Cooling for geothermal well drilling

Abstract

To provide a method and system for drilling geothermal wells.SOLUTION: A method for drilling a geothermal well in a subsurface zone includes drilling a geothermal well bore in the subsurface zone with a drill string. Intrinsic temperature of rock near a rock face located at a downhole end of the well bore is at least 250 degrees Celsius, and during the drilling step, a drilling fluid is flowed at the rock face at a temperature such that the difference between the intrinsic temperature of the rock near the rock face and the temperature of the drilling fluid at the rock face is at least 100 degrees Celsius.SELECTED DRAWING: Figure 2

Description

Technical Field

[0001] This disclosure relates to geothermal well drilling.

Background Art

[0002] Wells drilled for geothermal systems can face high formation temperatures. Such high temperatures can cause problems with drilling rates, the operation of downhole electronics, and other factors.

Prior Art Documents

Patent Documents

[0003]

Patent Document 1

Patent Document 2

Patent Document 3

Patent Document 4

Patent Document 5

Patent Document 6

Patent Document 7

Patent Document 8

Patent Document 9

Patent Document 10

Patent Document 11

Patent Document 12

Patent Document 13

[0004] This invention provides a method and system for drilling geothermal wells. [Means for solving the problem]

[0005] Some aspects of the subject matter herein may be implemented as a method for drilling a geothermal well in an underground zone. This method includes the step of drilling a geothermal well into an underground zone using a drill string. The intrinsic temperature of the rock near the rock face located at the downhole end of the well is at least 250 degrees Celsius. During the drilling step, a drilling fluid is flowed onto the rock face at a temperature such that the difference between the intrinsic temperature of the rock near the rock face and the temperature of the drilling fluid on the rock face is at least 100 degrees Celsius.

[0006] One embodiment, which can be combined with any other embodiment, may include the following feature: The difference between the intrinsic temperature of the rock near the rock face and the temperature of the drilling fluid at the rock face induces a thermally induced stress in the rock at the rock face that is higher than the tensile strength of the rock at the rock face.

[0007] One embodiment, which can be combined with any other embodiment, may include the following features: The downhole end of the well is located at a measurement depth of at least 4,000 meters.

[0008] One embodiment, which can be combined with any other embodiment, may include the following feature: The downhole end of the well is located at a vertical depth of at least 6,000 meters.

[0009] One embodiment, which can be combined with any other embodiment, may include the following feature: The difference between the intrinsic temperature of the rock near the rock face and the temperature of the drilling fluid at the rock face is at least 175 degrees Celsius.

[0010] One aspect that can be combined with any other aspect may include the following features. The natural temperature of the rock near the rock face is at least 350 degrees Celsius, and the difference between the natural temperature of the rock near the rock face and the temperature of the drilling fluid at the rock face is at least 200 degrees Celsius.

[0011] One aspect that can be combined with any other aspect may include the following features. The natural temperature of the rock near the rock face is at least 500 degrees Celsius, and the difference between the natural temperature of the rock near the rock face and the temperature of the drilling fluid at the rock face is at least 350 degrees Celsius.

[0012] One aspect that can be combined with any other aspect may include the following feature. The wellbore is a horizontal wellbore.

[0013] One aspect that can be combined with any other aspect may include the following feature. The downhole end of the drill string includes a rotary drill bit.

[0014] One aspect that can be combined with any other aspect may include the following feature. The downhole end of the drill includes a non-contact drill bit configured to break layer components at the rock face without requiring contact between the bit and the rock face.

[0015] One aspect that can be combined with any other aspect may include the following feature. A closed-loop geothermal well system including a wellbore is formed.

[0016] One aspect that can be combined with any other aspect may include the following features. The wellbore is a horizontal wellbore. The step of forming the closed-loop system includes the step of drilling a horizontal wellbore from a first surface wellbore and the step of connecting the first surface wellbore to a second surface wellbore by the horizontal wellbore.

[0017] One aspect that can be combined with any other aspect may include the following features. The difference between the in-situ temperature of the rock near the rock face and the temperature of the drilling fluid at the rock face induces a radial tensile fracture in at least a portion of the wellbore wall. The method further includes the step of sealing the radial tensile fracture with a sealing material.

[0018] One aspect that can be combined with any other aspect may include the following features. The drill string comprises a plurality of tube segments. At least one of the tube segments comprises a coating layer that at least partially covers the circumferential surface of the tube segment. The thermal resistance normalized by the length of the coated wall portion of the tube string is at least 0.002 meter Kelvin per watt.

[0019] One aspect that can be combined with any other aspect may include the following features. The thermal resistance normalized by the length of the coated wall portion is at least 0.01 meter Kelvin per watt.

[0020] One aspect that can be combined with any other aspect may include the following features. The plurality of tube segments are interconnected at connection joints. The coating layer at least partially covers one or more circumferential surfaces of the connection joints.

[0021] One aspect that can be combined with any other aspect may include the following features. The wellbore is a first wellbore. The method further includes the step of forming a second wellbore that intersects the first wellbore. A second drilling fluid flow is flowed below the second wellbore, and this second fluid flow constitutes at least a portion of the drilling fluid flowing across the rock face. In addition to or alternatively to the second fluid flow, a reflux drilling fluid flow is branched upward from the downhole end of the first wellbore to the second wellbore.

[0022] One embodiment, which can be combined with any other embodiment, may include the following features: The method further includes the steps of positioning an intermediate tube string in a well and positioning a drill string within the intermediate tube string. In this way, an internal annular gap is formed between the outside of the drill string and the inside of the intermediate tube string, extending at least partially into the downhole along the length of the drill string. The method further includes the step of at least partially filling the internal annular gap with an insulating material.

[0023] One embodiment, which can be combined with any other embodiment, may include the following feature: the insulating material is a gas, or contains a gas.

[0024] One embodiment, which can be combined with any other embodiment, may include the following features: The method further includes the step of adding a phase-change material to the drilling fluid, which is characterized to undergo a phase change near the downhole end of the drill string.

[0025] One embodiment, which can be combined with any other embodiment, may include the following features: The drill string comprises an up-hole portion consisting of a first plurality of tube segments and a down-hole portion consisting of a second plurality of tube segments. The majority of the first plurality of tube segments have a tensile strength at least 25% higher than the tensile strength of the majority of the second plurality of tube segments. The majority of the second plurality of tube segments are at least 35% lighter than the majority of the first plurality of tube segments.

[0026] Several aspects of the subject matter herein may be implemented as a method for drilling a geothermal well in a subsurface zone. This method includes the steps of drilling a first surface well and a second surface well. A lateral well is drilled from the first surface well to connect the first surface well to the second surface well in the subsurface zone. Drilling the lateral well includes positioning a drill string within the lateral well. The drill string defines a conduit for displacing fractured layer components from the rock face by flowing drilling fluid onto the rock face at the downhole end of the lateral well. This method also further includes the step of drilling the lateral well further into the subsurface zone using the drill string. The intrinsic temperature of the rock near the rock face located at the downhole end of the lateral well is at least 250 degrees Celsius. The drilling fluid is introduced into the lateral well at a temperature at the rock face that is at least 100 degrees Celsius lower than the intrinsic temperature of the rock near the rock face. The drill string is removed from the lateral well, and the working fluid is circulated in a closed loop within the first surface well, the second surface well, and the lateral well.

[0027] One embodiment, which can be combined with any other embodiment, may include the following feature: Thermal energy is extracted from the working fluid.

[0028] Some aspects of the subject matter herein may be implemented as a system for drilling geothermal wells in an underground zone. The intrinsic temperature of the rock near the rock face located at the downhole end of the well is at least 250 degrees Celsius. The system comprises a drill string having a drill bit for fracturing a layer at the rock face, and a drilling fluid circulated through the rock face at a temperature such that the difference between the intrinsic temperature of the rock near the rock face and the temperature of the drilling fluid at the rock face is at least 100 degrees Celsius.

