Cooling fluid returns

Abstract

Fluid is supplied fluid from a drilling string residing in a wellbore into an annulus between the drilling string and the wellbore based on a specified maximum temperature of the fluid in the annulus. The fluid in the annulus is cooled by the supplied fluid to at least the specified maximum temperature before the fluid exits the wellbore to the terranean surface.

Description

COOLING FLUID RETURNSTECHNICAL FIELD

[0001] This disclosure relates to drilling wells in hot subterranean zones, such as needed when drilling a geothermal well or other well in a hot zone.BACKGROUND

[0002] The high temperatures of hot subterranean zones make constructing the wells in the hot zones difficult. When the well is a multilateral, the additional length of the wellbores drilled and additional time spent drilling in the high temperatures of the subterranean zone exacerbates these difficulties. The tools used to drill the wellbores must be 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. But the available cooling by the drilling fluid becomes less as the drilling fluid, itself, heats up. The drilling fluid is circulated down the drilling string and back to the surface for re-use. The returned fluid is heated by its passage through the drilling string, and then further heated by the surrounding rock. The returning fluid at the surface can sometimes be heated in excess of 100° C, which presents dangers to workers at the surface handling fluids.SUMMARY

[0003] Certain aspects encompass a method where fluid from a drilling string residing in a wellbore is supplied into an annulus between the drilling string and the wellbore based on a specified maximum temperature of the fluid at a terranean surface. The fluid in the annulus is cooled to at least the specified maximum temperature before the fluid exits the wellbore to the terranean surface.

[0004] Certain aspects encompass a method where a geothermal well is drilled from a terranean surface into a geothermal subterranean zone, and while drilling the geothermal well, fluid returned to the terranean surface through a wellbore of the well is cooled to a specified temperature below which the fluid can flash to vapor at ambient atmospheric conditions at the terranean surface.

[0005] The aspects above can include some, none or all of the following features. In certain instances, supplying fluid from a drilling string includes supplying fluid through a diverter in the drilling string into the annulus. In certain instances, supplying fluid from a drilling string includes supplying fluid through a fluid separator in the drilling string into the annulus. In certain instances, supplying fluid through a fluid separator includes supplying a water rich fluid into the annulus and supplying an oil rich fluid through the drilling string below the fluid separator. In certain instances, supplying fluid from a drilling string includes supplying fluid from one of multiple tubes of the drilling string into the annulus from an opening in the tube uphole from a bottom hole assembly of the drilling string. In certain instances, supplying fluid from a drilling string includes supplying fluid from the drilling string into the annulus at 1000 m or less from the terranean surface while a bottom of the drilling string is at a total depth of greater than 1000 m. In certain instances, the fluid that exits the wellbore at the terranean surface is maintained in piping at the terranean surface until flowed into a cooler. In certain instances, specified temperature is 80° C. In certain instances, the specified temperature is selected based on an ambient atmospheric pressure at a wellsite where the wellbore is being drilled. In certain instances, the specified temperature is below a temperature at which the fluid can flash to vapor at 101.325 kPa.BRIEF DESCRIPTION OF DRAWINGS

[0006] FIG. 1A is a schematic side cross-sectional view of an example closed loop geothermal system in accordance with the concepts herein.

[0007] FIG. IB is a schematic side cross-sectional view of another example closed loop geothermal system in accordance with the concepts herein.

[0008] FIG. 2A is a side view of an example geothermal well, such as those in the systems of FIGS. 1A and IB, being drilled on jointed tubing in accordance with the concepts herein.

[0009] FIG. 2B is a side view of an example geothermal well, such as those in the systems of FIGS. 1A and IB, being drilled on coiled tubing in accordance with the concepts herein.

[0010] FIG. 3A is a schematic view of a downhole separator as a component of a drilling string, in accordance with the concepts herein.

[0011] FIG. 3B is a schematic view of another example of a downhole separator as a component of a drilling string, in accordance with the concepts herein.

[0012] FIG. 4 is end cross-sectional view of an example bundled coiled tubing in accordance with the concepts herein.

[0013] Like reference numbers in the drawings represent like elements.DETAILED DESCRIPTION

[0014] Turning now to FIG. 1A, an example closed loop geothermal system 100 is shown in schematic, side cross-sectional view in accordance with the concepts herein. In certain instances, 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 (e.g., horizontal, sloped or otherwise deviated) wellbores that exchange heat with the subterranean zone.

