Protecting drilling fluid

Abstract

A tripping operation is performed during the drilling of a wellbore in a subterranean formation. The tripping operation includes displacing a drilling fluid from a drilling string disposed within the wellbore by flowing an alternative fluid through the drilling string. The drilling fluid is the same type of fluid used when drilling the wellbore. The tripping operation includes displacing the drilling fluid from the wellbore to a terranean surface by flowing the aqueous fluid into the wellbore, and withdrawing the drilling string from the wellbore.

Description

PROTECTING DRILLING FLUIDTECHNICAL FIELD

[0001] This disclosure relates to drilling subterranean wells, and in particular, drilling wells in how subterranean zones.BACKGROUND

[0002] The high temperatures of some subterranean zones make constructing the wells in those zones difficult. The tools used to drill the wellbores are fortified to withstand exposure to the high temperatures over long timeframes. Even then, the tools must be cooled with the drilling fluid as the wellbore is being drilled. The drilling fluid, itself, is even affected by the high temperatures and can degrade if exposed to too high of a temperature. The temperature of the drilling fluid can be managed by circulating the fluid, for example, as is done during drilling. However, when the drilling and fluid circulation stop, such during tripping the drilling string into / out of the wellbore, the drilling fluid remaining in the wellbore can continue to heat up and be damaged.SUMMARY

[0003] This disclosure describes technologies relating to tripping operations during drilling of wellbores in subterranean formations.

[0004] An aspect encompasses a method where a tripping operation is performed during the drilling of a wellbore in a subterranean formation. The tripping operation includes displacing a drilling fluid from a drilling string disposed within the wellbore by flowing an alternative fluid through the drilling string. The drilling fluid is the same type of fluid used when drilling the wellbore. The tripping operation includes displacing the drilling fluid from the wellbore to a terranean surface by flowing the aqueous fluid into the wellbore, and withdrawing the drilling string from the wellbore.

[0005] An aspect encompasses a method where a fluid is flowed through a drilling string to an end of the drilling string disposed in a wellbore being formed in a subterranean formation. After flowing the fluid to the end of the drilling string, a drilling fluid disposed within the wellbore is displaced with the first mentioned fluid. The drilling fluid displaced from the wellbore is received at a surface location outside of the wellbore, and the drilling string is removed from the wellbore.

[0006] The aspects above can include one, some or none of the following features. In certain instances, after withdrawing the drilling string, a second drilling string is run into thewellbore. The drilling fluid can be an oil-based drilling fluid, and the first mentioned fluid can be aqueous. In certain instances, displacing the drilling fluid from the wellbore and withdrawing the drilling string from the wellbore occur simultaneously. Sometimes, prior to displacing the drilling fluid from the drilling string, a spacer fluid is flowed into the drilling string. Sometimes, after displacing the drilling fluid from the wellbore a plug is placed within the wellbore and a portion of the wellbore is sealed by the plug to prevent the alternative fluid from escaping the portion of the wellbore. The methods can be applied where a subterranean temperature of the subterranean formation exceeds 200 degrees Celsius (°C), and the drilling fluid is displaced from the wellbore before a temperature of the drilling fluid exceeds 150 °C. The alternative fluid can configured to withstand the subterranean temperature of the subterranean formation without degrading.

[0007] The details of one or more implementations of the subject matter of this disclosure are set forth in the accompanying drawings and the description. Other features, aspects, and advantages of the subject matter will become apparent from the description, the drawings, and the claims.DESCRIPTION OF DRAWINGS

[0008] FIG. 1A is a schematic side cross-sectional view of an example geothermal system.

[0009] FIG. IB is a schematic side cross-sectional view of another example geothermal system.

[0010] FIG. 2 is a detailed view of an example bottom hole assembly of a drilling string which can be used to drill a geothermal well, including those in the systems of FIGS. 1A and IB.

[0011] FIG. 3A is a progression of schematics showing example stages of a tripping operation while drilling a wellbore.

[0012] FIG. 3B is a progression of schematics showing example stages of a tripping operation while drilling a wellbore.

[0013] FIG. 3C is a progression of schematics showing example stages of a tripping operation while drilling a wellbore.

[0014] FIG. 3D is a schematic showing a multilateral geothermal well being drilled, in which drilling fluid has been replaced with a different fluid in various laterals that have already been drilled.

[0015] FIG. 4A is a flow chart of an example method for tripping a drilling string while drilling a wellbore.

[0016] FIG. 4B is a flow chart of an example method for tripping a drilling string while drilling a wellbore.DETAILED DESCRIPTION

[0017] In drilling a geothermal well, thermal control techniques can be selectively implemented to mitigate heat transfer from the Earth into the drilling fluid. The thermal control techniques can help control the temperature of the drilling fluid, which is used to cool the tools of the bottom hole assembly and to shock cool the rock face being drilled, improving the rate of penetration. Moreover, the thermal control techniques can be implemented to maintain the integrity of the drilling fluid during periods of inactivity, such as when drilling has stopped and / or when tripping the drilling string in and / or out of the wellbore.

[0018] The subject matter described in this disclosure can be implemented in particular implementations, so as to realize one or more of the following advantages. The drilling fluid residing within a wellbore can be replaced by a different fluid while tripping operations occur, such that the drilling fluid does not remain downhole and continue to get heated by the subterranean formation. By replacing the drilling fluid with a stabler fluid within the wellbore during tripping operations, an operating temperature of the drilling fluid can remain below a temperature degradation threshold throughout drilling operations and can remain safe from temperature degradation. This allows the drilling fluid to be continuously recycled to perform drilling operations without needing to replace degraded drilling fluid. Thus, operating costs associated with drilling fluid replacement can be avoided. Further, downtime (which negatively lengthens drilling time) associated with drilling fluid replacement can be avoided. Additionally, maintenance time and costs associated with repairing / replacing instrumentation and / or other components of the drilling string can be avoided, as the lower operating temperature of the drilling fluid throughout drilling operations can protect against the negative effects of high temperature.

[0019] FIG. 1A depicts a schematic, side cross-sectional view of an example closed loop geothermal system 100. The closed loop geothermal wellbore system can be, for example, a system such as that developed by Eavor Technologies Inc. of Calgary, Alberta, which includes a network of sealed lateral or deviated wellbores that exchange heat with the subterranean zone. The system 100 includes a geothermal well 102 drilled into the Earththrough a geothermal subterranean zone of interest 104. In some implementations, the subterranean zone is a dry, impermeable (matrix permeability of 0.1 millidarcy or less) formation, portion of formation or multiple formations having little to no naturally occurring recoverable fluids. In some implementations, the subterranean zone is in a crystalline basement formation. In some implementations, the rock of the subterranean zone is in a granitic formation (e.g., granite). In the implementation shown in FIG. 1A, the well 102 includes an inlet surface wellbore 120 and an outlet surface wellbore 130 in close proximity, each extending between the terranean surface and the subterranean zone 104. The inlet surface wellbore 120 and outlet surface wellbore 130 are connected within the subterranean zone 104 by one or more connecting wellbores 140. In some implementations, connecting wellbores 140 define a multilateral pattern of wellbores, including a plurality of pairs of lateral wellbores 150, a subset of which are kicked off from the inlet wellbore 120 and a subset of which are kicked off from the outlet wellbore 130. The pairs of lateral wellbores 150 each intersect at a respective junction 154 at or near their respective toes. The inlet wellbore 120, outlet wellbore 130, and connecting wellbores 140 define a closed loop.

