WO2025128521A1

WO2025128521A1 - Methods and systems employing geothermal cooling of drilling fluid

Info

Publication number: WO2025128521A1
Application number: PCT/US2024/059315
Authority: WO
Inventors: Ashley Bernard Johnson
Original assignee: Schlumberger Canada Ltd; Services Petroliers Schlumberger SA; Schlumberger Technology BV; Schlumberger Technology Corp
Current assignee: Schlumberger Canada Ltd; Services Petroliers Schlumberger SA; Schlumberger Technology BV; Schlumberger Technology Corp
Priority date: 2023-12-11
Filing date: 2024-12-10
Publication date: 2025-06-19
Anticipated expiration: 2026-06-11

Abstract

Methods and systems are provided for drilling a wellbore in a subterranean formation. The methods and systems circulate drilling fluid into and through the wellbore during the drilling, and circulate drilling fluid that exits the wellbore during the drilling into and through at least one secondary wellbore that employs geothermal cooling to cool the drilling fluid during the drilling.

Description

METHODS AND SYSTEMS EMPLOYING GEOTHERMAL COOLING OF DRILLING

FLUID

CROSS-REFERENCE TO RELATED APPLICATION(S)

[0001] The present disclosure claims priority from U.S. Provisional Appl. No. 63/608,390, filed on December 11, 2023, herein incorporated by reference in its entirety.

FIELD

[0002] The present disclosure relates generally to drilling operations, and in particular, to methods and systems that may be used for cooling drilling fluid.

BACKGROUND

[0003] During a typical well drilling operation, drilling fluid, which is commonly referred to as drilling mud, is circulated into and out of a wellbore. The drilling fluid can serve many useful purposes during the drilling operation, such as, for example, removing drill cuttings from the wellbore, controlling formation pressures and wellbore stability during drilling, sealing permeable formations, transmitting hydraulic energy to the drilling tools and bit, and cooling, lubricating, and supporting the drill bit and other parts of the bottom hole assembly during the drilling operations.

[0004] In some drilling applications, the formation temperature at the drill bit can be high, which can result in elevated temperatures in the circulating drilling fluid. For example, a geothermal well can be drilled to intersect a target geothermal reservoir to capture geothermal energy (heat) which can be used for a variety of applications, such as building heating or cooling and/or electrical power generation. Therefore, many geothermal wells are, by design, drilled into formations that have significantly elevated temperatures. For example, in some geothermal drilling applications, the temperature of the targeted formations may be on the order of approximately 500-600°F, or even greater, which can lead to conditions wherein the temperature of the returned drilling fluid is above 200-225° F. Such elevated drilling fluid temperatures can have significant detrimental effects on many of the various components of a typical drilling fluid handling system, including circulation pumps and associated seals and valves and the like.

[0005] In order to avoid these detrimental effects, it is common for geothermal well drilling operations to employ a mud handling system that includes an active cooling system (typically referred to as a mud cooler) at the surface to reduce the temperature of the drilling fluid that is returned to the surface when drilling the wellbore for the geothermal well. The active cooling system is a large chilling system that consumes a significant amount of electric power. It is expected that the consumed electrical power is more than double the thermal power of the geothermal well. The consumed electrical power can add significant costs to the drilling operations of the geothermal well and possibly negatively impact the economic viability of the geothermal well.

SUMMARY

[0006] Methods and systems are provided for drilling a wellbore in a subterranean formation. The methods and systems circulate drilling fluid into and through the wellbore during the drilling, and circulate drilling fluid that exits the wellbore during the drilling into and through at least one secondary wellbore that employs geothermal cooling to cool the drilling fluid during the drilling.

[0007] In embodiments, the at least one secondary wellbore can be a shallow offset well or the top section of an existing well.

[0008] In embodiments, the at least one secondary wellbore can include tubing that extends downward through the secondary wellbore. The tubing can be configured to carry the drilling fluid downward where it exits from the bottom end of the tubing and returns upward to the surface in an annulus between the exterior surface of the tubing and a wellbore wall. The ground that surrounds the secondary wellbore can provide for the geothermal cooling that cools the drilling fluid as it circulates into and through the secondary wellbore.

[0009] In embodiments, the tubing of the secondary wellbore can be selected from: conventional steel tubing, insulated tubing, or vacuum insulated tubing. [0010] In embodiments, the at least one secondary wellbore can include a plurality of series- coupled secondary wellbores, or a plurality of parallel-coupled secondary wellbores.

