the rock face and the temperature of the drilling fluid at the rock face is at least 175 degrees Celsius.

[0009] An aspect that can be combined with any other aspect may include the following characteristics: the inherent temperature of the rock adjacent to the rock face is at least 350 degrees Celsius, and the difference between the inherent temperature of the rock adjacent to the rock face and the temperature of the drilling fluid at the rock face is at least 200 degrees Celsius.

[0010] An aspect that can be combined with any other aspect may include the following characteristics: the inherent temperature of the rock adjacent to the rock face is at least 500 degrees Celsius, and the difference between the inherent temperature of the rock adjacent to the rock face and the temperature of the drilling fluid at the rock face is at least 350 degrees Celsius.

[0011] An aspect that can be combined with any other aspect may include the following characteristics: The wellbore is a transverse wellbore.

[0012] An aspect that can be combined with any other aspect may include the following feature: The downhole end of the drill string includes a rotating drill bit.

[0013] An aspect that can be combined with any other aspect may include the following feature: The downhole end of the drill bit includes a non-contact drill bit, which is constructed to break formation material at the rock face without requiring contact between the drill bit and the rock face.

[0014] One aspect, which can be combined with any other aspect, may include the following feature: forming a closed-loop geothermal well system including the wellbore.

[0015] An aspect that can be combined with any other aspect may include the following features: The wellbore is a transverse wellbore. Forming a closed-loop system involves drilling transverse wellbores from a first surface wellbore and connecting the first surface wellbore to a second surface wellbore via the transverse wellbore.

[0016] One aspect, which can be combined with any other aspect, may include the following feature: The difference between the inherent temperature of the rock adjacent to the rock face and the temperature of the drilling fluid at the rock face 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.

[0017] An aspect that can be combined with any other aspect may include the following features: The drill string comprises multiple sections. At least one of the sections includes a coating that at least partially covers the circumferential surface of the section. The normalized thermal resistance of the length of the coated section of the drill string is at least 0.002 m Kelvin per watt.

[0018] One aspect that can be combined with any other aspect may include the following feature: The normalized thermal resistance of the length of the coated tube wall portion is at least 0.01 m Kelvin per watt.

[0019] One aspect, which can be combined with any other aspect, may include the following features: The aforementioned multiple pipe segments are connected to each other at a joint. The coating at least partially covers the circumferential surface of one or more of the joints.

[0020] One aspect, which can be combined with any other aspect, may include the following features: The wellbore is a first wellbore. The method also includes forming a second wellbore intersecting the first wellbore. A second drilling fluid flow flows down into the second wellbore, and this second drilling fluid flow provides at least a portion of the drilling fluid flowing at the rock face. In addition to or in lieu of the second drilling fluid flow, drilling fluid return is diverted from the downhole end of the first wellbore to the second wellbore.

[0021] One aspect, which can be combined with any other aspect, may include the following features. The method also includes positioning an intermediate tubing string in the well and positioning a drill string within the intermediate tubing string. In this manner, an internal annulus is formed between the outside of the drill string and the inside of the intermediate tubing string, the internal annulus extending at least partially downhole along the length of the drill string. The method also includes filling the internal annulus at least partially with an insulating material.

[0022] An aspect that can be combined with any other aspect may include the following feature: The insulating material is a gas or comprises a gas.

[0023] One aspect, which can be combined with any other aspect, may include the following features. The method also includes adding a phase change material to the drilling fluid, the phase change material being specified to undergo a phase change near the bottom end of the drill string.

[0024] An aspect that can be combined with any other aspect may include the following features: The drill string includes an uphole portion and a downhole portion, wherein the uphole portion includes a first plurality of tubing segments and the downhole portion includes a second plurality of tubing segments. The tensile strength of a majority of the first plurality of tubing segments is at least 25% higher than the tensile strength of a majority of the second plurality of tubing segments. The majority of the second plurality of tubing segments is at least 35% lighter than the majority of the first plurality of tubing segments.

[0025] Certain aspects of the subject matter of this paper can be implemented as a method for forming a geothermal system in an underground region. The method includes drilling a first surface wellbore and a second surface wellbore. A transverse wellbore is drilled from the first surface wellbore to connect the first surface wellbore to the second surface wellbore in the underground region. Drilling the transverse wellbore includes positioning a drill string within the transverse wellbore. The drill string defines a conduit for allowing drilling fluid to flow toward a rock face at the bottom end of the transverse wellbore to displace fractured formation material from the rock face. The method also includes further drilling the transverse wellbore into the underground region using the drill string. The inherent temperature of the rock face adjacent to the bottom end of the transverse wellbore is at least 250 degrees Celsius. The drilling fluid flows in the transverse wellbore at the rock face at a temperature at least 100 degrees Celsius lower than the inherent temperature of the rock face adjacent to the rock face. The drill string is removed from the transverse wellbore, and the working fluid is circulated in a closed loop within the first surface wellbore, the second surface wellbore, and the transverse wellbore.

[0026] One aspect that can be combined with any other aspect may include the following feature: Extracting thermal energy from the working fluid.

[0027] Certain aspects of the subject matter of this paper can be implemented as a system for drilling wellbores in geothermal wells in subsurface areas. The inherent temperature of the rock face adjacent to the bottom end of the wellbore is at least 250 degrees Celsius. The system includes: a drill string having a drill bit to break the formation at the rock face; and drilling fluid that circulates at the rock face at a certain temperature such that the difference between the inherent temperature of the rock adjacent to the rock face and the temperature of the drilling fluid at the rock face is at least 100 degrees Celsius.

[0028] An aspect that can be combined with any other aspect may include the following characteristic: The difference between the inherent temperature of the rock adjacent to the rock face and the temperature of the drilling fluid at the rock face results in thermally induced stress in the rock at the rock face being greater than the tensile strength of the rock at the rock face.

[0029] An aspect that can be combined with any other aspect may include the following feature: The downhole end of the wellbore is located at a measurement depth of at least 4,000 meters.

[0030] An aspect that can be combined with any other aspect may include the following feature: The difference between the inherent temperature of the rock adjacent to the rock face and the temperature of the drilling fluid at the rock face is at least 175 degrees Celsius.

[0031] An aspect that can be combined with any other aspect may include the following characteristics: the inherent temperature of the rock adjacent to the rock face is at least 350 degrees Celsius, and the difference between the inherent temperature of the rock adjacent to the rock face and the temperature of the drilling fluid at the rock face is at least 200 degrees Celsius.

[0032] An aspect that can be combined with any other aspect may include the following characteristics: The wellbore is a transverse wellbore. Attached Figure Description

[0033] Figure 1A This is a schematic diagram of a closed-loop geothermal system conceived in this paper.

[0034] Figure 1B yes Figure 1A The diagram shows a plan view of a closed-loop geothermal system.

[0035] Figure 2 This is a schematic diagram of the drilling system conceived in this article.

[0036] Figure 3A This is a schematic diagram of a drill bit based on the concept conceived in this article.

[0037] Figure 3B This is a schematic diagram of the cross-section of a drill bit roller cone based on the concept described in this article.

[0038] Figure 4A It is a graphical representation of the temperature-pressure relationship for the brittle-to-semi-brittle transition in ductile or ductile rocks, based on the concept conceived in this paper.

[0039] Figure 4B It is a graphical representation of the brittle-to-semi-brittle transition in brittle igneous rocks as conceived in this paper.

[0040] Figure 5 This is a graphical representation of the effects of strain and stress on brittle and ductile rocks, based on the conception in this paper.