[0020] The inlet wellbore 120 and the outlet wellbore 130 can be drilled from the same drilling pad and / or reside on the same well site. In some implementations, the wellbores 120, 130 are drilled within 10, 25, 50 or 100 meters of one another. In some implementations, the inlet surface wellbore 120 and the outlet surface wellbore 130 can be separated by a longer distance. For example, FIG. IB, discussed in more detail below, shows a configuration in which the surface wellbores 120, 130 and the connecting wellbores 140 define a U-shape configuration. In some implementations, the inlet surface wellbore 120 and the outlet surface wellbore 130, when the geothermal well 102 is configured as a U-shape, are drilled 3,000 meters or more apart.

[0021] In some implementations, as shown in FIG. 1A, the inlet surface wellbore 120 and outlet surface wellbore 130 are vertical wellbores, drilled substantially straight (i.e., without the use of directional drilling methods or equipment). In some implementations, one orboth ofthe surface wellbores are other than vertical (e.g., slanted) and / or may be drilled with the use of directional drilling techniques. The connecting wellbores 140 can be drilled using directional drilling techniques through the surface wellbores 120, 130, and can include a curve in their trajectory beginning at a kickoff 148 at surface wellbores 120, 130. Although shown as slanted downward in FIG. 1A, in some implementations, some or all of the connecting wellbores are horizontal. In some implementations, the connecting wellbores 140 follow the geological dip of the formation in the subterranean zone. In some implementations, lateralwellbores 150 are anywhere from 2,000 meters to 10,000 meters or more in length and from 1,000 meters to 8,000 meters or more in depth from the surface.

[0022] FIG. 1A shows each pair of lateral wellbores 150 parallel to one another extending in the same direction (azimuth) from their respective surface wellbore 120, 130. The lateral wellbores 150 extending from the inlet surface wellbore 120 are shown above the lateral wellbores 150 extending from the outlet surface wellbore 130. In some implementations, the upper lateral wellbores 150 are directly above their (and are, in some instances, directly above a respective one of the lower lateral wellbores 150. In FIG. 1A the upper lateral wellbores 150 each turn to intersect its adjacent lower lateral wellbore 150 pair at the junction 154 to connect the surface wellbores 120, 130. In some implementations, one or more of the lower lateral wellbores 150 could intersect the upper lateral wellbores 150. Regardless, the configuration of connecting wellbores 140, one set atop the other defines a stacked wellbore pattern, with one sub-pattern of wellbores above and one sub-pattern of wellbores below. In some implementations, one or more additional sets of stacked patterns can be drilled from the surface wellbores 120, 130 at different depths (i.e., with different kickoffs 148). The lower lateral wellbores 150 can extend past and below the junction 154 to define a sump 152. The sump 152 provides a location for debris to accumulate outside of the flow path through the wellbores . In some implementations, one or more of the upper lateral wellbores 150 can extend past the junction to define the sump 152.

[0023] FIG. IB depicts an example geothermal well system 100’ having lateral wellbores 150 extending, respectively, from the inlet and outlet surface wellbores 120, 130 toward one another. The pairs of lateral wellbores 150, once intersected, together with the inlet and outlet wellbores 120, 130, define a generally U-shape. The configuration of connecting wellbores 140 defines a pattern of wellbores, in some implementations, in the same plane. In some implementations, one or more additional patterns of connecting wellbores can be drilled between the surface wellbores 120, 130 at different depths (i.e., with different kickoffs 148).

[0024] Referring to FIGS. 1A and IB, collectively, in some implementations, the surface wellbores 120, 130 are cased (at least partially or entirely), and the connecting wellbores 140, including the junctures at the kickoffs 148 are open hole (i.e., without casing or liner or a junction liner). In some implementations, the connecting wellbores 140 can be at least partially lined (e.g., include a liner or casing in those portions where the subterranean zone 104 is fractured, susceptible to collapse, unconsolidated or otherwise needing a liner). The connecting wellbores 140, including the junctures to the inlet and outlet surface wellbores 120, 130 are sealed (entirely or substantially) with a sealant against exchange of fluids with thesurrounding subterranean zone 104. The sealant is designed such that all or substantially all of the working fluid circulated through the well 102 during operation is recovered to the surface, and no or little naturally occurring fluids from the subterranean zone 104 are recovered. In other words, the resulting well 102 is closed loop. In some implementations, the sealant can be applied to the wellbores during drilling the connecting wellbores 140, e.g., included in the drilling fluid and / or supplied in fluid slugs distinct from the drilling fluid. Alternatively or additionally, the sealant is applied after drilling and / or during operation of the well. In some implementations, the sealant is included in the heat transfer working fluid and / or supplied in fluid slugs, distinct from the heat transfer working fluid.

[0025] Referring back to FIG. 1A, the system 100 includes a facility 110 disposed between inlet surface wellbore 120 and outlet surface wellbore 130. Well 102 can be sealed, and a working fluid can be added to the closed loop and circulated in the system such that the working fluid absorbs heat from subterranean zone 104. In some implementations, facility 110 includes valves and pumps for controlling the flow of the working fluid through the well 102, as well as a heat exchanger for extracting the heat from the working fluid and conveying it into a related process, such as a Rankine cycle (e.g., Organic Rankine Cycle) or other heat cycle that generates electricity, a steam generation process for industrial, agricultural or residential use, or another process. In some implementations, instead of, or in addition to a heat exchanger, facility 110 directly uses the heated working fluid, such as by passing it through an expander (e.g., a turbine) that drives a electric generator or directly using the heat of the working fluid in an industrial, agricultural or residential process. In some implementations, facility 110 is disposed at or near the Earth’s surface. In some implementations, facility 110 is disposed partially or fully within a subsurface location. The facility 110 need not be housed in one location and, for example as shown in FIG. IB, can be split between one or more discrete locations (shown as facility 110a, 110b) connected by piping.