[0011] In embodiments, the drilling fluid that exits the wellbore can be supplied to processing equipment that separates drill cuttings from the drilling fluid for supply to the at least one secondary wellbore.

[0012] In embodiments, the drilling fluid that exits the at least one secondary wellbore can be supplied to processing equipment that separates drill cuttings from the drilling fluid.

[0013] In embodiments, cooled drilling fluid can be stored downstream of the at least one secondary wellbore for input to a pump for circulation into and through the wellbore during the drilling.

[0014] In embodiments, the wellbore can be part of a geothermal wellbore that follows a trajectory that intersects a target geothermal formation to capture geothermal energy (heat).

[0015] This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

BRIEF DESCRIPTION OF THE DRAWINGS

[0016] The subject disclosure is further described in the detailed description which follows, in reference to the noted plurality of drawings by way of non-limiting examples of the subject disclosure, in which like reference numerals represent similar parts throughout the several views of the drawings, and wherein:

[0017] FIG. 1 is a schematic diagram of a drilling system that can embody aspects of the present disclosure;

[0018] FIG. 2 is a schematic diagram of part of a drilling system and a drilling fluid handling system that can embody aspects of the present disclosure; [0019] FIG. 3 is a schematic diagram of part of a drilling system and a drilling fluid handling system that can embody aspects of the present disclosure;

[0020] FIG. 4 is a schematic diagram of part of a drilling system and a drilling fluid handling system that can embody aspects of the present disclosure; and

[0021] FIGS. 5 to 8 depicts results of a model that was built to calculate the temperature profile in an example secondary wellbore of a drilling fluid handling system as described herein; FIG. 5 shows the temperature profile along the flow path of the secondary wellbore as predicted by the model for the case of conventional steel drill pipe; FIG. 6 shows the temperature profile along the flow path of the secondary wellbore as predicted by the model for the case of insulated drill pipe; FIG. 7 shows the temperature profile along the flow path of the secondary wellbore as predicted by the model for the case of vacuum insulated drill pipe; and FIG. 8 shows the temperature profile along the flow path of the secondary wellbore as predicted by the model for the case of vacuum insulated drill pipe at a reduced flow rate of 25 gallons per minute (gpm).

DETAILED DESCRIPTION

[0022] The particulars shown herein are by way of example and for purposes of illustrative discussion of the embodiments of the subject disclosure only and are presented in the cause of providing what is believed to be the most useful and readily understood description of the principles and conceptual aspects of the subject disclosure. In this regard, no attempt is made to show structural details in more detail than is necessary for the fundamental understanding of the subject disclosure, the description taken with the drawings making apparent to those skilled in the art how the several forms of the subject disclosure may be embodied in practice.

Furthermore, like reference numbers and designations in the various drawings indicate like elements.

[0023] It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for the purpose of simplicity and clarity and will not in itself dictate a relationship between the various embodiments and/or configurations discussed.

[0024] As used herein, the terms connect, connection, connected, in connection with, and connecting may be used to mean in direct connection with or in connection with via one or more elements. Similarly, the terms couple, coupling, coupled, coupled together, and coupled with may be used to mean directly coupled together or coupled together via one or more elements. Terms such as up, down, top and bottom and other like terms indicating relative positions to a given point or element may be utilized to more clearly describe some elements. Commonly, these terms relate to a reference point such as the surface from which drilling operations are initiated.

[0025] FIG. 1 is a schematic illustration of a drilling system, generally denoted by the numeral 100. It should be noted that while FIG. 1 generally depicts a land-based drilling system, those skilled in the art will readily recognize that the principles described herein are equally applicable to subsea drilling operations that employ floating or sea-based platforms and rigs, without departing from the scope of the disclosure.

[0026] By way of example, FIG. 1 shows a drilling system 100 for drilling into the earth to form a wellbore 114 in an earth formation 112. The drilling system 100 includes a drill rig 116 located at the surface 117 and operated to turn a drilling tool assembly which extends downward from the surface 117 into the wellbore 114. The drilling tool assembly includes a drill string 118 operably coupled to a bottomhole assembly (BHA) 120 with a drill bit 122.