[0029] One embodiment, which can be combined with any other embodiment, may include the following feature: The difference between the intrinsic temperature of the rock near the rock face and the temperature of the drilling fluid at the rock face induces a thermally induced stress in the rock at the rock face that is higher than the tensile strength of the rock at the rock face.

[0030] One embodiment, which can be combined with any other embodiment, may include the following features: The downhole end of the well is located at a measurement depth of at least 4,000 meters.

[0031] One embodiment, which can be combined with any other embodiment, may include the following feature: the difference between the intrinsic temperature of the rock near the rock face and the temperature of the drilling fluid at the rock face is at least 175 degrees Celsius.

[0032] One embodiment, which can be combined with any other embodiment, may include the following features: the intrinsic temperature of the rock at the rock surface is at least 350 degrees Celsius, and the difference between the intrinsic temperature of the rock near the rock surface and the temperature of the drilling fluid at the rock surface is at least 200 degrees Celsius.

[0033] One embodiment, which can be combined with any other embodiment, may include the following feature: The well is a lateral well. [Brief explanation of the drawing]

[0034] [Figure 1A] This is a schematic diagram of a closed-loop geothermal system based on the concept described herein. [Figure 1B] Figure 1A is a plan view of the closed-loop geothermal system shown. [Figure 2] This is a schematic diagram of a drilling system based on the concept described herein. [Figure 3A] This is a schematic diagram of a drill bit according to the concept described herein. [Figure 3B] This is a schematic cross-sectional view of a drill bit cone according to the concept described herein. [Figure 4A] This graph shows the temperature-pressure relationship for the brittle-to-quasi-brittle transition in plastic rocks according to the concept of this specification. [Figure 4B] This graph shows the brittle-to-quasi-brittle transition in brittle igneous rocks according to the concept of this specification. [Figure 5]This graph shows the effects of strain and stress on brittle and plastic rocks according to the concepts of this specification. [Figure 6A] This graph shows the relationship between rock brittleness and drilling progress. [Figure 6B] This figure shows the relationship between rock damage caused by drilling operations and the cooling temperature difference. [Figure 7] This graph shows the results of laboratory tests on the drilling rate in relation to the temperature difference between the drilling fluid and the rock being drilled. [Figure 8A] This figure shows coated tube segments of a tubing string for drilling according to the concept of this specification. [Figure 8B] This figure shows coated tube segments of a tubing string for drilling according to the concept of this specification. [Figure 9A] This figure shows the relationship between vertical depth and the temperature of the drill pipe, annular gap, and rock when using a tube segment with a certain coating configuration according to the concept of this specification. [Figure 9B] This figure shows the relationship between vertical depth and the temperature of the drill pipe, annular gap, and rock when using a tube segment with a certain coating configuration according to the concept of this specification. [Figure 9C] This figure shows the relationship between vertical depth and the temperature of the drill pipe, annular gap, and rock when using a tube segment with a certain coating configuration according to the concept of this specification. [Figure 9D] This figure shows the relationship between vertical depth and the temperature of the drill pipe, annular gap, and rock when using a tube segment with a certain coating configuration according to the concept of this specification. [Figure 10] This figure shows the relationship between the maximum drillable rock temperature and the thermal gradient for each different tube segment coating configuration according to the concept of this specification. [Figure 11] This is a schematic diagram of the thermal conductivity resistance for annular gaps and different tube configurations according to the concept of this specification. [Figure 12] This is a schematic diagram of a well-hole system using a second adiabatic annular gap according to the concept described herein. [Figure 13A] Figure 12 shows the thermal effect of the second adiabatic annular gap. [Figure 13B] Figure 12 shows the thermal effect of the second adiabatic annular gap. [Figure 14] This is a schematic diagram of a well system for drilling using a second well that serves as the inlet and / or outlet for the drilling fluid according to the concept herein. [Modes for carrying out the invention]

[0035] Figure 1A shows a closed-loop geothermal system according to the concept of this specification. This closed-loop geothermal well system can be, for example, a system by Eavor Technologies Inc, Calgary, Alberta, consisting of a sealed horizontal well network that functions as a radiator or heat exchanger between the well and the downhole layer. Descriptions of methods and apparatus used in some examples of such closed-loop geothermal systems can be found, for example, in U.S. Patent Publication No. 2019 / 0154010A1, U.S. Patent Publication No. 2019 / 0346181A1, and U.S. Patent Publication No. 2020 / 0011151A1, the contents of which are incorporated herein by reference.

[0036] Referring to Figure 1A, the closed-loop geothermal system 100 comprises an inlet surface well 104 and an outlet surface well 106, which are connected within a subsurface zone 108 by a network of transverse wells 110. The subsurface zone 108 is a formation, a part of a formation, or a group of formations. In the illustrated example, the surface wells 104 and 106 are substantially vertical, while in other examples of the disclosure, one or both of these surface wells may not be substantially vertical. In the illustrated example, the transverse wells 110 connecting the surface wells 104 and 106 are substantially horizontal, while in some examples of the disclosure, some or all of these transverse wells may not be substantially horizontal, and may be substantially linear or curved, or have a helical or other configuration. The transverse wells 110 are sealed, and a working fluid may be added to this closed loop as a circulating fluid. The power plant 112 is located above the surface 114 between the inlet surface well 104 and the outlet surface well 106, completing this closed-loop system. Heat from the underground zone 108 is recovered from the working fluid circulating within the loop circuit 116, and this heat is then used to generate electricity in the power plant 112 using a generator (not shown). In some examples of this disclosure, the lateral well 110 can be 2,000 to 8,000 meters long and 1,000 to 20,000 meters deep from the surface 114.

[0037] Figure 1B is a plan view of the lateral wells 110 that form part of the closed-loop geothermal system 100 of Figure 1A. Referring to Figure 1B, these lateral wells 110 are arranged radially spaced apart within the underground zone 108. Each lateral well 110 is commonly connected to the inlet well 104 and outlet well 106 in the closed loop. In some examples of this disclosure, some or all of the inlet well 104 and outlet well 106 are cased. In some examples of this disclosure, the lateral wells 110 are not cased, but instead the lateral wells and Between the layers within the aforementioned underground zone Effectively fluid-impermeable boundaryBy forming an interface, it is sealed without the use of a casing.

[0038] Figures 1A and 1B show an inlet well 104 spaced apart from an outlet well 106, but in other examples of this disclosure, wells 104 and 106 can be located close together, and a network of lateral wells 110 can be stacked or alternating and intersect at their tip ends.

[0039] Drilling for geothermal systems, such as those shown in Figures 1A and 1B, 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 800°C). Such hard, high-temperature rocks may be encountered, for example, when drilling deep horizontal well segments, as shown in Figures 1A and 1B.

[0040] Figure 2 is a schematic diagram of a well drilling system 200 according to an example of the present disclosure. This well drilling system 200 may be suitable for drilling an inlet surface well 104, an outlet surface well 106, and / or a lateral well 110 as shown in Figures 1A and 1B. Referring to Figure 2, the well 202 is formed in the subsurface zone 204 by drilling with a drill string 206 positioned within the well 202. The drill string 206 includes a bottom hole assembly (BHA) 210 at the downhole end. The BHA 210 includes a drill bit 208 and may further include a drill collar, an inclined drilling tool, and various electrical and electronic components for operating and / or controlling the drill bit 208. The interior of the drill string 206 defines a conduit, which is used to displace the fractured layer components from the rock face 214 by flowing drilling fluid 212 to the downhole end of the well, and these layer components are then carried upward by the drilling fluid 212 along an annular gap 216 defined between the outside of the drill string 206 and the inner surface of the well 202.