[0026] The geothermal wells 100, 100’ can be constructed by drilling and, if cased, casing the inlet wellbore 120 and outlet wellbore 130. The connecting wellbores 140 are drilled as intersecting lateral wellbores 150 from the inlet wellbore 120 and the outlet wellbore 130. In particular, a connecting wellbore 140 is constructed as a lateral wellbore 150 beginning at the sidewall of the inlet wellbore 120, i.e., kicking off from the inlet wellbore 120, and a lateral wellbore 150 beginning at the sidewall of the outlet wellbore 130, i.e., kicking off from the outlet wellbore. The lateral wellbores 150 are drilled to intersect at a junction 154 to define a connecting wellbore 140. Additional connecting wellbores 140 can be drilled as lateral wellbores 150 kicking off from the inlet wellbore 120, outlet wellbore 130 and / or other of theconnecting wellbores 140 (or lateral wellbore 150 that may become a connecting wellbore 140). The lateral wellbores 150 are drilled using directional drilling techniques with a drilling string extending from the terranean surface through the inlet wellbore 120 and outlet wellbore 130, respectively. In some implementations, a whipstock is used to kick off the lateral wellbores 150 from their respective surface wellbore 120, 130.

[0027] The drilling of the inlet and outlet wellbores 120, 130 and connecting wellbores140 can be conducted sequentially with one drill rig and drilling string, or concurrently and in some implementations, simultaneously with the two drilling strings each operating to drill their respective lateral wellbore 150 at the same time. In some implementations, the inlet wellbore 120, the outlet wellbore 130 and the connecting wellbores 140 are drilled with two drilling rigs, one atop the inlet wellbore 120 and one atop the outlet wellbore 130. In some implementations, the wellbores are drilled with a single drilling rig configured to drill two wellbores at the same time (e.g., having two masts, two top drives and / or two rotary tables, etc.).

[0028] FIG. 2 shows an example drilling string 200 that can be used for at least the directional drilling, i.e., drilling the connecting wellbores 140 and the lateral wellbores 150 that form them. Drilling string 200 is shown as multiple connected joints of tubing 202 (individually referred to as 202i, 202ii, . . . , 202n), that may be drill pipe and / or another type of tubing, with a bottom hole assembly (BHA) 210. In some implementations, the drilling string 200 can be partially or wholly continuous (i.e., not jointed) coiled tubing and / or another type of tubing with a BHA 210. The BHA 210 includes a drill bit 208, a mud motor 212, a directional tool 214, a measurement sub 216, a ranging tool 218, and a communication tool 220 (e.g., a mud pulse telemetry, electric signaling, acoustic and / or other type of tool for sending communications to the terranean surface). Some or all of the tubing 202 can be insulated and / or have insulative features, such as insulative coatings, insulative linings, and insulative walls. The drilling string 200 can include one or more actuable fluid diverters 204 (i.e., bypasses) above the BHA 210, each separately actuable to divert at least a portion of the fluid flowing through the interior of the drilling string 200 into the annulus surrounding the drilling string 200.

[0029] The directional tool 214 is configured to selectively deflect the drill bit 208 towards the sidewall of the wellbore, and thus allows control over the drilling trajectory. In FIG. 2, the directional tool 214 is shown as a rotary steerable type tool with actuable skids 222 that can be selectively extended into the sidewall of the wellbore to push the drill bit 208 toward a specified drilling trajectory. In some implementations, the directional tool 214 can be a bent sub and / or other type of tool to control the trajectory of the drill bit 208.

[0030] Although one measurement sub 216 is shown in FIG. 2, the drilling string 200 can include multiple measurement subs 216. One example measurement sub 216 is a measurement while drilling (MWD) tool that can measure wellbore trajectory using one or more sensors (collectively sensor 240), such as a magnetometer sensor that senses the orientation of the tool (and thus the BHA 210) relative to the Earth’s magnetic field and an accelerometer that senses the orientation of the tool relative to gravity. Another example measurement sub 216 is a logging while drilling (LWD) tool that can measure formation and casing properties with one or more sensors 240, such as a pressure sensor, an acoustic sensor, a gamma emitter / sensor and / or other sensors. In some implementations, the measurement sub 216 includes one or more processors (collectively processor 242) with one or more memories (collectively memory 244), where the memory 244 stores instructions to cause the processor 242 to generate, while the measurement sub 216 is downhole, values from raw sensor data. The calculated values determined by the processor 242, such as inclination, azimuth, density, porosity and / or other values, can be communicated to the terranean surface for use in guiding the directional drilling and / or for other purposes. Or, if the measurement sub 216 lacks the capability to generate values from the raw data, the raw data itself can be sent to the surface. In either instance, the communication can be made by the communication tool 220. The information transmitted by the measurement sub 216 can be communicated via wire (e.g., a wireline, an electrical or fiber line embedded in or coupled to the drilling string 200 and / or in another wired manner) and / or via mud pulse telemetry.

[0031] In some implementations, the ranging tool 218 includes one or more processors (collectively processor 242) with one or more memories (collectively memory 244), where the memory 244 stores instructions to cause the processor 242 to generate, while the ranging tool 218 is downhole, the relative direction and distance values from raw sensor data, such as the sensor 240 output (e.g., the magnitude of the signal from the source) and other data (e.g., inclination, azimuth, and / or other raw data). The relative direction and distance values determined by the processor 242 while downhole can be communicated to the terranean surface for use in guiding the directional drilling. Or, if the tool 218 lacks the capability to generate direction and distance values, the raw data can be sent to the surface. In either instance, the communication can be made by the communication tool 220. The information transmitted by the ranging tool 218 can be communicated via wire (e.g., a wireline, an electrical or fiber line embedded in or coupled to the drilling string 200 and / or in another wired manner) and / or via mud pulse telemetry. In some implementations, the directional tool 214 can include a processor and memory configured to receive and use the relative direction and distance data generatedby the ranging tool 218 for autonomously and / or semi-autonomously controlling the trajectory of the drilling.

[0032] In drilling a lateral wellbore 150, the ranging tool 218 is operated when needed to determine the ranging tool’s 218 position, and thus the BHA 210 and current drilling position, relative to one or more sources in another or multiple lateral wellbores 150 or connecting wellbores 140. Such position information can be measured at specified regular or irregular intervals and used to ensure the lateral wellbore 150 being drilled is positioned in a specified manner relative to the other wellbore, e.g., in a specified trajectory (such as converging, diverging or parallel (precisely or substantially)) and at a specified distance or distances. As the lateral wellbore 150 approaches another lateral wellbore 150 to intersect the other lateral wellbore 150 (and create a connecting wellbore 140), the ranging tool 218 will be operated at shorter intervals to more precisely determine the location of the ranging tool 218 relative to the other lateral wellbore 150. The performance / temperature relationship of the ranging tool 218 may correlate the accuracy of the relative distance and / or the accuracy of the relative direction values that can be determined from the raw sensor 240 data, or the raw sensor 240, itself, to different temperatures of the ranging tool 218.