[0015] System 100 includes a geothermal well 102 drilled into the Earth through a geothermal subterranean zone of interest 104. In certain instances, 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 certain instances, the subterranean zone is in a crystalline basement formation. In certain instances, the rock of the subterranean zone is in a granitic formation (e.g., granite). In certain instances, the subterranean zone 104 is selected based on its heat producing potential, so that the completed well 102 produces enough heat that the commercial value of that heat will, in a specified payback period, pay for the cost of constructing and running the well 102 and eventually yield a profit. In certain instances, the subterranean zone 104 is selected based on the levelized cost of electricity (LCOE) and / or levelized cost of heat (LCOH) produced by the well is competitive to other sources. In certain instances, the zone 104 has a temperature greater than 100° C, 200° C, 300° C, or even 400° C. In the illustrated instance, 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 the illustrated instance, 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. Thus, the inlet wellbore 120, outlet wellbore 130 and connecting wellbores 140 define a closed loop.

[0016] 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 certain instances, the wellbores 120, 130are drilled within 10, 25, 50 or 100 meters of one another. In other instances, 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 where the surface wellbores 120, 130 and the connecting wellbores 140 define a U-shape configuration. In certain instances, 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.

[0017] In the illustrated instance, 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 other instances, one or both of the 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 are drilled using directional drilling techniques through the surface wellbores 120, 130, and include a curve in their trajectory beginning at a kickoff 148 at surface wellbores 120, 130. Although shown as slanted downward, in some instances, some or all of the connecting wellbores are horizontal. In some instances, the connecting wellbores 140 follow the geological dip of the formation in the subterranean zone. In some instances, lateral wellbores 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.

[0018] 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 instances, 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 other instances, 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 certain instances, 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). In FIG. 1A, the lower lateral wellbores 150 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 thewellbores. In other instances, one or more of the upper lateral wellbores 150 could extend past the junction to define the sump 152.

[0019] FIG. IB another embodiment of a 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 certain instances, in the same plane. In certain instances, 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).

[0020] Referring to FIGS. 1A and IB, collectively, in some instances, 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 instances, 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 the surrounding 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 certain instances, 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 certain instances, the sealant can be included in the heat transfer working fluid and / or supplied in fluid slugs, distinct from the heat transfer working fluid.

[0021] In the illustrated instance, system 100 further includes a facility 110 disposed between inlet surface wellbore 120 and outlet surface wellbore 130. Well 102 can be sealed and a working fluid added to the closed loop and circulated in the system such that it absorbs heat from subterranean zone 104. In certain instances, 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 asa 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 certain instances, 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 an electric generator or directly using the heat of the working fluid in an industrial, agricultural or residential process. In some instances, facility 110 is disposed at or near the Earth’s surface; in other instances, facility 110 may be 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, it can be split between one or more discrete locations (shown as facility 110a, 110b) connected by piping.

[0022] In either instance, FIG. 1A or IB, the geothermal well is 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 the connecting 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 certain instances, a whipstock is used to kick off the lateral wellbores 150 from their respective surface wellbore 120, 130.

[0023] The drilling of the inlet and outlet wellbores 120, 130 and connecting wellbores 140 can be conducted sequentially with one drill rig and drilling string, or concurrently and, in some instances simultaneously, with the two drilling strings each operating to drill their respective lateral wellbore 150 at the same time. In some instances, 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 other instances, 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.). In certaininstances, such as when using coiled tubing, the drilling rig can be a coiled tubing rig. In certain instances, such as when constructing the drilling string from both jointed tubing and coiled tubing, the drilling rig can be a hybrid jointed tubing and coiled tubing rig. For example, such a rig can have jointed pipe handling capability and a drive (e.g., top drive, rotary table drive and / or another tubing drive), as well as a tubing spool handling capability and a continuous injector system, and be able to switch between the two as different types of tubing, jointed or coiled, are assembled into the drill string.