[0041] The drill string 206 comprises a plurality of tube segments 220 connected to one another by connecting joints 222. In some examples of this disclosure, the connecting joint 222 consists of a threaded box-pin joint or other suitable connecting part.

[0042] The heat transfer illustrated by arrow 224 can proceed from the underground zone 204 into the annular gap 216, and from the annular gap 216 into the interior of the drill string 206 and into the drilling fluid 212 flowing downward through the drill string 206. Thus, the heat transfer from the underground zone 204 to the annular gap 216 and from the annular gap 216 into the interior of the drill string 206 contributes to the temperature rise of the drilling fluid 212 by a countercurrent exchange mechanism before the drilling fluid 212 is delivered to the drill bit 208.

[0043] In some examples of 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 other types of drill bits that rely on contact with rock to achieve drilling. An example of a suitable contact-type drill bit is the tricone bit 300 shown in Figures 3A and 3B. As shown in Figure 3A, the tricone bit 300 comprises three cones 302, each cone 302 having a plurality of cutting elements 304. Figure 3B is a detail view of a cross section along the line 305A-305B shown in Figure 3A. In this example, each cone 302 comprises a plurality of cutting elements 304 spaced apart in the form of a specific spaced array across the plane of each cone. A series of additional cutting elements 306 may be provided to extend the service life and facilitate long-duration drilling without interruption. In this example, the additional cutting elements 306 are positioned below the cutting elements 304 such that the tips of the additional cutting elements 306 are adjacent to the bottom contacts of the cutting elements 304 that are superimposed on them. In this configuration, as element 304 wears down, the tip of the additional cutting element 306 becomes visible. This can be further accelerated by incorporating materials of different hardnesses within the gap 310 between at least adjacent elements 304 and 306. This configuration allows for the automatic regeneration of the cut surface of each cone. Further advantages of this feature include more uniform wear of the bit 300, which reduces the likelihood of eccentric drilling progress, as well as jamming or blockage / retraction in the test borehole being formed.

[0044] In other examples of this disclosure, the drill bit 208 in Figure 2 may be a non-contact drill bit configured to fracture the layer components at the rock surface 214 of the subsurface zone 204 located at the downhole end of the well 202 without requiring contact between the bit 208 and the rock surface 214, and in some examples of this disclosure, it may consist of an electronic grinding bit for electronic pulse drilling. Examples of non-contact drilling systems include plasma drilling (e.g., plasma drilling systems developed by GA Drilling, AS), laser drilling (e.g., laser drilling systems developed by Foro Energy), microwave drilling (e.g., microwave drilling systems developed by Quaise), thermal fracturing techniques such as supercritical water jetting or flame jetting, and electronic pulse drilling (e.g., electronic pulse drilling systems developed by Tetra Corporation). (It will be understood that during the drilling process, multiple portions of the non-contact drill bit may periodically collide with, rub against, or otherwise come into contact with the layer.)

[0045] For example, in the electron pulsed drilling system developed by Tetra Corporation, an electron pulverizing bit is used, which has multiple electrodes that generate high-energy sparks to break up the bedrock, thereby removing the broken bedrock from the path of the drill assembly. This bit can generate multiple sparks per second by using a specific excitation current profile that causes transient sparks to form an arc that passes through the most conductive part of the rock face located at the downhole end of the well. This arc breaks or collapses the portion of the rock face through which the arc passes, and is removed by the drilling fluid flow. A high-resistance drilling fluid is used for such electron pulsed drilling. Descriptions of several electronic 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 Application Publication No. 2020 / 0299562A1, PCT Patent Applications WO2008 / 003092, WO2010 / 027866, WO2014 / 008483, WO2018 / 136033, and WO2020 / 236189, among others. The contents of these patent documents are incorporated herein by reference. Electronic pulse drilling and other forms of non-contact drilling, because they fracture rock by tension (as opposed to compression or shear), can provide further synergistic effects, along with the cooling effect which will be discussed in more detail later.

[0046] The rate of drilling (ROP) may decrease when the rock is under very high sealing pressure, such as when drilling a lateral well 110 in a closed-loop system as shown in Figures 1A and 1B (example), and / or when the rock has plastic properties due to high temperatures that may be encountered when drilling into deep geothermal environments. Such high temperatures may also interfere with the operation of downhole electronics and / or downhole sensors. Furthermore, drilling multiple lateral wells, such as shown in Figure 1B, may require the extended use of tilt drilling techniques. Magnetometers or other downhole equipment used for such tilt drilling may be adversely affected by high downhole temperatures. Some downhole components of a tilt drilling system have a temperature limit of 150–250°C. Other downhole components may have different (even higher or lower) temperature limits or temperature ranges.

[0047] In some examples of the present disclosure, as described below, a combination of coatings, well geometry, downhole equipment, and / or appendages are used to supply a drilling fluid flow to the downhole end of the well at a drilling temperature such that the difference between the intrinsic temperature of the rock near the rock face (i.e., the temperature of the rock in front of the drill bit that will be drilled intrinsically, excluding the cooling effect of the drilling fluid) and the temperature of the drilling fluid at the rock face is at least 100°C. The fluid temperature at the rock face is the bulk fluid temperature, where convective cooling of the rock face occurs, for example, within about 1 cm of the rock face being drilled. In some examples of the present disclosure, such a temperature difference may be in a geothermal environment where the intrinsic temperature of the rock near the rock face is at least 250°C at measurement depths of 4000 m or more, i.e., at measurement depths through surface wells and lateral wells. (In this specification, this measurement depth is the length along the well path and not the sum of the vertical depths of wells other than complete vertical wells.) In some examples of the present disclosure, a larger temperature difference is possible. For example, in some examples of this disclosure, where the intrinsic temperature of the rock near the rock face is at least about 500°C, the temperature difference between the intrinsic temperature of the rock near the rock face and the temperature of the drilling fluid at the rock face can be at least about 350°C. In other examples of this disclosure, this temperature difference can be larger or smaller. Such a large temperature difference can increase ROP due to the impact cooling effect, thereby causing thermal contraction of the rock face. This applies stress to the tension of the rock, reducing the effective sealing pressure at the rock face. This can also cause tensile microfractures within the rock matrix.

[0048] For example, Figure 4A is a graph showing the temperature-pressure relationship for brittle-to-quasi-brittle transitions in plastic rocks. Plastic rocks transition to a more brittle state when the temperature or pressure decreases. When rapid thermal cooling is applied to a high-temperature brittle rock, the internal temperature of the rock decreases, and the rock transitions to a more brittle state compared to the untreated rock. Figure 4B illustrates this result in general terms. Therefore, this zone change from brittle, quasi-brittle, and any combination within a zone due to temperature manipulation makes the treated rock more brittle compared to its initial untreated state.

[0049] As shown in Figure 5, rock strength (the stress required to cause irreversible deformation) does not necessarily change with increasing brittleness. However, the deformation mode for brittle rocks is abrupt fracture and fracturing, and for rocks of higher brittleness, this fracture mode involves greater plastic deformation before fracture.

[0050] As shown in Figure 6A, the drilling rate generally increases with the brittleness of the rock, regardless of the drilling method. Specifically, pulsed electron drilling systems or other non-contact drilling systems may be particularly suitable for brittle rocks.

[0051] Figure 6B shows the relationship between cooling temperature and internal damage to rock (e.g., during drilling). Note that internal damage is a separate and additional effect on the embrittlement process described above. In contrast to mere embrittlement, a larger cooling temperature difference is required to induce irreversible damage within the rock. Irreversible damage manifests as microcracks, fracturing, and intergranular displacement due to differences in thermal contraction. Sufficient thermal cooling can induce both brittleness and subsequent irreversible damage in rock during drilling.