[0033] In some implementations, drilling bit 208 is a contact-type drilling bit, such as a polycrystalline diamond compact (PDC) drilling bit, rotary drilling bit, a particle drilling bit (e.g., a bit that impacts the rock with particles entrained in fluid, such as the system developed by Particle Drilling Technologies, Inc.) and / or other type of drilling bit that relies on contact with the rock to drill. In some implementations, drilling bit 208 can be a contactless drilling bit configured to break formation material at the rock face 228 being drilled (i.e., the end wall of the wellbore 150 at which rock is being removed) without requiring mechanical destruction between bit 208 and rock face 228. One example of a contactless drilling bit is an electrocrushing bit for electro-pulsed drilling. Examples of contactless drilling systems include plasma drilling (such as the plasma drilling system developed by GA Drilling, A.S.), laser drilling (such as the laser drilling system developed by Foro Energy), microwave drilling (such as the microwave drilling system developed by Quaise, Inc.), thermal spallation techniques such as supercritical water jetting or flame jets, and electro-pulse drilling (such as the electropulse drilling systems developed by Tetra Corporation). Although, referred to as “contactless,” this descriptor is not meant to exclude systems where portions of a drilling bit may bump, brush against, or otherwise come into contact with the formation during the drilling process.

[0034] In electro-pulse drilling systems, an electrocrushing bit is utilized that has multiple electrodes that generate high energy sparks to break formation material and therebyenable it to be cleared from the path of the drilling assembly. The bit can generate multiple sparks per second using a specified excitation current profile that causes a transient spark to form and arc through the most conducting portion of the rock face at the downhole end of the wellbore. The arc causes that portion of the rock face penetrated by the arc to disintegrate or fragment and be swept away by the flow of drilling fluid. A highly electrically resistive drilling fluid is utilized for such electro-pulse drilling. Descriptions of some electro-pulse drilling bits, drilling fluids, and related systems and methods that can be used herein are found in, for example, U.S. Pat. No. 4,741,405, U.S. Pat. No. 9,027,669, U.S. Pat. No. 9,279,322, U.S. Pat. No. 10,060,195, U.S. Pat. Pub. No. 12000299562A1, and PCT patent applications WO 2008 / 003092, WO 2010 / 027866, WO 2014 / 008483, WO 2018 / 136033, and WO 1200 / 236189.

[0035] As a lateral wellbore 150 is being drilled, drilling fluid 226 is pumped down the internal bore of the drilling string 200 and out through the drill bit 208 to the rock face 228 being drilled. The flow of drilling exits the bit 208, and a portion of the flow impacts the rock face 228 being drilled (the then end wall of the incomplete lateral wellbore 150). The drilling fluid then flows uphole in the annulus between the drilling string 200 and the sidewall of the lateral wellbore 150 being drilled, and then uphole to the surface in the annulus between the drilling string 200 and the surface wellbore 120, 130. One purpose of the drilling fluid is to entrain cuttings from the rock face 228 and carry the cuttings to the terranean surface for removal from the wellbore. The drilling fluid 226 also cools the tools in the BHA 210 as it flows through the bore of the drilling string 200 within the tools, and cools the rock face 228.

[0036] Referring briefly back to FIGS. 1A and IB, the temperature ofthe rock increases with depth in the subterranean zone 104 as a function of the thermal gradient of the zone 104 (i.e., the temperature increase per unit depth). The connecting wellbores 140 are the deepest wellbores of the geothermal well 102, drilled in the hottest rock of the zone 104 targeted by the well. Because the connecting wellbores 140 extend horizontally or slope through this hottest part of the zone 104, and the connecting wellbores 140 (and the lateral wellbores 150 that form them) are long, often 1-5 km or longer, the BHA 210 (FIG. 2A and 2B) must endure this hottest part of the zone 104 for long periods of time while drilling the connecting wellbores 140.

[0037] Referring to FIG. 2, heat 224, illustrated by arrows, is transferred from the rock of the zone 104 into the uphole flowing drilling fluid 226 in the annulus, through the wall of the drilling string 200, to the downhole drilling fluid 226 in the bore drilling string 200. This heat transfer through the counter-current flow is the primary heating influence on the fluid flowing downhole in the drilling string 200. The greatest rate of heat transfer between the annulus fluid and the fluid in the drilling string 200 is nearer the terranean surface than thebotom of the wellbore, because the temperature differential between the fluid in the annulus and in the drilling string 200 is the greatest near the surface. The high temperature differential is due to relatively cooler fluid being constantly supplied at the top of the drilling string 200, and the fluid in the annulus nearer to the terranean surface having had a long resident time adjacent to the heat of the rock to heat up as it traverses from the botom of the wellbore to the terranean surface. Conversely, the rate of heat transfer between the annulus fluid and the fluid in the drilling string 200 near the botom of the drilling string 200 (near the BHA 210) is lowest, because the fluids have a lower temperature differential. This lower temperature differential is in part because the fluid in the annulus in this region was recently the fluid in the drilling string 200.

[0038] Thermal control techniques can also include controlling the drilling fluid flow rate, distribution, and drilling fluid properties to affect the heat transfer, and thus the temperature of the fluid. In some implementations, for example with water-based fluids, increasing the flow rate can reduce the temperature of the drilling fluid in part because cool fluid more quickly displaces heated fluid in the drilling string 200, in the wellbore around the bit 208, and in the annulus near the botom of the wellbore (i.e., near and around the BHA 210). Selecting lower viscosity drilling fluids allow higher flow rates without excess heat generation from friction (hydraulic friction losses) that would otherwise occur at the higher flow rates. For example, in a primarily oil-based drilling fluid, having 90% oil, and with a low thermal resistance drilling string or an uninsulated drilling string, the frictional effect makes a lower flow rate typically beter at cooling the BHA 210. Also, in these conditions, higher viscosity fluids, such as thickened 90% oil base fluids selected to suspend high solids contents, are typically beter at cooling than equivalent lower viscosity fluids. However, by selecting a lower viscosity fluid, the fluid can be flowed at a higher flow rate to improve cooling if insulated drilling string is used. Thus, the drilling fluid flow rates can be selected based on the specified maximum and / or minimum drilling fluid temperatures, which in turn are determined based on the maximum rated temperatures of the tools in the BHA 210, specified maximum target and / or minimum temperatures determined based on the life / temperature relationship and performance / temperature relationship of the tools, and / or temperatures for shock cooling. Thermal control techniques can include selecting drilling fluid based on its thermal properties. Different drilling fluids can have different thermal properties, such as volumetric heat capacity and thermal conductivity. The different thermal properties thus affect the temperatures of the drilling fluid at the BHA 210 and in the wellbore, as well as the degree that the drilling fluid cools the tools of the BHA 210 and the rock face 228 (the relevance of cooling the rock face isdiscussed more below). Thus, the drilling fluid, itself, can be selected based on the specified maximum and / or minimum drilling fluid temperatures, discussed above, which in turn are determined based on the maximum rated temperatures of the tools in the BHA 210, specified maximum target and / or minimum temperatures determined based on the life / temperature relationship and performance / temperature relationship of the tools, and / or temperatures for shock cooling. Furthermore, different drilling fluids can be used for different intervals in a drilling run. For example, the drilling fluid for a first interval, nearer the terranean surface, may be different than the drilling fluid for a second interval, nearer the target depth of a lateral wellbore 150. In some implementations, the drilling fluid in the second interval may be selected prioritizing the thermal characteristics of the fluid to control the BHA 210 temperature, temperature of the fluid exiting the drill bit 208 and annular temperatures 226, while in the first interval, other aspects such as drilling performance, cost and / or other factors may be prioritized. Three, four, or additional intervals, each using different fluids, can be implemented.