[0041] Figure 6A It is a graphical representation of the relationship between rock brittleness and drilling speed.

[0042] Figure 6B It is a view showing the relationship between rock damage caused by drilling operations and the temperature difference of cooling.

[0043] Figure 7 It is a graphical representation of the laboratory test results showing how drilling speed changes with the temperature difference between the drilling fluid and the rock being drilled.

[0044] Figure 8A This is a view of a coated section of a drilling string conceived in this paper.

[0045] Figure 8B This is a view of a coated section of a drilling string conceived in this paper.

[0046] Figures 9A to 9D This is a graph illustrating the relationship between vertical depth and the temperatures of the drill pipe, annulus, and rock in pipe sections with different coating configurations, based on the concept conceived in this paper.

[0047] Figure 10 This is a view of the relationship between the maximum drillable rock temperature and the thermal gradient for different pipe section coating configurations, as conceived in this paper.

[0048] Figure 11 This is a schematic diagram illustrating the heat transfer resistance through the annular section and the tubes with different configurations, based on the concept conceived in this paper.

[0049] Figure 12 This is a schematic diagram of a wellbore system with a second insulating annular section, based on the concept conceived in this paper.

[0050] Figures 13A to 13B yes Figure 12 A view of the thermal effect of the second insulating annular section.

[0051] Figure 14 This is a schematic diagram of a wellbore system for drilling conceived in this paper, wherein a second well serves as the inlet and / or outlet for drilling fluid. Detailed Implementation

[0052] Figure 1AA closed-loop geothermal system conceived herein is illustrated. A closed-loop geothermal wellbore system can be, for example, a system developed by Eavor Technologies, Inc., Calgary, Alberta, comprising a network of sealed horizontal wellbores that act as radiators or heat exchangers for the downhole formation. Descriptions of methods and apparatus used in certain situations with such a closed-loop geothermal system can be found, for example, in U.S. Patent Application Publications Nos. 20190154010A1, 20190346181A1, and 20200011151A1, the contents of which are incorporated herein by reference.

[0053] refer to Figure 1A The closed-loop geothermal system 100 includes an inlet surface wellbore 104 and an outlet surface wellbore 106, which are connected within a subsurface region 108 by a network of transverse wellbores 110. The subsurface region 108 is a geological stratum, a portion of a geological stratum, or multiple geological strata. In the illustrated example, surface wellbores 104 and 106 are substantially vertical; in other embodiments of this disclosure, one or both of the surface wellbores may not be substantially vertical. In the illustrated example, the transverse wellbores 110 connecting surface wellbores 104 and 106 are substantially horizontal; in some embodiments of this disclosure, some or all of the transverse wellbores may not be substantially horizontal and may be substantially straight or curved or have a helical or other configuration. The transverse wellbores 110 can be sealed, and working fluid can be added to the closed loop as a circulating fluid. A power plant 112 is arranged on the surface 114 between the inlet surface wellbore 104 and the outlet surface wellbore 106 to complete a closed-loop system. Heat from the underground region 108 is recovered from the working fluid circulating in the loop 116, and this heat is then used to generate electricity in conjunction with a generator (not shown) in the power plant 112. In some embodiments of this disclosure, the length of the transverse wellbore 110 may be 2,000 meters to 8,000 meters or more, and the depth from the surface 114 may be 1,000 meters to 20,000 meters.

[0054] Figure 1B It is formed Figure 1A A plan view of a horizontal wellbore 110, a part of a closed-loop geothermal system 100. (Reference) Figure 1B Horizontal wellbores 110 are arranged radially at intervals within the subsurface region 108. Each horizontal wellbore 110 is connected in a closed loop to an inlet wellbore 104 and an outlet wellbore 106. In some embodiments of this disclosure, some or all of the inlet wellbore 104 and the outlet wellbore 106 are casing-type. In some embodiments of this disclosure, the horizontal wellbores 110 are not casing-type, but are sealed without casing by forming a substantially impermeable fluid interface between the horizontal wellbore and the formation.

[0055] although Figure 1A and Figure 1B The inlet wellbore 104 and outlet wellbore 106 are shown to be far apart, but in other embodiments of this disclosure, wellbores 104 and 106 may be close together, and the network of transverse wellbores 110 may be stacked or staggered and intersect at their toes.

[0056] Such as Figure 1A and Figure 1B Drilling the geothermal system shown can involve drilling through very hard polycrystalline rocks, such as granite, at extremely high temperatures (above 250°C, and in some environments above 400°C or even 800°C). For example, such hard, high-temperature rocks may be encountered when drilling deep horizontal well sections. Figure 1A and Figure 1B As shown.

[0057] Figure 2 This is a schematic diagram of a wellbore drilling system 200 according to an example of this disclosure, which can be suitable for drilling. Figure 1A and Figure 1B The inlet surface wellbore 104, the outlet surface wellbore 106, and / or the transverse wellbore 110. (Reference) Figure 2 A wellbore 202 is formed in a subsurface region 204 by drilling through a drill string 206 positioned within the wellbore. The drill string 206 includes a bottom hole assembly (BHA) 210 at its downhole end. The BHA 210 includes a drill bit 208 and may also include drill rings, directional drilling instruments, and various electrical and electronic components for operating and / or controlling the drill bit 208. An internal conduit is defined within the drill string 206 for allowing drilling fluid 212 to flow to the downhole end of the wellbore to displace fragmented formation material from the rock face 214, which is then carried by the drilling fluid 212 into an annular portion 216 defined between the outer surface of the drill string 206 and the inner surface of the wellbore 202.

[0058] The drill string 206 includes multiple pipe segments 220 connected to each other at a connection joint 222. In some embodiments of this disclosure, the connection joint 222 includes a threaded box pin joint or another suitable connection.

[0059] Heat transfer (shown by arrow 224) can flow from the subsurface region 204 into the annular portion 216, and from the annular portion 216 into the interior of the drill string 206 and into the drilling fluid 212 flowing downwards along the drill string 206. Therefore, heat transfer from the subsurface region 108 to the annular portion 216 and from the annular portion 216 to the interior of the drill string 206 before the drilling fluid 212 is delivered to the drill bit 208 via a countercurrent exchange mechanism contributes to an increase in the temperature of the drilling fluid.

[0060] In some instances of this disclosure, drill bit 208 is a contact drill bit, such as a polycrystalline diamond composite (PDC) drill bit, a rotary drill bit, and / or other types of drill bits that rely on contact with rock to achieve drilling. Examples of suitable contact drill bits are... Figure 3A and Figure 3B The 300 tricone drill bit shown is an example. Figure 3A As shown, the tricone drill bit 300 includes three cones 302, each cone having multiple cutting elements 304. Figure 3B It shows along Figure 3A Details of the cross-section of lines 305A-305B are shown. In this example, each die 302 includes a plurality of spaced cutting elements 304 arranged in a specific interval array on the face of each die. To facilitate extended service life and long-term uninterrupted drilling, a series of additional cutting elements 306 can be provided. In this example, the additional cutting elements 306 are positioned below the cutting elements 304 such that the tip of the additional cutting elements 306 is adjacent to the contact point of the base of the overlying cutting elements 304. In this arrangement, the tip of the additional cutting elements 306 emerges as the elements 304 wear. This process can be further accelerated by incorporating materials of varying hardness into the gap space 310 between adjacent elements 304 and 306. With this arrangement, the cutting face of each die is self-renewing. Additional advantages of this feature include more uniform wear of the drill bit 300, reducing eccentric drilling progress, and decreasing the likelihood of getting stuck or trapped / unrecoverable within the forming hole.