[0027] The drill string 118 can include several sections of drill pipe connected end-to-end through tool j oints as is well known. The drill string 118 can transmit rotational power from the drill rig 116 to the BHA 120 and the drill 122. In some embodiments, the drill string 118 may further include additional components such as subs, pup joints, etc. The drill pipe provides a fluid passageway through which drilling fluid is pumped from the surface 117. The drilling fluid discharges through nozzles, jets, or other orifices at or near the drill bit 122 for the purposes of cooling the drill bit 122 and cutting structures thereon, for lifting cuttings out of the wellbore 114 as it is being drilled, for controlling influx of fluids in the well, for maintaining the wellbore integrity, and for other purposes. [0028] An example BHA 120 may include additional or other components (e.g., coupled between/to the drill string 118 and the bit 122). Examples of additional BHA components include a drill collar, stabilizers, measurement-while-drilling (MWD) tools, logging-whiledrilling (LWD) tools, downhole motors, underreamers, section mills, hydraulic disconnects, jars, vibration or damping tools, other components, or combinations of the foregoing. The BHA 120 may further include a directional tool such as a bent housing motor or a rotary steerable system (RSS). The directional tool may include directional drilling tools that change the direction of the drill bit 122, and thereby the trajectory of the wellbore. In some cases, at least a portion of the directional tool may maintain a geostationary position relative to an absolute reference frame, such as gravity, magnetic north, or true north. Using measurements obtained with the geostationary position, the directional tool may locate the drill bit 122, change the course of the bit drill 122 and direct the drill bit 122 on a controlled trajectory. For instance, although the BHA 120 is shown as drilling a vertical portion of the wellbore 114, the BHA 120 (including the directional tool) may instead drill directional or deviated well portions as is well known.

[0029] In some embodiments, the BHA 120 may include a downhole motor to power downhole systems and/or provide rotational energy for downhole components (e.g., rotate the drill bit 122, drive the directional tool, etc.). The downhole motor may be any type of downhole motor, including a positive displacement pump (such as a progressive cavity motor) or a turbine. In some embodiments, a downhole motor may be powered by the drilling fluid flowing through the drill string 118. In other words, the drilling fluid pumped downhole from the surface 117 may provide the energy to rotate the downhole motor. The downhole motor may operate with an optimal pressure differential or pressure differential range. The optimal pressure differential may be the pressure differential at which the downhole motor may not stall, burn out, overspin, or otherwise be damaged. In some cases, the downhole motor may rotate the drill bit 122 such that the drill string 118 may not be rotated at the surface 117, or may rotate at a different rate (e.g., slower) than the rotation of the drill bit 122.

[0030] The drill bit 122 may be any type of bit suitable for degrading downhole materials such as earth formation 112. Example types of drill bits used for drilling earth formations are fixed- cutter or drag bits, roller cone bits, and combinations thereof. [0031] The drill rig 116 supports traveling block 124, which suspends a swivel 126 that is connected to kelly drive 127A. The kelly drive 127A cooperates with a rotary table 127B to rotate the drill string 118 and to lower the drill string 118 through the wellhead 128. In other embodiments, a top drive can be used in place of the swivel 126, the kelly drive 127A and the rotating function of the rotary table 127B. Drilling fluid is pumped by pump 130 through flow line 132, gooseneck 134, the swivel 126 and kelly 127A (or top drive), and down through the drill string 118 at high pressures and volumes to emerge through nozzles or jets or orifices at or near the drill bit 122. The drilling fluid then travels back up the wellbore 114 via the annulus formed between the exterior of the drill string 118 and the wellbore wall, through a blowout preventer 136, and into a tank 138 and/or pit 140 on the surface 117. Shale shakers (not shown) can be used to remove large cuttings before the drilling fluid is returned to the tank 138 and/or pit 140. At the surface 117, the drilling fluid can be cleaned and then circulated again by the pump 130. The drilling fluid can be used to cool the drill bit 122, to carry cuttings from the base of the wellbore 114 to the surface 117, and to balance the hydrostatic pressure with respect to the formation 112.

[0032] The drilling system 100 can also include additional or other drilling components and accessories, such as special valves (e.g., kelly cocks and safety valves).