[0039] Another thermal control technique can include cooling the drilling fluid at the terranean surface, after exiting the annulus and prior to reinjection into the drilling string 200. The cooling decreases the temperature of the fluid entering the drilling string 200, which can reduce the temperature of the fluid at the BHA 210 and the temperature of the fluid supplied into the wellbore at the drill bit 208. The cooling can be accomplished, for example, via a cooler that utilizes air or water cooling, refrigeration cycles, evaporative cooling, or any other type of cooling, and typically involves circulating the fluid through a heat exchanger of the cooler.

[0040] Another thermal control technique can include replacing the drilling fluid being used to drill with a different fluid during time durations in which the drilling fluid is not actively being used to drill. One example of a time duration in which the drilling fluid is not being actively used to drill is the time duration of a tripping operation in which the drilling string 200 is pulled out of the wellbore and then, subsequently, put back into the wellbore. A tripping operation may be necessary, for example, in cases in which the drill bit 208 needs to be repaired / replaced / changed or any case in which the drilling string 200 and / or BHA 210 needs to be taken out of the wellbore (such as for maintenance, repair / replace / change tubing, a tool, a BHA 210 component, after completion of drilling lateral 140 and / or otherwise). Typically, the drilling fluid being used to drill the wellbore remains within the wellbore throughout a tripping operation. However, because the drilling fluid is not circulated during this time (as it is during drilling), this disadvantageous^ causes the drilling fluid remaining in the wellbore tocontinue heating due to exposure to downhole temperatures of the subterranean formation. Some drilling fluids have a maximum rated temperature and / or temperature / fluid characteristic relationship whereby one or more characteristic of the fluid (e.g., effectiveness or additives, fluid rheology, fluid composition, and / or other characteristics) may change if the maximum rated temperature, or a specified temperature degradation threshold based on the temperature / fluid characteristic relationship, is exceed.

[0041] To counter this, the drilling fluid can be removed from the wellbore and replaced with a different fluid, such as an aqueous fluid or other fluid that can withstand increased operating temperatures without degrading or that is inexpensive, readily disposed of if degraded. In certain instances, the fluid being used to displace and replace the drilling fluid within the wellbore during tripping operations is an aqueous fluid that is configured to withstand a subterranean temperature (for example, temperatures greater than 200 degrees Celsius (°C)) encountered in the subterranean formation without degrading. In some implementations, the fluid being used to displace and replace the drilling fluid within the wellbore during tripping operations is an aqueous fluid that has a greater heat capacity in comparison to the drilling fluid. In some instances, the fluid being used to displace and replace the drilling fluid within the wellbore during tripping operations can be, for example, freshwater, treated wastewater, brine, weighted brine, another low-cost and thermally stable fluid and / or other fluids. By replacing the drilling fluid with another fluid within the wellbore during tripping operations, an operating temperature of the drilling fluid can be maintained below a maximum rated temperature and / or another specified temperature degradation threshold throughout drilling operations and can remain safe from temperature degradation. This allows the drilling fluid to be continuously recycled to perform drilling operations without needing to replace degraded drilling fluid. The maximum rated temperature and / or the specified temperature degradation threshold above which temperature degradation of the drilling fluid occurs depends on the type of drilling fluid used. In some implementations, the maximum rated temperature and / or the specified temperature degradation threshold is about 150 °C.

[0042] FIG. 3A illustrates a progression of stages of a tripping operation in which the drilling string 200 is pulled out of a wellbore 300. At stage (i), drilling has ceased, and the drilling string 200 has ceased operating to extend the wellbore 300. At stage (i), drilling fluid 226 that was used previously to drill the wellbore 300 resides within the wellbore 300. At stage (ii), an alternate fluid 304 is flowed into the drilling string 200. Flowing the alternate fluid 304 into the drilling string 200 at stage (ii) displaces drilling fluid 226 that was originally in the drilling string 200. The drilling fluid 226 is a drilling fluid having characteristics, such as fluidadditives, a specified rheology, a specified density and / or other characteristics, determined based on the drilling operations. In certain instances the drilling fluid 226 is an oil based drilling fluid, a drilling fluid having a greater oil to water ratio, a synthetic based fluid and / or another type of drilling fluid. The alternate fluid 304 is another fluid other than the drilling fluid selected based on one or multiple characteristics, such as its maximum rated temperature and / or temperature / fluid characteristic relationship relative to the temperatures expected to be experienced in the wellbore, its stability at those temperatures, relative lower cost than the drilling fluid 226, relative ease of disposal relative to the drilling fluid 226 and / or other factors. In certain instances, the alternate fluid 304 is an aqueous fluid and / or a fluid having a higher water to oil ratio than the drilling fluid 226. The alternate fluid 304 need not be a drilling fluid, but could be another fluid selected for geomechanical stability of the wellbore. At stage (iii), the alternate fluid 304 has reached the end of the drilling string 200 and has completely displaced the drilling fluid 226 that originally resided within the drilling string 200. At stage (iv), alternate fluid 304 continues to flow through the drilling string 200 and has begun to displace the drilling fluid 226 from the wellbore 300. The drilling fluid 226 displaced from the wellbore 300 by the alternate fluid 304 is received at the surface outside of the wellbore 300. At stage (v), the alternate fluid 304 has completely displaced the drilling fluid 226 from the wellbore 300, and the drilling string 200 is being pulled out of the wellbore 300. In certain instances, the drilling string 200 can be pulled out of the wellbore 300 beginning at the beginning of or during stage (iv), before the alternate fluid 304 has completely displaced the drilling fluid from the wellbore 300. At stage (vi), the drilling string 200 is lowered back into the wellbore 300 for further drilling. The drilling string 200 lowered back into the wellbore 300 at stage (vi) can be the same drilling string 200 that is shown in previous stages (i), (ii), (iii), (iv), and (v). In some implementations, the drilling string lowered into the wellbore 300 at stage (vi) is a different drilling string from drilling string 200 or the drilling string 200 that has been altered in some way (for example, replaced / repaired / changed drill bit and / or a tool, tubing or other component of the drilling string 200).