[0052] Figure 7 is a graph showing laboratory test results of the rate of drilling progress (ROP) against the temperature difference between the drilling fluid and the rock being drilled. These laboratory tests were conducted on 10-inch diameter granite blocks. These blocks were heated to a target temperature in an oven. The blocks were then placed in a pressurized chamber, and the chamber was pressurized to simulate a depth of approximately 1000 m in terms of both the sealing pressure (applied to the sleeve surrounding the rock sample) and the hydrostatic pressure of the drilling fluid. The rock sample was then drilled using a drilling fluid at ambient temperature at a constant bit load, rpm, and flow rate. As can be seen from Figure 7, when the temperature difference between the rock and drilling fluid exceeds approximately 175 degrees Celsius, the rate of drilling progress (ROP) substantially increases. Such a temperature difference can cause the thermally induced stress in the rock at the rock face to be higher than the tensile strength of the rock at the rock face, which increases the rate of drilling by embrittlement and causing cracks in the rock. Further increases in the temperature difference further improve the ROP.

[0053] Furthermore, impact cooling can reduce the effective lithostatic containment pressure on the rock face due to thermal contraction. In bench-scale tests without impact cooling, the ROP of drilling typically decreases with increasing containment pressure. Therefore, the impact cooling effect alone can improve performance in deep rock under high containment pressure.

[0054] In some examples of this disclosure, the difference between the intrinsic temperature of the rock near the rock face and the drilling fluid temperature at the rock face is sufficient to induce embrittlement of the layer at the rock face. When the embrittlemented rock fractures, it can break rapidly and without plastic deformation of its constituent parts.

[0055] In some examples of this disclosure, the difference between the intrinsic temperature of the rock near the rock face and the temperature of the cooling fluid at the rock face is sufficient to reduce the tensile strength of the rock and / or damage the rock microstructure (which can reduce the rock strength due to small microfractures and brittleness within the rock matrix), and / or induce spalling of the rock face due to thermal contraction of the rock. In some examples of this disclosure, the temperature difference is sufficient to reduce the sealing pressure at the rock face (by causing thermal contraction of the rock and inducing fracture). Once thermal contraction occurs to a level that causes fracture in the rock face, the rock face loses its sealing pressure and becomes more easily fractured.

[0056] In some examples of this disclosure, the difference between the intrinsic temperature of the rock near the rock face and the drilling fluid temperature at the rock face is sufficient to maintain the bottom hole assembly (BHA) at a low and relatively constant temperature, even when drilling rock at temperatures of 250°C to 500°C or higher and at depths of 2 to 14 km or higher. Such cooling is particularly advantageous in the example of electron pulse drilling, because such techniques inherently require power generation and transmission within the BHA, and electrical resistance increases with rising temperature. Despite this rock fracture 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 utilizing the cooling systems of this disclosure, these components can be maintained below their temperature limits, even when drilling very hot rock.

[0057] Similarly, some examples described herein may enable the use of inclined drilling in rocky environments at higher temperatures than previously possible by cooling the magnetometer and other downhole components of the inclined drilling system.

[0058] Therefore, the enhanced cooling systems and methods disclosed herein may enable the use of drilling systems (e.g., electron pulse drilling) and inclined drilling components to drill multiple horizontal wells (e.g., those shown in Figure 1B) of a closed-loop geothermal system in a high-layer temperature environment, with better downhole electronics performance and higher ROP, by increasing the temperature difference between the rock near the rock face and the drilling fluid at the rock face.

[0059] In some examples of this disclosure, enhanced cooling can be used to drill all of the wells in the systems shown in Figures 1A and 1B. Because high-temperature rock may be encountered in the layer where the lateral well 110 is drilled, in some examples of this disclosure, conventional, unmodified cooling can be used to drill the components of the vertical well shown in Figures 1A and 1B, and enhanced cooling can be used to drill some or all of the lateral well 110. Impact cooling may be more effective than ROP when the rock is at a high temperature, such as above 250°C. Therefore, enhanced cooling may be particularly suitable for wells where the majority of the drilling takes place in very high-temperature rock. This advantage of ROP may be reduced in a single vertical well or a staggered well, but it can be significant when a network of wells is drilled at depths in high-temperature rock, such as in the examples shown in Figures 1A and 1B.

[0060] Figure 8A shows a cooling coating applied to the tube segments 220 of the drill string 206 in Figure 2, according to an example of the present disclosure. The tube segments 220 are interconnected by connecting joints 222 and comprise a main body 802. In some examples of the present disclosure, the main body 802 consists of a carbon steel body. In other examples of the present disclosure, as will be described in more detail later, the main body 802 may consist of an aluminum alloy, a titanium alloy, and / or a fiber composite material (e.g., a polymer binder composite material containing carbon fiber, aramid fiber, fiberglass, E-glass, and / or other structural fibers). The inner coating layer 804 covers at least partially the inner circumferential surface of the tube segments 220. In the illustrated example, the inner coating layer covers the tube segments 220 along their entire length and further covers the inner surface of the connecting joints 222. In some examples of the present disclosure, the connecting joints 222 may be a significant heat transfer region. By covering the inner surface of the connecting joint 222 with the inner coating layer 804, heat transfer in the connecting joint 222 is reduced.

[0061] The outer coating layer 806 covers at least partially the outer circumferential surface of the tube segment 220. In the illustrated example, the connecting joint 222 has a larger diameter than the main body 802 and is therefore subject to greater contact with the well wall or other components of the well system, and thus to greater frictional forces. In the illustrated example, the outer coating layer 806 covers the portion of the tube segment 220 between the connecting joints 222, but not the larger diameter region around the connecting joints 222. In this way, the outer coating layer 806 is less exposed to the friction generated at the connecting joints 222.

[0062] In some examples of this disclosure, the inner coating layer 804 consists of one or more of the epoxy novolac resins TK340XT and CP-2060, and the epoxy phenol resins TK34XT and CP-2050. The TK products are commercially available from NOV, Inc., and the CP products are commercially available from Aremco products Inc. The thickness of the inner coating layer 804 made of epoxy phenol resin can be in the range of 150 to 250 μm, and the thickness of the inner coating layer 804 made of epoxy novolac resin can be in the range of 400 to 1270 μm. The epoxy phenol resin can have an average thermal conductivity of about 0.8 W / mk, and the epoxy novolac resin can have an average thermal conductivity of about 0.4 W / mk. To further reduce the heat transfer coefficient, insulating particles can be added to these resins or otherwise.

[0063] In some examples of this disclosure, the outer coating layer 806 consists of a fiber composite overlap (e.g., carbon fiber, E-glass composite, and / or other fiber composite) with a thickness of about 2540 μm. These coatings are commercially available from ACPT Inc. and / or Seal for Life Industries. E-glass may have a thermal conductivity of about 0.288 W / mk, and carbon fiber may have a thermal conductivity of about 0.8 W / km.

[0064] In some examples of this disclosure, the thermal resistance normalized by the length of the wall of the tubing string is at least about 0.002 mKelvin / watt. In some examples of this disclosure, the thermal resistance normalized by the length of the wall of the tubing string is at least about 0.01 mKelvin / watt. Referring to Figure 8A, the thickness 810 of this wall is defined by the inner surface of the inner coating layer 804 and the outer surface of the outer coating layer 806. In this disclosure, “length-normalized thermal resistance” is the effective conductive thermal resistance of the string with respect to radial heat transfer, taking into account the change in material along the length, and is the temperature difference required to transfer 1 watt of energy over an axial length of 1 meter of material.

[0065] The following are the thermal resistances normalized by the length of the wall portion of a tubing string in some examples of the present disclosure, having an inner body 802 and an inner coating layer 804 made of steel of suggestive material and thickness (but without an outer coating layer 806).