[0061] In other examples of this disclosure, Figure 2 The drill bit 208 can be a non-contact drill bit, configured to break formation material at a rock face 214 located at the bottom end of the wellbore 202 in the subsurface region 204 without requiring contact between the drill bit 208 and the rock face 214, and in some instances of this disclosure, may include an electric fracturing drill bit for electric pulse drilling. Examples of non-contact drilling systems include plasma drilling (such as plasma drilling systems developed by GA Drilling, AS), laser drilling (such as laser drilling systems developed by Foro Energy), microwave drilling (such as microwave drilling systems developed by Quaise), thermal stripping techniques (such as supercritical water jetting or flame jetting), and electric pulse drilling (such as electric pulse drilling systems developed by Tetra Corporation). (It is understood that during the drilling process, portions of the non-contact drill bit may periodically collide with, rub against, or otherwise contact the formation.)

[0062] In systems such as the electric pulse drilling system developed by Tetra, a multi-electrode breaker bit generates high-energy sparks to break up formation material, allowing it to be cleared from the path of the drilling assembly. Using a specific excitation current profile, the bit can generate multiple sparks per second, creating an electric arc through the most conductive portion of the rock face at the bottom end of the wellbore. The arc causes the portion of the rock face penetrated by the arc to disintegrate or fragment and be washed away by the drilling fluid flow. High-resistivity drilling fluids are used for this type of electric pulse drilling. Descriptions of some electrical pulse drill bits, drilling fluids, and related systems and methods can be found, for example, in U.S. Patent Nos. 4,741,405, 9,027,669, 9,279,322, 10,060,195, U.S. Patent Publication No. 20200299562A1, and PCT patent applications WO2008 / 003092, WO 2010 / 027866, WO 2014 / 008483, WO 2018 / 136033, and WO 2020 / 236189, the contents of which are incorporated herein by reference. Because electrical pulse drilling and other forms of non-contact drilling cause rock to fail under tension (rather than compression or shear), further synergistic effects can occur with the cooling effects discussed in more detail below.

[0063] When the rock is under very high confining pressure and / or due to the high temperatures that may be encountered in drilling deep geothermal environments (such as when drilling), for example... Figure 1A and Figure 1B When the lateral borehole 110 of the closed-loop system shown has ductile / plastic properties, the drilling rate (ROP) may decrease. This high temperature may also interfere with the function of downhole electronic equipment and / or sensors. Furthermore, drilling multiple lateral boreholes (such as...) Figure 1B As shown, directional drilling technology may be widely used. Magnetometers and other downhole equipment used in this type of drilling can be adversely affected by high downhole temperatures. Some downhole components of a directional drilling system have temperature limits of 150 to 250°C. Other downhole components may have different (higher or lower) temperature limits or ranges.

[0064] In some examples of this disclosure described below, coating combinations, wellbore geometries, downhole equipment, and / or additives are used to provide a drilling fluid flow at the downhole end of the wellbore at a temperature suitable for drilling, such that the inherent temperature of the rock adjacent to the rock face (i.e., the temperature of the rock to be internally drilled through ahead of the drill bit, if not for the cooling effect of the drilling fluid) differs from the temperature of the drilling fluid at the rock face by at least 100°C. The temperature of the fluid at the rock face is, for example, the temperature of a large volume of fluid due to convective cooling of the rock face occurring within approximately 1 cm of the drilled rock face. In some examples of this disclosure, this temperature difference can occur in geothermal environments, where, at a measurement depth of 4000 meters or greater, the inherent temperature of the rock adjacent to the rock face is at least 250°C; i.e., the measurement depth across surface wellbores and transverse wellbores. (As used herein, the measurement depth is the length along the wellbore path and (except for true vertical wells) differs from the vertical depth of the well). In some examples of this disclosure, the temperature difference can be greater. For example, in the embodiments of this disclosure, the inherent temperature of the rock adjacent to the rock face is at least about 500°C, and the difference between the inherent temperature of the rock adjacent to the rock face and the temperature of the drilling fluid at the rock face can be at least about 350°C. In other embodiments of this disclosure, the temperature difference can be larger or smaller. Such a large temperature difference can increase the ROP (Recovery Point Pressure) because the shock cooling effect causes thermal contraction of the rock face. This puts the rock under tensile stress and reduces the effective confining pressure at the rock face. The temperature difference can also generate tensile microcracks in the rock matrix.

[0065] For example, Figure 4A This is a graphical representation of the temperature-pressure relationship used for the brittle-to-semi-brittle transition in ductile or ductile rocks. As temperature or pressure decreases, ductile rocks transition to a more brittle state. When hot-brittle rocks are subjected to rapid thermal cooling, the internal temperature of the rock decreases, and the rock transitions to a more brittle state relative to untreated rock. Figure 4B This result is shown in general. Thus, through temperature manipulation, this regional transformation from ductility, semi-brittleness, and any combination thereof within the region makes the treated rock more brittle relative to its initial untreated state.

[0066] The strength of rock (the stress required to induce irreversible deformation) does not necessarily change with increasing brittleness, such as... Figure 5 As shown. However, the deformation mode of brittle rocks is sudden failure and fracture, while for more ductile rocks, the failure mode is to undergo more plastic deformation before failure.

[0067] like Figure 6A As shown, regardless of the drilling method used, the drilling speed generally increases with the brittleness of the rock. In particular, pulsed electric drilling systems or other non-contact drilling systems can be especially suitable for brittle rocks.

[0068] Figure 6B The relationship between internal rock damage and cooling temperature (e.g., during drilling operations) is illustrated. Note that internal damage is a separate and additional effect, in addition to the embrittlement mechanisms discussed earlier. A higher cooling temperature difference is required to induce irreversible damage within the rock compared to simple embrittlement. Irreversible damage manifests as microcracks, fissures, and displacement between grains due to differential thermal contraction. Under sufficient thermal cooling, both embrittlement and subsequent irreversible damage can be induced in the drilled rock.

[0069] Figure 7 This is a graphical representation of laboratory test results showing the variation of drilling speed with the temperature difference between the drilling fluid and the rock being drilled. The laboratory tests were performed on 10-inch diameter granite blocks heated to a target temperature in an oven. These blocks were then placed in a pressurized chamber, pressurized relative to the confining pressure (which is applied to a sleeve around the rock sample) and relative to the hydrostatic pressure of the drilling fluid, to simulate a depth of approximately 1000 m. The rock samples were then drilled using drilling fluid at ambient temperature at a consistent bit weight, rotational speed per minute, and flow rate. (From...) Figure 7 It is evident that when the temperature difference between the rock being drilled and the drilling fluid exceeds approximately 175 degrees Celsius, the rate of drilling (ROP) increases significantly. At such a temperature difference, the thermally induced stress in the rock at the rock face can exceed the tensile strength of the rock at the rock face, which can weaken the rock and lead to cracks, thus increasing the drilling rate. Further increases in the temperature difference have an even greater effect on improving ROP.

[0070] Furthermore, shock cooling can reduce the effective static rock pressure at the rock surface through thermal contraction. In benchmark tests without shock cooling, the ROP (Recovery Point Pressure) of drilling typically decreases with increasing confining pressure. Therefore, the shock cooling effect itself can improve the performance of deep rocks under high confining pressure.

[0071] In some instances of this disclosure, the temperature difference between the inherent temperature of the rock adjacent to the rock face and the temperature of the drilling fluid at the rock face is sufficient to induce formation embrittlement at the rock face. When the embrittled rock fails, it can fracture abruptly without plastic deformation of the material.