[0043] FIG. 3B illustrates a progression of stages of a tripping operation in which the drilling string 200 is pulled out of the wellbore 300. At stage (i), drilling has ceased, and the drilling string 200 has ceased operating to extend the wellbore 300. At stage (i), drilling fluid 226 that was used previously to drill the wellbore 300 resides within the wellbore 300. At stage (ii), a slug of spacer fluid 308 is flowed into the drilling string 200. The spacer fluid 308 is a fluid that is compatible with the drilling fluid 226 in that the spacer fluid 308 does not mix with (substantially or at all) or contaminate the drilling fluid 226. At stage (iii), an alternate fluid304 is flowed into the drilling string 200. Flowing the alternate fluid 304 into the drilling string 200 at stage (iii) displaces drilling fluid 226 that was originally in the drilling string 200. The slug of spacer fluid 308 provided at stage (ii) provides a liquid barrier between the drilling fluid 226 and the alternate fluid 304, so that the drilling fluid 226 is protected from mixing with and / or being contaminated by the alternate fluid 304. At stage (iv), the spacer fluid 308 has reached the end of the drilling string 200, and the spacer fluid 308 and alternate fluid 304 have completely displaced the drilling fluid 226 that originally resided within the drilling string 200. At stage (v), alternate fluid 304 continues to flow through the drilling string 200 and has begun to displace the drilling fluid 226 and the spacer fluid 308 from the wellbore 300. The drilling fluid 226 and spacer fluid 308 displaced from the wellbore 300 by the alternate fluid 304 are received at the surface outside of the wellbore 300. Simultaneously, at stage (v) the drilling string 200 is pulled out of the wellbore 300. At stage (vi), the alternate fluid 304 has completely displaced the drilling fluid 226 and spacer fluid 308 from the wellbore 300, and the drilling string 200 has been fully pulled out of the wellbore 300. In certain instances, the drilling string 200 can remain in the wellbore 300 until the drilling fluid 226 and spacer fluid 308 are fully displaced from the wellbore 300 and then the drilling string 200 withdrawn. At stage (vii), the drilling string 200 is lowered back into the wellbore 300 for further drilling. The drilling string 200 lowered back into the wellbore 300 at stage (vii) can be the same drilling string 200 that is shown in previous stages (i), (ii), (iii), (iv), (v), and (vi). In some implementations, the drilling string lowered into the wellbore 300 at stage (vii) is a different drilling string from drilling string 200 or the drilling string 200 that has been altered in some way (for example, replaced / repaired / changed drill bit and / or a tool, tubing or other component of the drilling string 200).

[0044] FIG. 3C illustrates a progression of stages of a tripping operation in which the drilling string 200 is pulled out of the wellbore 300. At stage (i), drilling has ceased, and the drilling string 200 has ceased operating to extend the wellbore 300. At stage (i), drilling fluid 226 that was used previously to drill the wellbore 300 resides within the wellbore 300. At stage (ii), a spacer fluid 308 is flowed into the drilling string 200. The spacer fluid 308 is a fluid that is compatible with the drilling fluid 226 in that the spacer fluid 308 does not mix with (substantially or at all) or contaminate the drilling fluid 226. At stage (iii), an alternate fluid 304 is flowed into the drilling string 200. Flowing the alternate fluid 304 into the drilling string 200 at stage (iii) displaces drilling fluid 226 that was originally in the drilling string 200. The spacer fluid 308 provided at stage (ii) provides a liquid barrier between the drilling fluid 226 and the alternate fluid 304, so that the drilling fluid 226 is protected from mixing with and / orbeing contaminated by the alternate fluid 304. At stage (iv), the spacer fluid 308 has reached the end of the drilling string 200, and the spacer fluid 308 and alternate fluid 304 have completely displaced the drilling fluid 226 that originally resided within the drilling string 200. At stage (v), alternate fluid 304 continues to flow through the drilling string 200 and has begun to displace the drilling fluid 226 and the spacer fluid 308 from the wellbore 300. The drilling fluid 226 and spacer fluid 308 displaced from the wellbore 300 by the alternate fluid 304 are received at the surface outside of the wellbore 300. Simultaneously, at stage (v) the drilling string 200 is pulled out of the wellbore 300. At stage (vi), the alternate fluid 304 has completely displaced the drilling fluid 226 and spacer fluid 308 from the wellbore 300. In certain instances, the drilling string 200 can remain in the wellbore 300 until the drilling fluid 226 and spacer fluid 308 are fully displaced from the wellbore 300 and then the drilling string 200 withdrawn. At stage (vii), a bridge plug 310 is placed within the wellbore 300. The bridge plug 310 can be a mechanical bridge plug or a liquid bridge plug. The bridge plug 310 is a fluid flow isolation apparatus that seals against a wall of the wellbore 300 and plugs a portion of the wellbore 300, such that fluid is prevented from escaping the plugged portion of the wellbore 300. The bridge plug 310 can be placed, for example, using a drilling string, coiled tubing, wireline and / or in another manner. In certain instances, the bridge plug 310 is a fluid, such as cement or another fluid that will harden in the wellbore to define a bridge plug 310. In certain instances, the bridge plug 310 is integral with a whipstock used to kick off drilling a lateral wellbore from wellbore 344. At stage (viii), the drilling string 200 is lowered back into the wellbore 300 for further drilling. The drilling string 200 lowered back into the wellbore 300 at stage (viii) can be the same drilling string 200 that is shown in previous stages (i), (ii), (iii), (iv), (v), (vi), and (vii). In some implementations, the drilling string lowered into the wellbore 300 at stage (viii) is a different drilling string from drilling string 200 or the drilling string 200 that has been altered in some way (for example, replaced / repaired / changed drill bit and / or tool, tubing or other component of the drilling string 200). In certain instances, as shown at stage (viii), the drilling string 200 is operated to drill a lateral 300’ from the wellbore 300. The lateral 300’ is a secondary wellbore branching from the wellbore 300. The drilling fluid 226 is circulated through the lateral 300’ as the lateral 300’ is drilled. The alternate fluid 304 residing in the portion of the wellbore 300 sealed by the bridge plug 310 is prevented from interacting and contaminating the drilling fluid 226 as the lateral 300’ is drilled.

[0045] FIG. 3D depicts a multilateral geothermal well 320. The multilateral geothermal well 320 includes a wellbore 322. In the view shown in FIG. 3D, the wellbore 322 has already been formed. The drilling fluid 226 that was used to drill the wellbore 322 wasdisplaced and replaced by the alternate fluid 304 during a first tripping operation, and a portion 322a of the wellbore 322 has been filled with the alternate fluid 304. A first bridge plug 324 has been placed to isolate the portion 322a of the wellbore 322, so that the alternate fluid 304 filling the portion 322a of the wellbore 322 does not escape and interfere with further drilling operations. By replacing the drilling fluid 226 with the alternate fluid 304 in the wellbore 322 during the first tripping operation, the drilling fluid 226 can avoid heating up to elevated temperatures (for example, exceeding 150 °C), thereby avoiding temperature degradation.