[0066] [Table 1]

[0067] The following are thermal resistances normalized by the length of the wall portion of a tubing string in some examples of the present disclosure, having an inner body 802 and inner coating layer 804 made of steel of a suggested material and thickness, and an outer coating layer 806 ("jacket") made of E-glass of a suggested thickness.

[0068] [Table 2]

[0069] In one example of this disclosure, the drill string 206 in Figure 2 comprises tube segments 220 as shown in Figure 8A, the tube segments 220 comprising an inner coating layer 804 made of epoxy novolac resin TK340XT having a thickness of about 400 microns and an outer coating layer 806 made of E-glass having a thickness of about 5 millimeters. In such an example, assuming a subsurface zone with a thermal gradient of about 60°C / km, a drill string with a length of about 8000m, a water-based drilling fluid with a circulation rate of about 3m³ / min, and a rock surface temperature of about 490°C, the drill string 206 consisting of such tube segments 220 can consequently result in a temperature difference of about 346°C between the rock near the rock surface and the drilling fluid at the rock surface.

[0070] In another example of the present disclosure, the drill string 206 in Figure 2 comprises tube segments 220 as shown in Figure 8A, which comprise an inner coating layer 804 made of epoxy novolac resin TK34XT having a thickness of about 250 microns and an outer coating layer 806 made of E-glass having a thickness of about 2.5 millimeters. In such an example, given a subsurface zone with a thermal gradient of 40°C / km, a tube string with a length of about 9000 m, a water-based drilling fluid with a circulation rate of about 3.5 m³ / min, and a rock surface temperature of about 370°C, such a drill string 206 comprising such tube segments 220 may consequently result in a temperature difference of about 196°C between the rock near the rock surface and the drilling fluid at the rock surface.

[0071] In other examples of this disclosure, the inner coating layer 804 and / or the outer coating layer 806 may have greater or lesser thicknesses, and / or may comprise other types of coatings, such as ceramic inorganic coatings, such as silicate-bonded ceramics.

[0072] Figure 8B shows a cooling coating applied to the tube segment 220 of the drill string 206 in Figure 2, according to another example of the present disclosure. In the example shown in Figure 8B, the tube segment 220 is a composite pipe segment, and these composite pipe segments comprise a composite main body 850 (which may be made from steel, titanium, aluminum, fiber composite, or other suitable material), which is connected to a connecting joint 222, which may also be made from steel, titanium, aluminum, fiber composite, or other suitable material.

[0073] Referring to Figure 8B, the inner coating layer 854 covers at least partially the inner circumferential surface of the tube segment 220. In this illustrated example, the inner coating layer 854 covers the inner circumferential surface of the tube segment 220 only at and near the location of the connecting joint 222. By covering a region of the inner circumferential surface of the segment 220 at and near the location of the connecting joint 222, the heat transfer at the connecting joint 222 is reduced. In other examples of this disclosure, the inner coating layer 854 covers the entire inner circumferential surface of the tube segment 220.

[0074] In some examples of this disclosure, the inner coating layer 854 in Figure 8B may consist of the same material and thickness as the inner coating layer 804 in Figure 8A described by reference. In some examples of this disclosure, the inner coating layer 854 may also consist of other suitable materials or thicknesses. In some examples of this disclosure, the tube segment 220 may comprise a vacuum-insulated tube (VIT), the insulation being achieved by a vacuum layer within the tube segment 220 instead of, or in addition to, the inner coating layer 804 (or 854) and the outer coating layer 806.

[0075] In some examples of this disclosure, main body 802 and / or main body 850 may comprise a high-strength-to-weight ratio steel drill pipe, such as a commercially available UD165 steel drill pipe from, for example, NOV, Inc. In some examples of this disclosure, such a steel drill pipe may be a UD-165 steel drill pipe having a yield strength of approximately 165,000 psi (1,138 MPa), a tube tensile strength of approximately 1,000,000 lbf (4.45 MN), a joint air load normalized over 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 with an outer diameter of 5.875 inches (14.92 cm).

[0076] In some examples of the present disclosure, the main body 802 and / or main body 850 may comprise a drill pipe made of a titanium alloy. In some examples of the present disclosure, such a titanium alloy drill pipe may consist of a Ti-6Al-4V titanium alloy and have a yield strength of approximately 120,000 psi (827 MPa), a tube tensile strength of approximately 750,000 lbf (3.34 MN), a joint air load normalized to length of 16 lbf / ft (233.8 N / m), and a joint strength-to-weight ratio of approximately 1,000 lbf / lbf (1000 N / N) in a drill pipe with an outer diameter of 5.875 inches (14.92 cm).

[0077] In some examples of this disclosure, the main body 802 and / or main body 850 may comprise a drill pipe made of an aluminum alloy. In some examples of this disclosure, such an aluminum alloy drill pipe may be made of an Al-Zn-Mg II aluminum alloy in a drill pipe with an outer diameter of 5.787 inches (14.699 cm) and may have a yield strength of approximately 70,000 psi (483 MPa), a tube tensile strength of approximately 600,000 lbf (2.67 MN), a joint air load normalized to length of 15.5 lbf / ft (226 N), and a joint strength-to-weight ratio of approximately 825 lbf / lbf (825 N / N). In some examples, such an aluminum alloy pipe may consist of a commercially available FarReach® drill pipe from Alcoa Energy Systems. In some examples of this disclosure, such an aluminum alloy drill pipe may consist of a commercially available aluminum drill pipe from Aluminum Drill Pipe, Inc.

[0078] In some examples of this disclosure, the main body 802 and / or main body 850 may comprise a carbon fiber composite drill pipe. In some examples of this disclosure, such a carbon fiber composite drill pipe may consist of a commercially available Advance Composite Drill Pipe from Advance Composite Products & Technology, Inc.

[0079] In some examples of this disclosure, the drill string 206 in Figure 2 comprises tube segments 220, each of which may comprise a main body 802 and / or 850 made of steel, titanium, aluminum, and / or fiber composite material, as described above. For example, in some examples of this disclosure, each segment of the drill string 206 comprises a main body 802 and / or 850 made of a single material, such as an aluminum alloy. In other examples of this disclosure, the drill string 206 may consist of various parts, each comprising multiple segments 220 made of different materials. For example, in some examples of this disclosure, some of the tube segments 220 of the drill string 206 may be made of a certain main body material (e.g., an aluminum alloy), and the remaining tube segments 220 of the drill string 206 may be made of other main body materials (e.g., steel). In some examples of this disclosure, the drill string 206 may consist of two, three, or more parts, each of which comprises a tube segment 220 having a main body made of a different material than the other parts. In other examples, most of the segments 220 closer to the drill bit 208 have a main body made of a lighter material than the segments further from the drill bit 208 to the uphole, based on a length-normalized air load. In the above example, the titanium drill pipe is about 35% lighter than steel, and the aluminum drill pipe is about 37% lighter. These segments 220 located further from the drill bit 208 to the uphole may have a main body made of a higher-strength material. In the above example, the UD-165 drill pipe has about 67% higher tensile strength than aluminum, and the titanium drill pipe has about 25% higher tensile strength than aluminum. Furthermore, the difference in tensile strength and the difference in length-normalized load can be achieved by using a single material, but with drill pipes of varying thickness / diameter in a nested manner in the uphole section compared to the downhole section.In one example of this disclosure, the majority of segment 220 located near the drill bit is approximately 35% lighter than the majority of segment 220 located in the uphole portion, and the majority of segment 220 located in the uphole portion has approximately 25% higher tensile strength than the majority of segment 220 located near the drill bit. By using different drill string materials in this manner, it becomes possible to drill into much hotter rocks at greater depths, and therefore an insulated drill string with sufficient tensile strength to extend to such depths may be required. The materials described above, when properly combined, enable drilling to depths greater than 9 km, including up to 14 km or more. Due to the Earth's geothermal gradient, rocks at greater depths have higher temperatures. This impact cooling technique provides a method to improve drilling rate and drilling performance in hotter rocks. Thus, a synergistic effect can be obtained by combining the deeper drilling made possible by combining drill pipe segments of various weights / strengths with the cooling techniques described herein. Closed-loop multilateral wells can be drilled to a sufficient depth (and therefore rock temperature) to enable shock cooling, thus significantly reducing the drilling time and cost of multilateral wells.