[0072] In some instances of this disclosure, the temperature difference between the inherent temperature of the rock adjacent to the rock face and the temperature of the drilling fluid at the rock face is sufficient to reduce the tensile strength of the rock and / or damage its microstructure (which can reduce rock strength due to microcracks and weak points within the rock matrix) and / or induce spalling at the rock face due to thermal contraction. In some instances of this disclosure, the temperature difference is sufficient to reduce the confining pressure at the rock face (by causing the rock to thermally contract and inducing cracks). If thermal contraction occurs to the extent that cracks are generated in the rock face, it will lose confining pressure and become more prone to fracture.

[0073] In some instances of this disclosure, the temperature difference between the inherent temperature of the rock adjacent to the face and the temperature of the drilling fluid at the face is sufficient to keep the bottom hole assembly (BHA) cooled and at a relatively constant temperature, even when drilling into rock at temperatures of 250°C to 500°C or higher and at depths of 2 to 14 km or more. This cooling can be particularly advantageous in the case of electrical pulse drilling, as this technology itself requires the generation and transmission of electricity within the BHA, and resistance increases with temperature. Regardless of the rock-breaking method, some downhole electronics, circuit boards, batteries, and other components may have temperature limits of 150 to 200°C. (Some downhole components may have different (higher or lower) temperature limits). By using the cooling system of this disclosure, these components are kept below their temperature limits even when drilling into very hot rock.

[0074] Similarly, by cooling the magnetometer and other downhole components of the directional drilling system, some of the examples described in this disclosure enable directional drilling to be used in rock environments with higher temperatures than previously possible.

[0075] Therefore, by providing a large temperature difference between the rock adjacent to the rock face and the drilling fluid at the rock face, the enhanced cooling system and method disclosed herein can be used with drilling systems (such as electric pulse drilling) and directional drilling components in high formation temperature environments (such as... Figure 1B In the environment shown, multiple horizontal wells of a closed-loop geothermal system were drilled, and the downhole electronic equipment performance and ROP were improved.

[0076] In some instances of this disclosure, enhanced cooling can be used in drilling. Figure 1A and Figure 1B All wellbores of the system shown. Because the hottest rocks may be encountered in the formation traversed by drilling the transverse wellbore 110, conventional drilling methods without advanced cooling are used in some instances of this disclosure. Figure 1A and Figure 1BVertical well components, and use enhanced cooling to drill some or all of the transverse wellbores 110. When the rock is very hot (e.g., above 250 degrees Celsius), shock cooling has a greater impact on ROP; therefore, enhanced cooling can be particularly suitable for wells where most of the drilling is carried out within very hot rock. In a single vertical or deviated well, the advantages of ROP may be reduced; however, if drilling at depths within hot rock, forming a network of wellbores, such as... Figure 1A and Figure 1B In the example shown, the advantages can be quite obvious.

[0077] Figure 8A Examples of applications according to this disclosure are shown. Figure 2 A cooling coating is applied to the pipe segment 220 of the drill string 206. The pipe segments 220 are connected to each other at a connection joint 222 and include a body 802. In some embodiments of this disclosure, the body 802 comprises a carbon steel body. In other embodiments of this disclosure, the body 802 may comprise an aluminum alloy, a titanium alloy, and / or a fiber composite material (e.g., a composite material of a polymer adhesive and carbon fiber, aramid fiber, glass fiber, electronic glass, and / or other structural fibers), as described in more detail below. An internal coating 804 at least partially covers the inner circumferential surface of the pipe segment 220. In the illustrated embodiment, the internal coating covers the entire length of the pipe segment 220 and also covers the inner surface of the connection joint 222. In some embodiments of this disclosure, the connection joint 222 may be a significant heat transfer area. By covering the inner surface of the connection joint 222 with the internal coating 804, heat transfer at the connection joint 222 is reduced.

[0078] The outer coating 806 at least partially covers the outer peripheral surface of the pipe section 220. In the illustrated example, the diameter of the connector 222 is larger than the diameter of the main portion of the body 802, and therefore receives more contact, resulting in greater friction against the wellbore wall or other components of the wellbore system. In the illustrated example, the outer coating 806 covers the portion of the pipe section 220 between the connectors 222, but does not cover the larger diameter area around the connectors 222. In this way, the outer coating 806 is less affected by the friction occurring at the connectors 222.

[0079] In some examples of this disclosure, the internal coating 804 comprises one or more of epoxy phenolic resins (TK340XT and CP-2060) and epoxy phenolic resins (TK34XT and CP-2050). TK products are available from NOV, while CP products are available from Aremco Products. The thickness of the internal coating 804 comprising epoxy phenolic resin can range from 150 to 250 μm, while the thickness of the internal coating 804 comprising epoxy phenolic resin can range from 400 to 1270 μm. The average thermal conductivity of the epoxy phenolic resin can be ~0.8 K / Wm, while the average thermal conductivity of the epoxy phenolic resin can be ~0.4 K / Wm. Insulating particles can be added to these resins or other resins to further reduce thermal conductivity.

[0080] In some examples of this disclosure, the outer coating 806 comprises a fiber composite cladding (such as carbon fiber, electronic glass composite, and / or another fiber composite) with a thickness of about 2540 μm. These coatings are available from ACPT and / or Seal for Life Industries. The thermal conductivity of electronic glass can be about 0.288 W / mK, while the thermal conductivity of carbon fiber can be about 0.8 W / km.

[0081] In some embodiments of this disclosure, the normalized thermal resistance of the tube wall is at least about 0.002 mKelvin per watt. In some embodiments of this disclosure, the normalized thermal resistance of the tube wall is at least about 0.01 mKelvin per watt. Reference Figure 8A The wall thickness 810 is defined by the inner surface of the inner coating 804 and the outer surface of the outer coating 806. For the purposes of this disclosure, "length-normalized thermal resistance" is the effective conductive thermal resistance of a column for radial heat transfer, taking into account the different materials along the length of the column, and is the temperature difference required to transfer 1 watt of energy over a 1-meter axial length of material.

[0082] The following are the normalized thermal resistances of the tube wall length for some examples of tubes having a steel inner body 802 and an inner coating 804 (the material and thickness of which are shown below) (but no outer coating 806):

[0083]

[0084] The following are the normalized thermal resistances of the tube wall length for a tube having a steel inner body 802 and an inner coating 804 (the material and thickness of which are shown below) plus an outer coating 806 (“sheath”) made of electronic glass with the thickness shown below in some examples of this disclosure:

[0085]

[0086] In the examples disclosed herein, Figure 2 The drill string 206 includes, for example, Figure 8A The pipe segment 220 shown includes an internal coating 804 of epoxy phenolic resin TK340XT with a thickness of approximately 400 micrometers and an external coating 806 of electronic glass with a thickness of approximately 5 millimeters. In such an example, it is assumed that the thermal gradient of the subsurface area is approximately 60°C / km, the drill string length is approximately 8000 meters, and the circulation velocity of the water-based drilling fluid is approximately 3 meters per second. 3 If the temperature at the rock surface is approximately 490°C, then the drill string 206 composed of this section 220 can result in a temperature difference of approximately 346°C between the rock adjacent to the rock surface and the drilling fluid at the rock surface.