[0033] In accordance with the present disclosure, a drilling system, such as the drilling system 100 of FIG. 1, can be adapted to include one or more secondary wellbores configured to employ geothermal cooling to cool drilling fluid that returns to the surface during drilling operations. In embodiments, the wellbore being drilled can be a geothermal wellbore that follows a trajectory that intersects a target geothermal formation to capture geothermal energy (heat) which can be used for a variety of applications, such as building heating or cooling and/or electrical power generation. In some geothermal drilling applications, the temperature of the target geothermal formation may be on the order of approximately 500-600°F, or even greater, which can lead to conditions wherein the temperature of the returned drilling fluid is above 200-225° F.

[0034] FIG. 2 illustrates an example system 200 that includes a secondary wellbore 251 that is configured to employ geothermal cooling to cool drilling fluid that returns to the surface 217 during the drilling of a wellbore 214 (such as a deep geothermal wellbore). In embodiments, the wellbore 214 can be deep geothermal wellbore that follows a trajectory that intersects a target geothermal formation to capture geothermal energy (heat) which can be used for a variety of applications, such as building heating or cooling and/or electrical power generation.

[0035] In general, several elements of the system 200 of FIG. 2 are substantially similar to corresponding elements of the previously described system 100 of FIG. 1 above. Accordingly, and where appropriate, the reference numbers used in describing the various elements of the system 200 shown in FIG. 2 substantially correspond to the reference numbers used in describing related elements of the system 100 illustrated in FIG. 1, except that the leading numeral in each figure has been changed from a “1” to a “2.” For example, surface 117 shown in FIG. 1 corresponds to surface 217 of FIG. 2, the wellhead 128 of FIG. 1 corresponds to wellhead 228 of FIG. 2, the BOP 136 of FIG. 1 corresponds to BOP 236 of FIG. 2, and so on.

[0036] As shown in FIG. 2, a blow-out preventer (BOP) 236 is positioned on wellhead 228 as drilling operations are being performed on wellbore 214. In operation, drilling fluid mixed with drill cuttings flows out of the wellbore 214 and exits the BOP 236 through connector 253, and thereafter flows through the flow line 255. The drilling fluid that flows through the flow line 255 is labeled “DF (hot)” in FIG. 2. This drilling fluid is supplied to drilling fluid processing equipment 256 at the surface 217, which separates drill cuttings from the drilling fluid.

Equipment 256 can include one or more vibratory separators (e.g., shale shakers) and/or one or more hydrocyclone and/or centrifuge apparatus. The drilling fluid (with drill cuttings removed) flows from equipment 256 to the wellhead 257 of the secondary wellbore 251. This drilling fluid circulates in the secondary wellbore 251 which provides for geothermal cooling that cools the hot drilling fluid. Specifically, the secondary wellbore 251 includes tubing 258 that extends from the wellhead 257 downward through the secondary wellbore. The tubing 258 carries the hot drilling fluid downward where it exits from the bottom end of the tubing 258 and returns upward to the surface in the annulus between the exterior surface of the tubing 258 and the wellbore wall as shown. The ground that surrounds the secondary wellbore 251 provides for geothermal cooling that cools the drilling fluid as it circulates into and through the secondary wellbore 251. The secondary wellbore 251 can be a shallow offset well or the top section of an existing well. The tubing 258 of the secondary wellbore can be standard steel tubing, insulated tubing, vacuum insulated tubing or other tubing that provides for circulation of the drilling fluid into and through the secondary wellbore 251. As used herein, insulate tubing refers to a type of tubing or pipe designed with one or more layers of thermal insulating material disposed on the inside diameter surface and/or the outside diameter surface of the tubing. The thermal insulating material reduces heat transfer between fluid flowing through the tubing and the surrounding environment. As used herein, vacuum insulated tubing refers to a type of tubing or pipe designed with a vacuum space between two concentric walls. The vacuum space reduces heat transfer between fluid flowing through the tubing and the surrounding environment.

[0037] The cooled drilling fluid that results from the circulation in the secondary wellbore 251 exits the wellhead 257 and flows through flow line 259 for supply to drilling fluid storage 263 at the surface 217. The drilling fluid storage 263 can be one or more tanks and/or pits on the surface 217. Optionally, the drilling fluid storage 263 can employ passive cooling to further cool the drilling fluid.