[0080] Figure 9A shows the results of a thermodynamic simulation of the heat transfer coefficient in a fluid flowing through a downhole tube drill string with a standard carbon steel pipe located in a cased well within a subsurface zone. This simulation assumes a water drilling fluid pumped at 3.5 cubic meters / minute below the tube string and a temperature gradient of 50°C / km from the surface (i.e., the surface location at the uphole end of the well) to the rock face (located at the downhole end of the well). Referring to Figure 9A, the curve labeled "Drill Pipe" represents the temperature of the fluid flowing through the tube drill string at a given depth, the curve labeled "Annular Gap" represents the temperature of the fluid flowing through the annular gap between the tube and the casing at a given depth, and the curve labeled "Rock" represents the intrinsic temperature of the rock at a given depth. As shown in Figure 9A, some insulation is provided to prevent heat transfer so that the temperature of the fluid located on the rock face at the bottom of the well becomes approximately 206°C, and the rock temperature becomes 260°C, resulting in a temperature difference of approximately 54°C. However, such a temperature difference may not be sufficient to cool the downhole electronics or inclined drilling equipment, or to provide a cool enough drilling fluid flow to achieve an impact cooling effect on the rock face, or to realize other advantages of using a cool drilling fluid for drilling at the downhole end of the well as described above. In Figure 9A, the fluid temperature on the rock face becomes equivalent to the annular pore temperature at the bottom of the well after the fluid has exited the drill bit.

[0081] The coating and coating geometry described with reference to Figures 8A and 8B can reduce heat exchange between the cooler fluid descending the tube string and the hotter fluid returning through the annular gap during drilling, resulting in a difference of at least 100°C between the intrinsic temperature of the rock near the rock face and the temperature of the drilling fluid located at the rock face, even in geothermal environments where the intrinsic temperature of the rock adjacent to the rock face is at least 250°C. For example, Figures 9B to 9D show the results of thermodynamic simulations of heat transfer to a downhole tube, assuming a tube segment as shown in Figure 8A, in various examples of the present disclosure as described below. In the simulations shown in Figures 9B to 9D, the inner coating layer 804 covers the entire length of the tube segment, including the inner surface of the connecting joint. In Figures 9B to 9D, the curve labeled "Tube" represents the temperature of the fluid flowing within the tube drill string at a given depth, the curve labeled "Casing" represents the temperature of the fluid flowing within the annular gap between the drill pipe tube and the casing at a given depth, and the curve labeled "Rock" represents the intrinsic temperature of the rock at a given depth. The drilling fluid flows into the tube at the surface, through the BHA, through the drill bit, through the rock surface, and into the annular gap. The temperature of the drilling fluid at the rock surface is approximately the same as the temperature of the fluid in the annular gap at the bottom of the shaft.

[0082] Figure 9B shows a thermodynamic heat transfer simulation for an example of a standard carbon steel pipe with an internal coating 804 made of 400 μm thick epoxy novolac (TK340XT) (without an external coating 806). This simulation assumes a water drilling fluid pumped at approximately 3.5 cubic meters / minute and a temperature gradient of approximately 50°C / km from the ground surface to the rock surface. As shown in Figure 9B, this example achieves a higher temperature difference compared to Figure 7, namely a temperature difference of approximately 91°C over 5000 meters.

[0083] Figure 9C shows a thermodynamic heat transfer simulation for an example of a standard carbon steel pipe with an internal coating 804 consisting of 400 μm thick epoxy novolac TK340XT and an external coating 806 consisting of a 5 mm thick E-glass jacket. This simulation assumes a water drilling fluid pumped at approximately 3 cubic meters / minute and a temperature gradient of approximately 60°C / km from the ground surface to the rock surface. As shown in Figure 9C, this example achieves a temperature difference of approximately 346°C over 8000 meters.

[0084] Figure 9D shows a thermodynamic heat transfer simulation for an example of a standard carbon steel pipe having an internal coating 804 consisting of 250 μm thick epoxy novolac TK34 and an external coating 806 consisting of a 2.5 mm thick E-glass jacket. This simulation assumes a water drilling fluid pumped at approximately 3.5 cubic meters / minute and a temperature gradient of approximately 40°C / km from the ground surface to the rock surface. As shown in Figure 9D, this example achieves a temperature difference of approximately 196°C over 9000 meters.

[0085] Figure 10 shows the maximum drillable rock temperature for the thermal gradient from the ground surface to the rock surface (located at the downhole end of the well), based on the example described with reference to Figures 9C and 9D, assuming that the temperature of the drilling fluid leaving the drill bit at the rock surface should not exceed approximately 150°C. The upper curve 1002 corresponds to the example described with reference to Figure 9C. For example, using the example described with reference to Figure 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 example described with reference to Figure 9D. For example, using the example described with reference to Figure 9D, at point 1008, the temperature gradient is approximately 40°C / km, and the maximum drillable rock temperature is approximately 335°C.

[0086] In some examples of this disclosure, a phase-change material, such as water ice or dry ice, may be added to the drilling fluid of the drilling system (e.g., drilling fluid 212 in Figure 2) instead of or in addition to the coating layers 804 and 806 on the tube segment 220. These phase-change materials may absorb thermal energy by undergoing a phase change (e.g., melting). In some examples of this disclosure, the drilling fluid may be pumped at a flow rate sufficient to cause the phase-change material to undergo a phase change in the vicinity of the drill bit.

[0087] In some examples of this disclosure, a heat exchanger may be added to the system in Figure 2 to cool the drilling fluid 212 as it is recirculated from the well 202 back to the downhole. In some examples of this disclosure, such a heat exchanger may be located at the ground surface.

[0088] Not all drilling fluid must necessarily flow through the drill bit to achieve the results described herein. Alternatively, a portion of the drilling fluid may pass from the tube into the annular gap via a port or other device located near the bit or BHA. If components within the bottom hole assembly have flow limiters, such configurations may allow for higher flow rates.

[0089] Figure 11 shows the heat transfer resistance, or thermal resistance, through annular gaps and tubes of four different configurations. As the low-temperature drilling fluid circulates through the tubes to the downhole and back up through the annular gaps, the drilling fluid in the annular gaps is heated to tannulus by the surrounding rock of the subsurface zone. Subsequently, the drilling fluid in the annular gaps heats the drilling fluid inside the tubes to ttubing. In each example, the primary heat transfer mechanism through the annular gaps filled with drilling fluid is convection. The flowing drilling fluid, i.e., the imperfectly convective medium, exhibits thermal resistance (convection, annulus). In the case of sections of uninsulated carbon steel tubes (carbon steel), this steel is an imperfectly conductive medium and exhibits additional (series) thermal resistance (convection, steel). Finally, the primary heat transfer mechanism within the drilling fluid-filled tubes, which heats the flowing drilling fluid itself, is convection. This drilling fluid exhibits additional (series) thermal resistance (convection, tube-ing). When the tube is completely covered with an insulating coating (coated carbon steel), this coating exhibits additional thermal resistance (a series of thermal resistances). When composite material tubes with steel collars (joints) are used (composite material and composite material + coated collar), the composite material tube and carbon steel exhibit parallel thermal resistances (RCONDUCTION, COMPOSITE and RCONDUCTION, STEEL COLLAR, respectively). In other words, materials with lower thermal resistance (i.e., materials with lower insulating properties) have a greater impact on the total thermal resistance of the tube segment. Typically, because composite materials have higher thermal resistance than steel, coating only the steel collar can result in a significant increase in the total thermal resistance of the tube segment.