[0087] In another example of this disclosure, Figure 2 The drill string 206 includes, for example, Figure 8A The pipe segment 220 shown includes an internal coating 804 of epoxy phenolic resin TK34XT with a thickness of approximately 250 micrometers and an external coating 806 of electronic glass with a thickness of approximately 2.5 millimeters. In such an example, it is assumed that the thermal gradient of the underground region is 40°C / km, the pipe string length is approximately 9000 meters, and the circulation flow rate of the water-based drilling fluid is approximately 3.5 m³ / km. 3 If the drilling fluid is at a temperature of approximately 370°C per minute, and the temperature at the rock surface is approximately 370°C, then the drill string 206 composed of this section 220 can result in a temperature difference of approximately 196°C between the rock adjacent to the rock surface and the drilling fluid at the rock surface.

[0088] In other embodiments of this disclosure, the inner coating 804 and / or the outer coating 806 may have a greater or lesser thickness and / or may include other types of coatings, such as ceramic inorganic coatings (e.g., silicate bonded ceramics).

[0089] Figure 8B Another example of application according to this disclosure is shown. Figure 2 The cooling coating on the drill string 206 and the pipe section 220. Figure 8B In the example shown, pipe segment 220 is a composite drill pipe segment that includes a composite body 850 (which may be made of steel, titanium, aluminum, fiber composite or another suitable material) connected at a connecting joint 222, which may also include steel, titanium, aluminum, fiber composite or another suitable material.

[0090] refer to Figure 8BThe internal coating 854 at least partially covers the inner circumferential surface of the pipe segment 220. In the illustrated example, the internal coating 854 covers only the inner circumferential surface of the pipe segment 220 at and near the connector 222. By covering the area of ​​the inner circumferential surface of the pipe segment 220 at and near the connector 222 with the internal coating 854, heat transfer at the connector 222 is reduced. In other embodiments of this disclosure, the internal coating 854 covers the entire inner circumferential surface of the pipe segment 220.

[0091] In some examples disclosed herein, Figure 8B The internal coating 854 may include reference Figure 8A The internal coating 804 is of the same material and thickness as described. In some embodiments of this disclosure, the internal coating 854 may include other suitable materials or thicknesses. In some embodiments of this disclosure, the pipe segment 220 may include a vacuum insulated pipe (VIT), wherein, instead of or in addition to the internal coating 804 (or 854) and the external coating 806, insulation is provided by a vacuum layer within the pipe segment 220.

[0092] In some embodiments of this disclosure, body 802 and / or body 850 may comprise steel drill pipe with a high strength-to-weight ratio, such as UD165 steel drill pipe available from NOV Corporation. In some embodiments of this disclosure, such steel drill pipe may be UD-165 steel drill pipe, which may have a yield strength of approximately 165,000 psi (1,138 MPa), a pipe tensile strength of approximately 1,000,000 lbf (4.45 MN), a length-normalized joint air weight of 24.76 lbf / ft (361.3 N / m), and a joint strength-to-weight ratio of approximately 900 lbf / lbf (900 N / N).

[0093] In some embodiments of this disclosure, body 802 and / or body 850 may comprise drill pipe made of titanium alloy. In some embodiments of this disclosure, such titanium alloy drill pipe may comprise Ti-6Al-4V titanium alloy and may have a yield strength of approximately 120,000 psi (827 MPa), a pipe tensile strength of approximately 750,000 lbf (3.34 MN), a length-normalized joint air weight of 16 lbf / ft (233.8 N / m), and a joint strength to weight ratio of approximately 1,000 lbf / lbf (1000 N / N).

[0094] In some embodiments of this disclosure, body 802 and / or body 850 may comprise drill pipe made of aluminum alloy. In some embodiments of this disclosure, such aluminum alloy drill pipe may comprise an 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 length-normalized 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 some embodiments, such aluminum alloy rod may comprise FarReach, available from Alcoa Energy Systems. TM Drill pipe. In some examples of this disclosure, such aluminum alloy drill pipe may include aluminum alloy drill pipes available from Aluminum Drill Pipe.

[0095] In some embodiments of this disclosure, body 802 and / or body 850 may include carbon fiber composite drill pipe. In some embodiments of this disclosure, such carbon fiber composite drill pipe may include Advanced Composite Drill Pipe, available from Advance Composite Products & Technology.

[0096] In some examples disclosed herein, Figure 2The drill string 206 may include segments 220, each segment comprising a body 802 and / or 250 of steel, titanium, aluminum, and / or fiber composite materials as described above. For example, in some embodiments of this disclosure, each segment of the drill string 206 comprises a body 802 and / or 250 made of a single material (such as an aluminum alloy). In other embodiments of this disclosure, the drill string 206 may include different sections, each section comprising multiple segments 220 composed of different materials. For example, in some embodiments of this disclosure, some segments 220 of the drill string 206 may comprise one body material (such as an aluminum alloy), while the remaining segments 220 of the drill string 206 may comprise another body material (such as steel). In some embodiments of this disclosure, the drill string 206 may include two, three, or more sections, each of which comprises multiple segments 220, the body of which is composed of a material different from that of the other sections. In another example, based on length-normalized air weight, the material of the bulk body of most of the section 220 near the drill bit 208 is lighter than that of the section closer to the wellbore. For the example above, titanium drill pipe is about 35% lighter than steel drill pipe, while aluminum drill pipe is about 37% lighter than steel drill pipe. Those sections 220 closer to the wellbore from the drill bit 208 can include a bulk body made of a higher-strength material. For the example above, the tensile strength of UD-165 drill pipe is about 67% higher than that of aluminum drill pipe, while the tensile strength of titanium drill pipe is about 25% higher than that of aluminum drill pipe. Differences in tensile strength and length-normalized weight can also be achieved with a single material, but the thickness / diameter of the drill pipe in the uphole section varies in a scaling manner compared to the downhole section. In one example of this disclosure, most of the section 220 near the drill bit is approximately 35% lighter than most of the section 220 in the surface portion, and the tensile strength of most of the section 220 in the surface portion is approximately 25% higher than that of most of the section 220 near the drill bit. The use of these different drill string materials enables drilling into rocks with much higher temperatures at greater depths (and therefore requires thermally insulated drill strings with sufficient tensile strength to extend to such depths). When properly combined, the aforementioned materials can be used to drill to depths exceeding 9 km (including up to 14 km or more). The Earth's geothermal gradient results in higher temperatures in rocks at greater depths. The impact cooling technology of this invention provides a method to improve drilling speed and performance in high-temperature rocks. Therefore, a synergistic effect is achieved by combining drill string sections with different weights / strengths to enable deeper drilling with the cooling technology described herein. Closed-loop multi-sided wells can be drilled at sufficient depths (and therefore sufficient rock temperatures) to achieve shock cooling, thus greatly reducing the time and cost of drilling multi-sided wells.

[0097] Figure 9AThe results of a thermodynamic simulation of heat transfer in a fluid flowing within a downhole tubular drill string, comprising a standard carbon steel drill pipe within a casing wellbore in an underground region, are presented. The simulation assumes that water drilling fluid is pumped down the string at a flow rate of 3.5 cubic meters per minute, with a temperature gradient of 50°C / km from the surface (i.e., from the surface position at the top of the wellbore) to the rock face (at the bottom of the wellbore). Reference Figure 9A The curve labeled "Drill Pipe" represents the temperature of the fluid flowing within the tubular drill string at a given depth; the curve labeled "Annulus" represents the temperature of the fluid flowing within the annulus between the casing and the tubing at a given depth; and the curve labeled "Rock" represents the inherent temperature of the rock at a given depth. Figure 9A As shown, some insulation is provided for heat transfer, resulting in a fluid temperature of approximately 206°C at the rock face and a rock temperature of 260°C at the bottom of the well, representing a temperature difference of approximately 54°C. However, such a temperature difference may not be sufficient to provide a sufficiently cold drilling fluid flow to cool downhole electronic equipment or directional drilling equipment, or to provide a shock cooling effect at the rock face, or other advantages of cold drilling fluid flowing at the bottom end of the wellbore as described above. Figure 9A In this case, the temperature of the fluid at the rock surface is equal to the temperature of the annulus at the bottom of the well after the fluid has left the drill bit.