[0046] The multilateral geothermal well 320 includes a first lateral 332. In the view shown in FIG. 3D, the first lateral 332 has already been formed. Similar to the wellbore 322, the drilling fluid 226 that was used to drill the first lateral 332 was displaced and replaced by the alternate fluid 304 during a second tripping operation, and a portion 332a of the first lateral 332 has been filled with the alternate fluid 304. A second bridge plug 334 has been placed to isolate the portion 332a of the first lateral 332, so that the alternate fluid 304 filling the portion 332a of the first lateral 332 does not escape and interfere with further drilling operations. By replacing the drilling fluid 226 with the alternate fluid 304 in the first lateral 332 during the second tripping operation, the drilling fluid 226 can avoid heating up to elevated temperatures (for example, exceeding 150 °C), thereby avoiding temperature degradation.

[0047] The multilateral geothermal well 320 includes a second lateral 342. In the view shown in FIG. 3D, the second lateral 342 is being formed. A whipstock 344 has been placed to direct the BHA 210 of the drilling string 200 in the desired direction for forming the second lateral 342. The whipstock 344 defines an inclined plane (wedge) that causes the drill bit 208 to deflect from the original borehole (for example, the wellbore 322) at a kick-off point. In some implementations, the whipstock 344 includes an anchor to fix the whipstock 344 in position in the wellbore during sidetracking operations and efficient slip retraction for easy retrieval. The whipstock 344 (or another similar whipstock) can, for example, have been used to form the first lateral 342, which is shown as having already been formed in FIG. 3D. The drilling fluid 226 is circulated through the second lateral 342 as the second lateral 342 is being drilled by the BHA 210 of the drilling string 200. Once the second lateral 342 has been fully formed, the drilling fluid 226 can similarly be displaced and replaced by the alternate fluid 304 during a third tripping operation for withdrawing the drilling string 200 from the second lateral 342. By replacing the drilling fluid 226 with the alternate fluid 304 in the second lateral 342 during the third tripping operation, the drilling fluid 226 can avoid heating up to elevated temperatures (for example, exceeding 150 °C), thereby avoiding temperature degradation.

[0048] FIG. 4A is a flow chart for an example method 400A for a tripping operation while drilling a wellbore, such as the wellbore 300 or the wellbore of the geothermal system 100. At block 402, a tripping operation is performed while drilling the wellbore 300. Performing the tripping operation at block 402 includes displacing a drilling fluid 226 from a drilling string 200 disposed within the wellbore 300 by flowing an alternate fluid 304 through the drilling string 200 at block 402a. As mentioned previously, the drilling fluid 226 is the same type of fluid that was used to drill the wellbore 300. The drilling fluid 226 can, for example, be an oil-based drilling fluid. In some implementations, the method 400A includes flowing a spacer fluid 308 into the drilling stream 200 prior to block 402a (an example can be seen in stage (ii) of FIG. 3B). Performing the tripping operation at block 402 includes displacing the drilling fluid 226 from the wellbore 300 to the terranean surface by flowing the alternate fluid 304 into the wellbore 300 at block 402b. The alternate fluid 304 displaces the drilling fluid 226 from the wellbore 300 at block 402b before a temperature of the drilling fluid 226 exceeds 150 °C. An example of blocks 402a and 402b being performed can be seen in stage (iv) of FIG. 3A. In some implementations, the method 400A includes placing a fluid flow isolation apparatus (such as the bridge plug 310) within the wellbore 300 after block 402b. In some implementations, the method 400A includes sealing, by the bridge plug 310, a portion of the wellbore 300 to prevent the alternate fluid 304 from escaping the sealed portion of the wellbore 300 (an example can be seen in stage (vii) of FIG. 3C). Performing the tripping operation at block 402 includes withdrawing the drilling string 200 from the wellbore 300 at block 402c. An example of block 402c being performed can be seen in stage (v) of FIG. 3A. In some implementations, blocks 402b and 402c occur simultaneously. In some implementations, the method 400A includes running a second drilling string into the wellbore 300 after block 402c. The second drilling string can be the drilling string 200, a different drilling string, or the drilling string 200 that has been altered in some way (for example, replaced / repaired drill bit and / or replaced / repaired instrumentation). In some implementations, the method 400A includes drilling a second wellbore with the second drilling string while circulating the drilling fluid 226 through the second wellbore. By implementing the method 400A, an operating temperature of the drilling fluid 226 can remain below about 150 °C throughout drilling operations and can remain safe from temperature degradation.

[0049] FIG. 4B is a flow chart for an example method 400B for a tripping operation while drilling a wellbore, such as the wellbore 300 or the wellbore of the geothermal system 100. At block 404, an alternate fluid 304 is flowed through a drilling string 200 to an end of the drilling string 200, which is disposed in a wellbore 300 being formed in a subterraneanformation. An example of block 404 being performed can be seen in stages (ii) and (iii) of FIG. 3A. In some implementations, the method 400B includes flowing a spacer fluid 308 into the drilling stream 200 prior to block 404 (an example can be seen in stage (ii) of FIG. 3B). At block 406, a drilling fluid 226 disposed within the wellbore 300 is displaced with the alternate fluid 304. As mentioned previously, the drilling fluid 226 is the same type of fluid that was used to drill the wellbore 300. The drilling fluid 226 can, for example, be an oil-based drilling fluid. The alternate fluid 304 displaces the drilling fluid 226 from the wellbore 300 at block 406 before a temperature of the drilling fluid 226 exceeds 150 °C. An example of block 406 being performed can be seen in stage (iv) of FIG. 3A. In some implementations, the method 400B includes placing a fluid flow isolation apparatus (such as the bridge plug 310) within the wellbore 300 after block 406. In some implementations, the method 400B includes sealing, by the bridge plug 310, a portion of the wellbore 300 to prevent the alternate fluid 304 from escaping the sealed portion of the wellbore 300 (an example can be seen in stage (vii) of FIG. 3C). At block 408, the drilling fluid 226 being displaced from the wellbore 300 is received at a surface location outside of the wellbore 300. At block 410, the drilling string 200 is removed from the wellbore 300. An example of block 410 being performed can be seen in stage (v) of FIG. 3 A. In some implementations, blocks 406, 408, and 410 occur simultaneously. In some implementations, the method 400B includes running a second drilling string into the wellbore 300 after block 410. The second drilling string can be the drilling string 200, a different drilling string, or the drilling string 200 that has been altered in some way (for example, replaced / repaired drill bit and / or replaced / repaired instrumentation). In some implementations, the method 400B includes drilling a second wellbore with the second drilling string while circulating the drilling fluid 226 through the second wellbore. By implementing the method 400B, an operating temperature of the drilling fluid 226 can remain below about 150 °C throughout drilling operations and can remain safe from temperature degradation.