[0038] The cooled drilling fluid stored in the drilling fluid storage 263 is supplied to pump 230 via flow line 267 for circulation within the wellbore 214 during the drilling operations. The drilling fluid pumped into the wellbore 214 during the drilling operations is labeled “DF (cold)” in FIG. 2 More specifically, the cold drilling fluid is pumped by pump 230 through flow line 232, swivel 226, kelly 227A (or top drive), and down through the drill string 218 at high pressures and volumes to emerge through nozzles or jets or orifices at or near the drill bit (not shown). The drilling fluid then travels back up the wellbore 214 via the annulus formed between the exterior of the drill string 218 and the wellbore wall, through the blowout preventer 236 for circulation through the secondary wellbore 251 as described above. The drilling fluid can be used to cool the drill bit, to carry cuttings from the base of the wellbore 214 to the surface 217, and to balance the hydrostatic pressure with respect to the formation being drilled.

[0039] In other embodiments, the system of FIG. 2 can be adapted to employ a number of series- coupled secondary wellbores for geothermal cooling of drilling fluid. For example, FIG. 3 shows the layout for a system that employs three series-coupled secondary wellbores for geothermal cooling of drilling fluid. The number and geometry of the series-coupled secondary wellbores can be configured based on the expected temperature of the drilling fluid during the drilling operation of the wellbore being drilled and the geothermal cooling characteristics of the secondary wellbores.

[0040] In other embodiments, the system of FIG. 2 can be adapted to employ a number of parallel-coupled secondary wellbores for geothermal cooling of drilling fluid. For example, FIG.

4 shows the layout for a system that employs four parallel-coupled secondary wellbores for geothermal cooling of drilling fluid. The number and geometry of parallel-coupled secondary wellbores can be configured based on the expected temperature of the drilling fluid during the drilling operation of the wellbore being drilled and the geothermal cooling characteristics of the secondary wellbores.

[0041] In the embodiments described above, the drilling fluid processing equipment is disposed upstream of the secondary wellbore(s) that cools the hot drilling fluid. In other embodiments, the drilling fluid processing equipment can be disposed downstream of the secondary wellbore(s) that cools the hot drilling fluid. This downstream configuration can be used to avoid fluid evaporation at the drilling fluid processing equipment.

[0042] In order to evaluate the drilling fluid cooling afforded by the systems described herein, a model was built to simulate the temperature of drilling fluid in the secondary wellbore as detailed below in Table 1. The model assumes turbulent flow in the tubing and the annulus of the secondary wellbore. The model also assumes radial heat conduction through the formation and a steady state with a far field temperature 5 meters from the secondary wellbore.

Table 1: Parameters used for simulation.

[0043] The model was configured to simulate four different scenarios for the tubing of the secondary wellbore as outlined below in Table 2, including: conventional drill pipe with a flow of 50 gpm and pump power at 12kW, insulated drill pipe (0.25 in thick) with pump power at 12kW, vacuum insulated drill pipe with pump power at 12kW, and vacuum insulated drill pipe with a reduced flow of 25 gpm and reduced pump power at 3kW. The conditions are shown in Table 2 with an estimate of the drilling fluid temperature at the discharge of the drilled wellbore and the equivalent thermal power extracted from the drilling fluid. The estimated pump power assumes a turbulent flow of water in the wellbore. The modeled temperature distributions are shown in FIGS. 5 to 8.

Table 2: Drill pipe specification with modelled fluid temperatures.

[0044] FIG. 5 shows the temperature profile along the flow path of the secondary wellbore as predicted by the model for the case of conventional steel drill pipe.

[0045] FIG. 6 shows the temperature profile along the flow path of the secondary wellbore as predicted by the model for the case of insulated drill pipe.

[0046] FIG. 7 shows the temperature profile along the flow path of the secondary wellbore as predicted by the model for the case of vacuum insulated drill pipe. [0047] FIG. 8 shows the temperature profile along the flow path of the secondary wellbore as predicted by the model for the case of vacuum insulated drill pipe but a reduced flow rate of 25 gallons per minute (gpm).

[0048] Although the system of circulating drilling fluid through the secondary wellbore will not generate a huge temperature reduction in the drill fluid, the benefits can be considerable in terms of reduction in consumed electrical power and reduced carbon footprint and the thermal power removed from the drilling fluid.

[0049] It is evident that by changing the tubing of the secondary wellbore, one can obtain a significant increase in the system performance. Also note that reducing the flow rate of the circulating drilling fluid in the secondary wellbore can significantly increase the cooling of the drilling fluid by the secondary wellbore.