[0098] refer to Figure 8A and Figure 8B The described coating and coating geometry can reduce heat exchange between the colder fluid descending in the tubing string and the hotter fluid returning in the annulus during drilling, and can result in a difference of at least 100°C between the inherent temperature of the rock adjacent to the rock face and the temperature of the drilling fluid at the rock face, even in geothermal environments where the inherent temperature of the rock adjacent to the rock face is at least 250°C. For example, in various examples of this disclosure described below, Figures 9B to 9D This illustrates the use of downhole tubing (assuming, for example) Figure 8A The results of a thermodynamic simulation of heat transfer in the pipe segment shown. Figures 9B to 9D In the simulation shown, the internal coating 804 covers the entire length of the pipe section, including the inner surface of the connector. Figures 9B to 9D In the diagram, the curve labeled "Tube" represents the temperature of the fluid flowing within the tubular drill string at a given depth; the curve labeled "Casing" represents the temperature of the fluid flowing within the annulus between the drill pipe and casing at a given depth; and the curve labeled "Rock" represents the inherent rock temperature at a given depth. The drilling fluid flows into the tube at the surface, through the BHA (Boiler Attachment), through the drill bit, across the rock face, and into the annulus. The temperature of the drilling fluid at the rock face is approximately equal to the temperature of the fluid within the annulus at the bottom of the well.

[0099] Figure 9BA thermodynamic heat transfer simulation is shown for an example including a standard carbon steel rod, where the inner coating 804 comprises a 400 μm thick epoxy phenolic resin TK340XT (and there is no outer coating 806). The simulation assumes that the water drilling fluid is pumped at a flow rate of approximately 3.5 cubic meters per minute, and the temperature gradient from the Earth's surface to the rock face is approximately 50 °C / km. Figure 9B As shown, with Figure 7 In comparison, this example provides an increased temperature difference; that is, approximately 91°C at 5000 meters.

[0100] Figure 9C A thermodynamic heat transfer simulation is shown for an example including a standard carbon steel pipe, where the inner coating 804 comprises a 400 μm thick epoxy phenolic resin TK340XT, and the outer coating 806 comprises a 5 mm thick electro-optical glass sheath. The simulation assumes that the water drilling fluid is pumped at a flow rate of approximately 3 cubic meters per minute, and the temperature gradient from the surface to the rock face is approximately 60 °C / km. Figure 9C As shown, this example provides a temperature difference of approximately 346°C at a distance of 8000 meters.

[0101] Figure 9D A thermodynamic heat transfer simulation is shown for an example including a standard carbon steel rod, where the inner coating 804 comprises a 250 μm thick epoxy phenolic TK34, and the outer coating 806 comprises a 2.5 mm thick electro-optical glass sheath. The simulation assumes that the water drilling fluid is pumped at a flow rate of approximately 3.5 cubic meters per minute, and the temperature gradient from the surface to the rock face is approximately 40 °C / km. Figure 9D As shown, this example provides a temperature difference of approximately 196°C at a distance of 9000 meters.

[0102] Figure 10 This shows what can be used for reference. Figure 9C and Figure 9D The description of the example drilled well illustrates the variation of the maximum rock temperature with the thermal gradient from the Earth's surface to the rock face (at the bottom end of the wellbore), and assumes that the temperature of the drilling fluid leaving the drill bit at the rock face should not exceed approximately 150°C. Upper curve 1002 corresponds to the reference... Figure 9C Examples described. For instance, using the example described by reference 9C, at point 1004, the temperature gradient is approximately 60°C / km, and the maximum drillable rock temperature is approximately 483°C. The lower curve 1006 corresponds to the reference... Figure 9D Examples described. For example, using the example described in Reference 9D, at point 1008, the temperature gradient is approximately 40°C / km, and the maximum drillable rock temperature is approximately 335°C.

[0103] In some instances of this disclosure, instead of or in addition to coatings 804 and 806 on pipe section 220, drilling fluid (e.g., ...) can be applied to the drilling system. Figure 2A phase change material, such as ice or dry ice, is added to the drilling fluid 212. The phase change material can absorb heat energy when it undergoes a phase change (e.g., melting). In some embodiments of this disclosure, the drilling fluid can be pumped at a sufficient flow rate so that the phase change material undergoes a phase change near the drill bit.

[0104] In some examples of this disclosure, one can... Figure 2 The system incorporates a heat exchanger to cool the drilling fluid 212 as it returns from the wellbore 202 and is recirculated downhole. In some embodiments of this disclosure, such a heat exchanger may be located at a surface location.

[0105] Not all drilling fluid necessarily needs to flow through the drill bit to achieve the results described herein. A portion of the drilling fluid may also enter the annulus from the tubing through ports or other devices located near the drill bit or BHA. Such a configuration can allow for higher flow rates if components within the bottom hole assembly have flow restrictions.

[0106] Figure 11 The resistance to heat transfer through the annulus and four differently constructed tubes is shown, i.e., thermal resistance. As cold drilling fluid circulates downhole through the tubes and rises through the annulus, the drilling fluid in the annulus is heated to T by the surrounding rock in the subsurface region. 环状部 The drilling fluid in the annular section then heats the drilling fluid inside the pipe to T. 管 In each instance, the primary heat transfer mechanism through the annulus filled with drilling fluid is convection. The flowing drilling fluid (an imperfect convective medium) exhibits a thermal resistance R. 对流,环状部 In the case of an uninsulated carbon steel pipe (carbon steel), steel is an imperfect conductor of heat and exhibits an additional (series) thermal resistance R. 传导,钢 Finally, the primary heat transfer mechanism of the drilling fluid itself, which is heated within the tubing filled with drilling fluid, is convection. The drilling fluid exhibits an additional (series) thermal resistance R. 对流,管 When the pipe is completely covered by an insulating coating (coated carbon steel), the coating exhibits an additional (series) thermal resistance R. 传导,涂层 When using composite pipes with steel clamps (joints) (composite material and composite material + coated clamps), the composite pipe and carbon steel exhibit parallel thermal resistances (Ri and Rii, respectively). 传导,复合材料 and R 传导,钢箍 In other words, materials with lower thermal resistance (i.e., materials with poorer insulation) have a greater impact on the total thermal resistance of a pipe section. Since the thermal resistance of composite materials is generally higher than that of steel, simply applying steel clamps can significantly increase the total thermal resistance of a pipe section.

[0107] Figure 12 The formation of a second insulating annular portion according to an embodiment of this disclosure is shown. (Reference) Figure 12 The examples described in this disclosure will be referenced. Figure 2 The drilling system 200 is described using its components. (See reference...) Figure 12 At the downhole end of drill string 206, drill bit 208 is being used to drill wellbore 202. Drilling fluid 212 flows down drill string 206 and out of drill bit 208. An annular portion 216 is defined in the lower portion of wellbore 202, located between the outside of drill string 206 and wellbore 202. Intermediate tubing 1202 is positioned within the wellbore such that drill string 206 is positioned within intermediate tubing 1202, thereby forming an inner annular portion 1204 between the outside of drill string 206 and the inside of intermediate tubing 1202, and an outer annular portion 1206 between the outside of intermediate tubing 1202 and wellbore 202, each of the inner annular portion 1204 and the outer annular portion 1206 extending at least partially downhole along the length of drill string 206. In some embodiments of this disclosure, the inner annular portion 1204 may be filled with insulating material. In some embodiments of this disclosure, the insulating material is a gas, thus forming a "gas blanket". In other embodiments of this disclosure, instead of or in addition to gas, the inner annular portion 1204 may be filled with foam or insulating oil or any fluid or material with low thermal conductivity.