[0090] Figure 12 illustrates the formation of a second adiabatic annular gap according to an example of the present disclosure. This example of the present disclosure, described with reference to Figure 12, is described with reference to the components of the drilling system 200 in Figure 2. Referring to Figure 12, the well 202 is drilled using a drill bit 208 at the downhole end of a drill string 206. Drilling fluid 212 flows downward through the drill string 206 and out through the drill bit 208. The annular gap 216 is defined in the lower portion of the well 202 so as to be located between the outside of the drill string 206 and the well 202. The intermediate tube string 1202 is positioned in the well so as to position the drill string 206 within the intermediate tube string 1202, thereby forming an internal annular gap 1204 between the outside of the drill string 206 and the inside of the intermediate tube string 1202, and an external annular gap 1206 between the outside of the intermediate tube string 1202 and the well 202. The internal annular gap 1204 and the external annular gap 1206 each extend at least partially into the downhole along the length of the drill string 206. In some examples of the present disclosure, the internal annular gap 1204 may be filled with an insulating material. In some examples of the present disclosure, this insulating material is gas, so that a “gas blanket” is formed. In other examples of the present disclosure, the internal annular gap 1204 may be filled with a foaming material, insulating oil, or any fluid or material having low conductivity, instead of or in addition to gas.

[0091] The internal annular gap 1204 insulates the drilling fluid 212 flowing downward from the heated fluid flowing upward within the external annular gap 1206. Figures 13A and 13B show a comparison of well fluid temperatures in a certain well system. Figure 13A shows the expected drilling fluid temperature with respect to depth in a drilling system without an insulated intermediate tube string, and Figure 13B shows the drilling fluid temperature with respect to depth in a drilling system with an insulated intermediate tube string forming an internal annular gap filled with insulated gas, as described with reference to Figure 12. The bottom portion of the well continues to heat due to the lack of insulation at the bottom of the gas blanket, but the rock face temperature is still dramatically cooled. In this example, the internal annular gap 1204 only extends to the bottom of the last casing string, but significant cooling is still achieved at the rock face (of the main well and / or lateral wells drilled from the main well). The adiabatic fluid blanket remains in place due to its much lower density and therefore essentially floats above the drilling fluid.

[0092] Because the "blanket fluid" has a lower density, this blanket fluid is pressurized in a surface well (not shown). Pressure-controlled drilling (MPD) technology is a system that maintains pressure within the annular gap around a rotary drill pipe. The main challenge is to seal it to prevent fluid leakage beyond the rotary pipe. MPD systems have been improved in recent years to a sufficient extent to hold the pressurized fluid blanket in place. Therefore, it is preferable to use a modern MPD system when the fluid blanket will fill an internal annular gap coaxial with the rotary drill pipe.

[0093] One variation involves installing another casing string (not shown) to form two internal annular gaps. The internal annular gaps are positioned coaxially and adjacently to the external annular gaps, which can be filled with a rotary drill pipe, a secondary internal annular gap, and an external annular gap from which the heated drilling fluid returns. This setup requires the cost and hassle associated with larger wells to create room for the additional annular gaps, but avoids the use of a high-pressure MPD system because the internal annular gaps can be filled with drilling fluid.

[0094] Another example of reducing counterflow heat transfer from the annular gap to the tube is to utilize a second well that serves as the inlet and / or outlet for the drilling fluid. Figure 14 shows a schematic diagram of this “slipstream well”.

[0095] Referring to Figure 14, and further as illustrated with reference to Figure 2, well 202 is drilled using a drill bit 208 at the downhole end of a drill string 206. Drilling fluid 212 flows downward through the drill string 206 to the drill bit 208. An annular gap 216 is defined between the outside of the tube string and well 202. Well 202 may comprise a primary well and / or a lateral well.

[0096] In the example shown in Figure 14, well 202 is the first well, and the second well 1402 is drilled so as to intersect with the first well 202. The second drilling fluid flow 1404 flows downward through the second well 1402. The second drilling fluid flow 1404 constitutes at least a portion of the drilling fluid flowing at the downhole end of well 202, i.e., on the rock face near the drill bit 208. The second well 1402 is located far enough from the first well 202 to reduce or eliminate heat transfer, thereby the second drilling fluid flow 1404 provides additional cooling to the downhole end of well 202.

[0097] In some examples of this disclosure, drilling fluid and cuttings may be delivered up the second well 1402 and back to the surface. In this modification, the heated fluid does not flow upward into the annular gap 216, and therefore counterflow heat exchange does not occur above the intersection point 1406. This directional flow is indicated by a dashed line by the figure 1408.

[0098] It will be understood that a second well 1402 may be drilled and used to cool any number of additional wells / conduits from the surface location. For example, a closed-loop geothermal well system may be constructed by drilling four corner wells. After the completion of drilling one of the four corner wells, the “slipstream” crossing section is sealed and abandoned, and another crossing segment is drilled to intersect one of the other corner wells. In this configuration, a single well may be used multiple times to cool other wells, and only the interconnecting segments need to be drilled each time.

[0099] Impact cooling of hot rock using the techniques described herein can introduce several challenges to the drilling process behind the bit. Cooling increases the compressive strength of the well but decreases its tensile strength. Significant temperature differences between the circulating drilling fluid and the well wall can lead to cooling-induced tensile fractures that move radially away from the well. These tensile fractures may need to be sealed or controlled with well-strengthening materials such as graphite or calcium carbonate, or other loss-of-circulation materials. Furthermore, these fractures may need to be sealed with sealant chemicals such as sodium silicate or potassium silicate. Another approach is to carry out the drilling process underbalanced, which can be used to mitigate the tensile fracture effects behind the bit, either separately or in combination with other techniques disclosed. A system design particularly suitable for electron pulse drilling would involve a pressure-controlled drilling system and the use of an oil-based drilling fluid with high electrical resistance and an equivalent circulating specific gravity below hydrostatic pressure. This provides the freedom to control the downhole pressure while supplying a drilling fluid suitable for electron grinding.

[0100] Another difficulty associated with impact cooling is the possibility that induced tensile fractures may lead to spreading shear fractures or other further problems, resulting in large amounts of cuttings or the collapse of rock fragments of varying sizes from the borehole wall behind the bit. Excess debris generated by the impact cooling process can be removed by combining highly viscous drilling fluids and high flow rates (>2.5 m³ / min) with other methods. In other examples of this disclosure, the drilling fluid may have a Marsh funnel viscosity of at least 80–100 secs. Also, various slags or sweeps of high-viscosity fluid volumes passing through the system assist in the removal of excess debris. Successfully circulating larger fragments to the surface may correlate with two key parameters: annular pore fluid velocity (determined by flow rate and annular pore volume) and fluid rheology (plastic viscosity / yield point (PV / YP) that adds transport capacity / reduces sliding velocity, and gel strength that suspends while linking). Periodic circulation of low-volume / high-viscosity sweeps can transport and float large debris to the surface. In some examples of this disclosure, these debris may be captured (i.e., filtered and removed) at the surface to prevent or mitigate contamination of the base drilling fluid.

[0101] By reducing heat exchange between the cooler fluid descending the tube string and the hotter fluid returning through the annular gap during drilling, the coatings and coating geometries described with reference to Figures 8A and 8B, as well as the methods and systems described with reference to Figures 12 and 14, can further mitigate the negative effects of higher layer temperatures on the tensile strength and other properties of the tube segments of the tube string (e.g., tube segment 220 of drill string 206 in Figure 2).