[0050] Furthermore, the circulating depth can be set to match the inlet drilling fluid temperature. If the fluid emerges from the drill pipe below the formation temperature the system efficiency will be reduced.

[0051] Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. § 112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.

Claims

WHAT IS CLAIMED IS:

1. A method for drilling a wellbore in a subterranean formation, comprising: circulating drilling fluid into and through the wellbore during the drilling, and circulating drilling fluid that exits the wellbore during the drilling into and through at least one secondary wellbore that employs geothermal cooling to cool the drilling fluid during the drilling.

2. The method of claim 1, wherein: the at least one secondary wellbore comprises a shallow offset well or the top section of an existing well.

3. The method of claim 1, wherein: the at least one secondary wellbore comprises tubing that extends downward through the secondary wellbore, wherein the tubing carries the drilling fluid downward where it exits from the bottom end of the tubing and returns upward to the surface in an annulus between the exterior surface of the tubing and a wellbore wall, and wherein ground that surrounds the secondary wellbore provides for the geothermal cooling that cools the drilling fluid as it circulates into and through the secondary wellbore.

4. The method of claim 3, wherein: the tubing of the secondary wellbore is selected from: conventional steel tubing, insulated tubing, or vacuum insulated tubing.

5. The method of claim 1, wherein: the least one secondary wellbore comprises a plurality of series-coupled secondary wellbores; or the least one secondary wellbore comprises a plurality of parallel-coupled secondary wellbores.

6. The method of claim 1, further comprising: supplying the drilling fluid that exits the wellbore to processing equipment that separates drill cuttings from the drilling fluid for supply to the at least one secondary wellbore.

7. The method of claim 1, further comprising: supplying the drilling fluid that exits the at least one secondary wellbore to processing equipment that separates drill cuttings from the drilling fluid.

8. The method of claim 1, further comprising: storing cooled drilling fluid downstream of the at least one secondary wellbore for input to a pump for circulation into and through the wellbore during the drilling.

9. The method of claim 1, wherein: the wellbore is part of a geothermal wellbore that follows a trajectory that intersects a target geothermal formation to capture geothermal energy (heat).

10. A system for drilling a wellbore in a subterranean formation, comprising: a drilling fluid handling system configured to i) circulate drilling fluid into and through the wellbore during the drilling and ii) circulate drilling fluid that exits the wellbore during the drilling into and through at least one secondary wellbore that employs geothermal cooling to cool the drilling fluid during the drilling.

11. The system of claim 10, wherein: the at least one secondary wellbore comprises a shallow offset well or the top section of an existing well.

12. The system of claim 10, wherein: the at least one secondary wellbore comprises tubing that extends downward through the secondary wellbore, wherein the tubing carries the drilling fluid downward where it exits from the bottom end of the tubing and returns upward to the surface in an annulus between the exterior surface of the tubing and a wellbore wall; and wherein ground that surrounds the secondary wellbore provides for the geothermal cooling that cools the drilling fluid as it circulates into and through the secondary wellbore.

13. The system of claim 12, wherein: the tubing of the secondary wellbore is selected from: conventional steel tubing, insulated tubing, or vacuum insulated tubing.

14. The system of claim 10, wherein: the least one secondary wellbore comprises a plurality of series-coupled secondary wellbores; or the least one secondary wellbore comprises a plurality of parallel-coupled secondary wellbores.

15. The system of claim 10, further comprising: drilling fluid processing equipment configured to process drilling fluid that exits the wellbore to separate drill cuttings from the drilling fluid for supply to the at least one secondary wellbore.

16. The system of claim 10, further comprising: drilling fluid processing equipment configured to process drilling fluid that exits the at least one secondary wellbore to separate drill cuttings from the drilling fluid.

17. The system of claim 10, further comprising: drilling fluid storage configured to store cooled drilling fluid downstream of the at least one secondary wellbore.

18. The system of claim 17, wherein: the drilling fluid storage comprises at least one tank and/or at least one pit.

19. The system of claim 17, further comprising: a pump operably coupled to the drilling fluid storage for circulation of cooled drilling fluid into and through the wellbore during the drilling.

20. The system of claim 1, wherein: the wellbore is part of a geothermal wellbore that follows a trajectory that intersects a target geothermal formation to capture geothermal energy (heat).