[0108] The inner annular portion 1204 separates the downward-flowing drilling fluid 212 from the heated, upward-flowing fluid in the outer annular portion 1206. Figure 13A and Figure 13B It is a comparison of the wellbore fluid temperature in the well system. Figure 13A The diagram shows the predicted drilling fluid temperature as a function of depth in a drilling system without an insulated intermediate tubing string. Figure 13B This illustrates the drilling fluid temperature as a function of depth in a drilling system with an insulated intermediate tubing string that provides an internal annular section filled with insulating gas, as shown in the reference. Figure 12 As described. Although the bottom portion of the well continues to heat without an insulating layer beneath the gas caprock, the temperature at the rock face is still drastically cooled. In this example, the inner annulus 1204 extends only to the bottom of the final casing string; however, significant cooling is still achieved at the rock face (of the main borehole and / or the lateral boreholes drilled from the main borehole). Due to its much lower density, the insulating fluid caprock remains in place, and thus essentially floats on top of the drilling fluid.

[0109] Because the "overburden fluid" has a low density, it is pressurized at the wellhead (not shown) on the surface. Managed Pressure Drilling (MPD) is a system that maintains pressure in an annulus surrounding the rotating drill pipe. A key challenge is sealing the fluid to prevent leakage through the rotating drill pipe. Recently, MPD systems have been sufficiently improved to hold the pressurized fluid overburden in place. Therefore, modern MPD systems are preferably used if the fluid overburden fills the inner annulus concentric with the rotating drill pipe.

[0110] A variation of this approach involves installing an additional casing string to create two inner annexes (not shown). One inner annulus is positioned concentrically and adjacent to the rotating drill pipe, a second inner annulus that can be filled with overburden fluid, and an outer annulus through which heated drilling fluid returns. This setup requires the cost and complexity of a larger wellbore to make room for the additional annulus; however, it avoids the use of a high-pressure MPD system because the inner annulus can be filled with drilling fluid.

[0111] According to an alternative example of this disclosure, in order to reduce backflow heat transfer from the annulus to the tube, a second well is used, which serves as an inlet and / or outlet for the drilling fluid. Figure 14 A schematic diagram of this "slipstream well" is shown.

[0112] refer to Figure 14 For reference as well Figure 2 As described, at the bottom end of drill string 206, wellbore 202 is being drilled using drill bit 208. Drilling fluid 212 flows along drill string 206 toward drill bit 208. An annular portion 216 is defined between the outside of the tubing string and the wellbore 202. Wellbore 202 may include a main wellbore and / or a transverse wellbore.

[0113] exist Figure 14 In the example shown, wellbore 202 is the first wellbore, and a second wellbore 1402 is drilled to intersect with the first wellbore 202. A second drilling fluid flow 1404 flows down along the second wellbore 1402. The second drilling fluid flow 1404 provides at least a portion of the drilling fluid flowing at the downhole end of wellbore 202 (i.e., near the rock face of drill bit 208). The second wellbore 1402 is sufficiently far from the first wellbore 202 to reduce or eliminate heat transfer, such that the second drilling fluid flow 1404 provides additional cooling at the downhole end of wellbore 202.

[0114] In some embodiments of this disclosure, drilling fluid and cuttings can be directed upwards back to the surface along the second wellbore 1402. In this variation, there is no upward flow of heated fluid into the annulus 216, and thus countercurrent heat exchange is eliminated above the intersection point 1406. This directional flow is indicated by the numeral 1408 in dashed lines.

[0115] It is understood that the second wellbore 1402 can be drilled and used to cool any number of additional wellbores / pipes from surface locations. For example, a closed-loop geothermal well system can be constructed by drilling four corner wells. After drilling is completed in one of the four corner wells, the "slipstream" intersection section is plugged and abandoned, and another intersection section is drilled to intersect with the other corner well in the four corner wells. In this way, a single well can be used multiple times to cool other wells, and only the intersection section needs to be drilled each time.

[0116] Impact cooling of hot rock using the techniques described herein can present several challenges behind the drill bit during drilling. Cooling increases the compressive strength of the wellbore but reduces its tensile strength. The significant temperature difference between the circulating drilling fluid and the wellbore wall can lead to cooling-induced tensile fractures radially away from the wellbore. These tensile fractures may need to be sealed or controlled with wellbore reinforcing materials such as graphite or calcium carbonate, or other loss-generating circulating materials. Furthermore, the fractures may need to be sealed with chemical sealants such as sodium silicate or potassium silicate. Underbalanced operation during drilling is another approach, which can be used alone or in conjunction with other disclosed techniques, to mitigate the effects of tensile fractures behind the drill bit. A system design particularly suitable for electric pulse drilling would utilize a managed pressure drilling system and an oil-based drilling fluid with high resistivity and an equivalent circulating density below hydrostatic pressure. This would allow for flexibility in controlling downhole pressure while still supplying a suitable drilling fluid for electro-break drilling.

[0117] Another challenge associated with shock cooling is that the induced tensile fractures can propagate into shear fractures or introduce further complications, resulting in a large amount of cuttings or rock fragments of varying sizes breaking off from the wellbore wall behind the drill bit. Other methods, such as those using viscous drilling fluids and high flow rates (>2.5 m), also present challenges. 3 The combination of blows (per minute) can remove additional debris generated by the impact cooling process. In some instances of this disclosure, the drilling fluid can have a Marsh funnel viscosity of at least 80 to 100 seconds. Various impacts or flushes through the high-viscosity fluid volume of the system will also help remove additional debris. Successful circulation of larger debris to the surface is the result of two main parameters: annular fluid velocity (driven by flow rate and annular volume) and fluid rheology (plastic viscosity / yield point (PV / YP) to increase carrying capacity / reduce slip velocity, and gel strength to suspend while bonding). Circulation of large debris by periodic low-volume / high-viscosity flushes can transport and suspend large debris to the surface. In some instances of this disclosure, these debris can be captured (i.e., filtered and removed) at the surface to prevent or reduce contamination of the base drilling fluid.

[0118] By reducing the heat exchange between the colder fluid descending along the tubing during drilling and the warmer fluid returning in the annulus, reference Figure 8A and Figure 8B The coating and coating geometry described, and references Figure 12 and Figure 14 The described methods and systems can also reduce the impact of higher formation temperatures on sections of the tubing (such as...). Figure 2 The negative impact on the tensile strength and other properties of the drill string 206 (pipe section 220).

[0119] The methods, systems, and equipment described above for enhancing the cooling of drilling fluids can be used individually or in combination with each other.

[0120] In this disclosure, unless the context clearly specifies otherwise, the terms “a,” “an,” or “the” are used to include one or more. Unless otherwise stated, the term “or” is used to refer to a non-exclusive “or.” The expression “at least one of A and B” has the same meaning as “A, B, or A and B.” Furthermore, it should be understood that unless otherwise defined, phrases or terms used in this disclosure are for descriptive purposes only and not for limitation. The use of any section headings is intended to aid in reading this document and should not be construed as limiting; information relating to a section heading may appear within or outside that particular section.