[0102] The methods, systems, and apparatus described above for enhancing the cooling of drilling fluids can be used individually or in combination with each other.

[0103] In this disclosure, the terms “a, an” or “the” are used to mean one or more unless the context explicitly indicates otherwise. The term “or” is used to mean non-exclusive “or” unless the context explicitly indicates otherwise. The expression “at least one of A and B” is synonymous with “A, B, or A and B.” Furthermore, it should be understood that any expressions or terms used in this disclosure are for illustrative purposes only, and not for limitation, unless otherwise defined. Any chapter headings used are intended to aid in reading the literature and should not be interpreted as limiting. Information related to a chapter heading may relate to that chapter or elsewhere.

[0104] This disclosure includes numerous specific implementation details, which should not be interpreted as limitations on the subject matter or the scope of claims, but rather as descriptions of features that may be specific to a particular implementation. Furthermore, some features described in this disclosure in the context of separate implementations may be implemented in combination or in a single implementation. In contrast, various features described in the context of a single implementation may be implemented in multiple implementations, either individually or in any suitable subcombination. Moreover, while the aforementioned features are described as functioning in several combinations, and may even be initially claimed as such, in some examples, one or more features in a claimed combination may be removed from that combination, and the claimed combination may cover a subcombination or a variation of a subcombination.

[0105] Specific implementations of the subject matter have been described. However, it should be understood that various modifications, substitutions, and changes are possible. While operations may be shown in a particular order in the drawings or claims, this should not be understood as requiring those operations to be performed in that specific order or sequence to achieve the desired result, nor as requiring all operations shown to be performed (some operations may be considered optional). Accordingly, the exemplary implementations described above do not define or limit this disclosure. [Explanation of Symbols]

[0106] 100 Closed-loop geothermal systems 104 Inlet surface well 106 Outlet surface well 108 Underground Zone 110 Lateral well 112 Power Plants 114 Ground surface 116 Loop Circuit 200 well drilling system Well 202, Well No. 1 204 Underground Zone 206 Drill String 208 Drill Bits 210 Bottom Hole Assembly 212 Drilling fluid 214 Rock surface 216 Annular gap 220 Tube Segments 222 Connecting joint 224 Arrow 300 Tricorne Bit 302 Corn 304 Cutting element 306 Additional Cutting Elements 310 gap 802 Main body, steel inner body 804 Inner coating layer, internal coating 806 Outer coating layer, external coating 810 Wall thickness 850 Composite material main body 854 Inner coating layer 1004 points 1006 curve 1008 points 1202 Intermediate Tube String 1204 Internal annular gap 1206 Outer annular gap 1402 Second well 1404 Second drilling fluid flow 1406 Intersection Point 1408 Directional flow

Claims

1. A method for forming a geothermal well system, A step of forming a well in a layer within an underground zone, comprising the step of forming a well having a substantially fluid-impermeable interface between the well and the layer, wherein the step of forming the well is A step of drilling into the layer by using a drill bit at the downhole end of a drill string to break the rock on the rock surface in front of the drill bit, wherein the intrinsic temperature of the rock near the rock surface in front of the drill bit is at least 250 degrees Celsius. A step of crushing the rock at the rock surface with the drill bit, while simultaneously flowing a water-based or oil-based drilling fluid whose temperature at the rock surface is lower than the intrinsic temperature of the rock near the rock surface in front of the drill bit, wherein the difference between the intrinsic temperature of the rock near the rock surface in front of the drill bit and the temperature of the drilling fluid at the rock surface in front of the drill bit is at least 100 degrees Celsius. It has, The method further, The steps include sealing a portion of the well without using a casing to form the interface, The steps include circulating the geothermal working fluid through the well in a closed loop, A method that includes [a certain feature].

2. The drill string comprises a composite material tube, The method according to claim 1.

3. The composite material tube has a normalized thermal resistance of at least 0.002 mKelvin / watt. The method according to claim 2.

4. The composite material tube has a normalized thermal resistance of at least 0.01 mKelvin / watt. The method according to claim 2.

5. The drill bit is a non-contact drill bit. The method according to claim 1.

6. The downhole end of the well is located at a measurement depth of at least 4,000 meters. The method according to claim 1.

7. The difference between the intrinsic temperature of the rock near the rock surface in front of the drill bit and the temperature of the drilling fluid on the rock surface in front of the drill bit is at least 175 degrees Celsius. The method according to claim 1.

8. The intrinsic temperature of the rock near the rock surface in front of the drill bit is at least 350 degrees Celsius, and the difference between the intrinsic temperature of the rock near the rock surface in front of the drill bit and the temperature of the drilling fluid on the rock surface in front of the drill bit is at least 200 degrees Celsius. The method according to claim 1.

9. The intrinsic temperature of the rock near the rock surface in front of the drill bit is at least 500 degrees Celsius, and the difference between the intrinsic temperature of the rock near the rock surface in front of the drill bit and the temperature of the drilling fluid on the rock surface in front of the drill bit is at least 350 degrees Celsius. The method according to claim 1.

10. The portion of the well that is sealed without using a casing is a lateral well, The method according to claim 1.

11. The temperature of the drilling fluid is greater than 25 degrees Celsius when flowing through the drill string at the ground surface located at the uphole end of the well. The method according to claim 1.

12. A system for forming a geothermal well system comprising a well in a layer within an underground zone, wherein the intrinsic temperature of the rock near the rock surface located at the downhole end of the well is at least 250 degrees Celsius, A drill string equipped with a drill bit for breaking the rock on the rock surface, A water-based or oil-based drilling fluid, wherein the system is configured such that the drilling fluid flows simultaneously with the drill bit breaking the rock at the rock surface, and the temperature of the drilling fluid is lower than the intrinsic temperature of the rock near the rock surface in front of the drill bit, and the difference between the intrinsic temperature of the rock near the rock surface in front of the drill bit and the temperature of the drilling fluid at the rock surface in front of the drill bit is at least 100 degrees Celsius. A sealing material configured to seal a well after a portion of the well has been drilled without the use of a casing, such that the interface between the portion of the well drilled without the use of a casing and the layer is substantially impermeable to fluid, and that a geothermal working fluid can flow through the well in a closed loop, A system equipped with these features.

13. The drill string comprises a composite material tube, The system according to claim 12.

14. The composite material tube has a normalized thermal resistance of at least 0.002 mKelvin / watt. The system according to claim 13.

15. The composite material tube has a normalized thermal resistance of at least 0.01 mKelvin / watt. The system according to claim 13.

16. The drill bit is a non-contact drill bit. The system according to claim 12.

17. The downhole end of the well is located at a measurement depth of at least 4,000 meters. The system according to claim 12.

18. The difference between the intrinsic temperature of the rock near the rock surface in front of the drill bit and the temperature of the drilling fluid on the rock surface in front of the drill bit is at least 175 degrees Celsius. The system according to claim 12.

19. The intrinsic temperature of the rock near the rock surface in front of the drill bit is at least 350 degrees Celsius, and the difference between the intrinsic temperature of the rock near the rock surface in front of the drill bit and the temperature of the drilling fluid on the rock surface in front of the drill bit is at least 200 degrees Celsius. The system according to claim 12.

20. The portion of the well that is sealed without using a casing is a lateral well, The system according to claim 12.

21. The intrinsic temperature of the rock near the rock surface in front of the drill bit is at least 500 degrees Celsius, and the difference between the intrinsic temperature of the rock near the rock surface in front of the drill bit and the temperature of the drilling fluid on the rock surface in front of the drill bit is at least 350 degrees Celsius. The system according to claim 12.

22. The temperature of the drilling fluid is greater than 25 degrees Celsius when flowing through the drill string at the ground surface located at the uphole end of the well. The system according to claim 12.

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