[0050] While this specification contains many specific implementation details, these should not be construed as limitations on the scope of what may be claimed, but rather as descriptions of features that may be specific to particular implementations. Certain features that are described in this specification in the context of separate implementations can also be implemented, in combination, in a single implementation. Conversely, various features that are described in the context of a single implementation can also be implemented in multiple implementations, separately, or in any sub-combination. Moreover, although previously described features may be described as acting in certain combinations and even initially claimed as such, one or more features from a claimed combination can, in some cases, beexcised from the combination, and the claimed combination may be directed to a subcombination or variation of a sub-combination.

[0051] As used in this disclosure, the terms “a,” “an,” or “the” are used to include one or more than one unless the context clearly dictates otherwise. The term “or” is used to refer to a nonexclusive “or” unless otherwise indicated. The statement “at least one of A and B” has the same meaning as “A, B, or A and B.” In addition, it is to be understood that the phraseology or terminology employed in this disclosure, and not otherwise defined, is for the purpose of description only and not of limitation. Any use of section headings is intended to aid reading of the document and is not to be interpreted as limiting; information that is relevant to a section heading may occur within or outside of that particular section.

[0052] As used in this disclosure, the term “about” or “approximately” can allow for a degree of variability in a value or range, for example, within 10%, within 5%, or within 1% of a stated value or of a stated limit of a range.

[0053] As used in this disclosure, the term “substantially” refers to a majority of, or mostly, as in at least about 50%, 60%, 70%, 80%, 90%, 95%, 96%, 97%, 98%, 99%, 99.5%, 99.9%, 99.99%, or at least about 99.999% or more.

[0054] Values expressed in a range format should be interpreted in a flexible manner to include not only the numerical values explicitly recited as the limits of the range, but also to include all the individual numerical values or sub-ranges encompassed within that range as if each numerical value and sub-range is explicitly recited. For example, a range of “0.1% to about 5%” or “0.1% to 5%” should be interpreted to include about 0. 1% to about 5%, as well as the individual values (for example, 1%, 2%, 3%, and 4%) and the sub-ranges (for example, 0.1% to 0.5%, 1.1% to 2.2%, 3.3% to 4.4%) within the indicated range. The statement “X to Y” has the same meaning as “about X to about Y,” unless indicated otherwise. Likewise, the statement “X, Y, or Z” has the same meaning as “about X, about Y, or about Z,” unless indicated otherwise.

[0055] Particular implementations of the subject matter have been described. Other implementations, alterations, and permutations of the described implementations are within the scope of the following claims as will be apparent to those skilled in the art. While operations are depicted in the drawings or claims in a particular order, this should not be understood as requiring that such operations be performed in the particular order shown or in sequential order, or that all illustrated operations be performed (some operations may be considered optional), to achieve desirable results. In certain circumstances, multitasking or parallel processing (or a combination of multitasking and parallel processing) may be advantageous and performed asdeemed appropriate.

[0056] Moreover, the separation or integration of various system modules and components in the previously described implementations should not be understood as requiring such separation or integration in all implementations, and it should be understood that the described components and systems can generally be integrated together or packaged into multiple products.

[0057] Accordingly, the previously described example implementations do not define or constrain the present disclosure. Other changes, substitutions, and alterations are also possible without departing from the spirit and scope of the present disclosure.

Claims

CLAIMSWHAT IS CLAIMED IS:

1. A method, comprising: performing a tripping operation during the drilling of a wellbore in a subterranean formation, wherein performing the tripping operation comprises: displacing a drilling fluid from a drilling string disposed within the wellbore by flowing an alternative fluid through the drilling string, wherein the drilling fluid is the same type of fluid used when drilling the wellbore; displacing the drilling fluid from the wellbore to a terranean surface by flowing the aqueous fluid into the wellbore; and withdrawing the drilling string from the wellbore.

2. The method of claim 1, further comprising, after withdrawing the drilling string, running a second drilling string into the wellbore.

3. The method of claim 2, wherein the drilling fluid comprises an oil-based drilling fluid.

4. The method of any of claims 1-3, wherein displacing the drilling fluid from the wellbore and withdrawing the drilling string from the wellbore occur simultaneously.

5. The method of any of claims 1-4, further comprising, prior to displacing the drilling fluid from the drilling string, flowing a spacer fluid into the drilling string.

6. The method of any of claims 1-5, further comprising, after displacing the drilling fluid from the wellbore: placing a plug within the wellbore; and sealing, by the plug, a portion of the wellbore to prevent the alternative fluid from escaping the portion of the wellbore.

7. The method of any of claims 1-6, wherein a subterranean temperature of the subterranean formation exceeds 200 degrees Celsius (°C), and the drilling fluid is displaced from the wellbore before a temperature of the drilling fluid exceeds 150 °C.

8. The method of claim 7, wherein the alternative fluid is configured to withstand the subterranean temperature of the subterranean formation without degrading.

9. A method, comprising: flowing a fluid through a drilling string to an end of the drilling string disposed in a wellbore being formed in a subterranean formation; after flowing the fluid to the end of the drilling string, displacing a drilling fluid disposed within the wellbore with the first mentioned fluid; receiving the drilling fluid displaced from the wellbore at a surface location outside of the wellbore; and removing the drilling string from the wellbore.

10. The method of claim 9, further comprising: removing the drilling string from the wellbore; and inserting a second drilling string into the wellbore.

11. The method of claim 10, wherein the drilling fluid comprises an oil -based drilling fluid.

12. The method of any of claims 9-11, wherein displacing the drilling fluid within the wellbore with the first mentioned fluid and removing the drilling string from the wellbore occur simultaneously.

13. The method of any of claims 9-12, further comprising, prior to flowing the first mentioned fluid through the drilling string, flowing a spacer fluid into the drilling string.

14. The method of any of claims 9-13, further comprising, after receiving the drilling fluid displaced from the wellbore at the surface location, sealing a portion of the wellbore to prevent the first mentioned fluid from escaping the portion of the wellbore.

15. The method of any of claims 9-14, wherein a subterranean temperature of the subterranean formation exceeds 200 degrees Celsius (°C), and the drilling fluid is displaced from the wellbore before a temperature of the drilling fluid exceeds 150 °C.

16. The method of claim 15, wherein the first mentioned fluid is aqueous fluid.

17. The method of any of claims 9-14, wherein a subterranean temperature of the subterranean formation exceeds a specified maximum temperature for the drilling fluid, and the drilling fluid is displaced from the wellbore before a temperature of the drilling fluid exceeds the specified maximum temperature.

18. The method of claim 17, wherein the specified maximum temperature is selected based on a temperature / rheology relationship of the drilling fluid.

19. The method of any of claims 9-18, wherein the wellbore is a wellbore in a geothermal well.

20. The method of cany of claims 9-19, wherein the wellbore is a lateral wellbore.

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