[0121] While this disclosure contains numerous specific implementation details, these should not be construed as limiting the subject matter or what may be claimed, but rather as descriptions of features that may be specific to a particular implementation. Certain features described in the context of individual implementations may also be implemented in combination or in a single implementation. Conversely, various features described in the context of a single implementation may also be implemented individually in multiple implementations or in any suitable sub-combination. Furthermore, although the features previously described may be described as functioning in certain combinations, or even originally claimed as such, in some cases one or more features from a claimed combination may be removed from that combination, and the claimed combination may involve sub-combinations or variations thereof.

[0122] Specific implementations of the subject matter of this invention have been described. However, it will be understood that various modifications, substitutions, and alternatives may be made. Although operations are described in a specific order in the drawings or claims, this should not be construed as requiring that such operations be performed in the specific order shown or in sequence, or that all of the operations shown be performed (some operations may be considered optional) to achieve the desired result. Therefore, the exemplary implementations described above do not limit or restrict this disclosure.

Claims

1. A method for forming a geothermal well in an underground region, the method comprising: A transverse wellbore is formed in a formation in an underground region, the transverse wellbore having a substantially impermeable fluid interface between the transverse wellbore and the formation, wherein forming the transverse wellbore includes: Drilling is performed in the formation using a non-contact drill bit located at the end of a drill string, wherein, at a rock face located in front of the drill bit, the drill bit induces tension to break the rock at the rock face, and the inherent temperature of the rock adjacent to the rock face in front of the drill bit is at least 250 degrees Celsius; and While inducing tension through the drill bit to break the rock at the rock face, by flowing water-based or oil-based drilling fluid at the rock face, tension is induced to stress the rock at the rock face, the temperature of the drilling fluid at the rock face is lower than the inherent temperature of the rock adjacent to the rock face in front of the drill bit, and the difference between the inherent temperature of the rock adjacent to the rock face and the temperature of the drilling fluid at the rock face is at least 100 degrees Celsius; and To seal the transverse wellbore without using casing to form the interface; and The geothermal working fluid is circulated through the transverse wellbore in a closed loop.

2. The method according to claim 1, wherein, The downhole end of the horizontal wellbore is located at a measurement depth of at least 4,000 meters.

3. The method according to claim 1, wherein, The bottom end of the horizontal wellbore is located at a vertical depth of at least 6,000 meters.

4. The method according to claim 1, wherein, The temperature difference between the inherent temperature of the rock adjacent to the rock face in front of the drill bit and the temperature of the drilling fluid at the rock face in front of the drill bit is at least 175 degrees Celsius.

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

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

7. The method according to any one of claims 1 to 6, further comprising forming a closed-loop geothermal well system, wherein, The closed-loop geothermal well system includes the horizontal wellbore.

8. The method according to claim 7, wherein, The wellbore is a transverse wellbore, and the formation of the closed-loop geothermal well system includes drilling the transverse wellbore from a first surface wellbore and connecting the first surface wellbore to a second surface wellbore through the transverse wellbore.

9. The method according to any one of claims 1 to 6, wherein, The difference between the inherent temperature of the rock face adjacent to the wellbore wall of the transverse wellbore behind the drill bit and the temperature of the drilling fluid at the rock face of the wellbore wall of the transverse wellbore behind the drill bit induces radial tensile fractures in at least a portion of the wellbore wall of the transverse wellbore behind the drill bit, and the method further includes sealing the radial tensile fractures with a sealing material.

10. The method according to any one of claims 1 to 6, wherein, The drill string includes a plurality of segments, wherein at least one of the segments includes a coating that at least partially covers the circumferential surface of the segment, and wherein the normalized thermal resistance of the length of the coated portion of the drill string is at least 0.002 mKelvin per watt.

11. The method according to claim 10, wherein, The normalized thermal resistance of the coated tube wall portion is at least 0.01 mKelvin per watt.

12. The method according to claim 10, wherein, The plurality of pipe segments are connected to each other at joints, and wherein the coating at least partially covers the circumferential surface of one or more of the joints.

13. The method according to any one of claims 1 to 6, wherein, The transverse wellbore is the first wellbore, and the method further includes: Forming a second wellbore intersecting the first wellbore; and At least one of the following: The second drilling fluid flow is directed down the second wellbore, wherein the second drilling fluid flow provides at least a portion of the drilling fluid flowing at the rock face in front of the drill bit, and This diverts the drilling fluid backflow from the bottom end of the first wellbore to the second wellbore.

14. The method according to claim 1, further comprising: Position the intermediate tubing string in the well; Position the drill string inside the intermediate tubing string; This forms an inner annular portion between the outside of the drill string and the inside of the intermediate tubing string, the inner annular portion extending at least partially downhole along the length of the drill string; as well as The internal annular portion is at least partially filled with thermal insulation material.

15. The method according to claim 14, wherein, The heat insulation material includes gas.

16. The method according to any one of claims 1 to 6, further comprising adding a phase change material to the drilling fluid, the phase change material being designated to undergo a phase change near the downhole end of the drill string.

17. The method according to claim 1, wherein, The drill string includes an uphole portion and a downhole portion, wherein the uphole portion includes a first plurality of pipe segments, the downhole portion includes a second plurality of pipe segments, and wherein a majority of the first plurality of pipe segments has a tensile strength that is at least 25% higher than that of a majority of the second plurality of pipe segments, and a majority of the second plurality of pipe segments is at least 35% lighter than a majority of the first plurality of pipe segments.

18. The method according to claim 1, wherein, When the drilling fluid flows through the drill string to the surface position at the top end of the transverse wellbore, the drilling fluid has a temperature greater than zero degrees Celsius.

19. A system for drilling a wellbore in a geothermal well in an underground area, the system comprising: A drill string comprising a non-contact drill bit configured to induce pull to break rock at the bottom end of a transverse wellbore in the subsurface region, wherein the inherent temperature of the rock adjacent to the bottom end of the transverse wellbore is at least 250 degrees Celsius. A water-based or oil-based drilling fluid, wherein the system is configured such that: while inducing tension through the drill bit to break the rock, the water-based or oil-based drilling fluid induced tension to stress the rock by flowing from the drill bit, the temperature of the drilling fluid at the rock face is lower than the inherent temperature of the rock adjacent to the rock face in front of the drill bit, and the difference between the inherent temperature of the rock adjacent to the rock face in front of the drill bit and the temperature of the drilling fluid at the rock face in front of the drill bit is at least 100 degrees Celsius; as well as A sealing material is configured to seal the transverse wellbore after drilling without the use of casing, such that the interface between the transverse wellbore and the formation is substantially impermeable to fluids, and that geothermal working fluids can flow through the transverse wellbore in a closed loop.

20. The system according to claim 19, wherein, The downhole end of the horizontal wellbore is located at a measurement depth of at least 4,000 meters.

21. The system according to claim 19, wherein, The temperature difference between the inherent temperature of the rock adjacent to the rock face in front of the drill bit and the temperature of the drilling fluid at the rock face in front of the drill bit is at least 175 degrees Celsius.

22. The system according to claim 19, wherein, The inherent temperature of the rock adjacent to the rock face in front of the drill bit is at least 350 degrees Celsius, and the difference between the inherent temperature of the rock adjacent to the rock face in front of the drill bit and the temperature of the drilling fluid at the rock face in front of the drill bit is at least 200 degrees Celsius.

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