[0024] FIGS. 2A-2B show 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 of FIG. 2A is shown depending from a drilling rig 232 as multiple connected joints of tubing 202 (individually referred to as 202i, 202ii. . ,202n), that may be drill pipe and / or another type of jointed tubing, with a bottom hole assembly (BHA) 210. In other instances, the drilling string 200 can be partially or wholly continuous coiled tubing 202. FIG. 2B shows a drilling string 200 constructed of multiple connected lengths of coiled tubing 202 in an upper interval and jointed tubing 202 with a BHA 210 in a lower, further downhole interval. Also, although FIG. 2B shows multiple tubings, in certain instances, the drilling string 200 can be a single, continuous length of coiled tubing depending from a coiled tubing rig 234 (or a hybrid rig) and having a BHA 210 or other components connected at its downhole end. Also, in certain instances, the drilling string 200 can be multiple side-by-side tubes, such as shown and discussed in more detail in connection with FIGS. 8-9.

[0025] The BHA 210 includes, among other things, a drill bit, a mud motor, a directional tool, one or more measurement subs, a ranging tool and a communication tool (e.g., a mud pulse telemetry, electric signaling, acoustic and / or other type of tool for sending communications to the terranean surface). The drilling string 200 can include other components, depicted as component 238 (FIG. 2B), such as fluid separators, tractors (to pull the string through the wellbore), agitator / vibrator tools (to reduce stiction of the string on the wellbore), mud turbine electric generators, battery systems, capacitors and / or other components, positioned in the BHA 210 or apart from the BHA 210. Although only one component 238 is shown, one or multiple could be provided in the configurations of FIGS. 2A-2B. Some or all of the tubing 202 can be insulated, having insulative features, such as insulative coatings or linings and / or multiple walls. In certain instances, some or all of the tubing has a length normalized, bulk, radial thermal resistance to heat transfer through asidewall of the tubing that is at least 0.008 m K / W, at least 0.05 m K / W or higher. In certain instances, the drilling string 200 can include one or more actuable fluid diverters and / or separators 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.

[0026] As a lateral wellbore 150 is being drilled, drilling fluid is pumped down the internal bore of the drilling string 200 and out through the drill bit 208 to the rock face being drilled. 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 and carry the cuttings to the terranean surface for removal from the wellbore. Further, as discussed in more detail below, the drilling fluid also cools the tools in the BHA 210 and the tubing 202 as the fluid flows through the bore of the drilling string 200 within the tools, and cools the rock face 228.

[0027] Referring briefly back to FIGS. 1A and IB, the temperature of the 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, 10 km or longer, the BHA 210 (FIGS. 2A-2C) must endure this hottest part of the zone 104 for long periods of time while drilling the connecting wellbores 140.

[0028] Referring to FIGS. 2A and 2B, heat is transferred from the rock of the zone 104 into the uphole flowing drilling fluid in the annulus, through the wall of the drilling string 200, to the downhole drilling fluid 226 in the bore drilling string 200. While the drilling string 200 and the drilling fluid in the drilling string 200 absorb some heat from the drilling fluid in the annulus, the majority of the heat is communicated to the terranean surface. In certain instances, the fluid temperatures in the annulus, if uncontrolled, can exceed 100° C. Beyond the inherent dangers in workers at the surface handling fluids at such high of temperatures, the fluid can flash to vapor (e.g., steam if aqueous) at surface conditions introducing further risks to handling. As described in more detail below, temperature control techniques can be implemented to reduce the temperature of the drilling fluid returns whilestill within the annulus and / or on the surface before the fluids are let to come to surface conditions. In certain instances, returns temperatures are cooled to 80°C or lower. In certain instances, the returns temperature are cooled at least to a temperature below which the fluid can flash to vapor at ambient atmospheric pressure at the wellsite and / or 101.325 kPa.

[0029] The annulus fluid temperature control techniques can include releasing flow from within the drilling string 200 into the annulus via a one or more fluid diverter tools 204 to intermix with and cool the fluids (e.g., drilling fluids returns) in the annulus. Three such diverter tools are shown in FIG. 2B; however, in some instances, a fewer or greater number of diverter tools (for example, only one diverter tool or five diverter tools) can be deployed as part of drilling string 200. For example, a diverter tool 204 near the surface bypasses a portion of the cool drilling fluid flow from within the drilling string 200 into the annulus to cool the annulus fluids. In certain instances, diverter tools 204 are placed in the drilling string 200, as the drilling string 200 is extended during drilling, to maintain a diverter tool 204 at 1000 m or less from the terranean surface during the drilling operations, and at least during drilling the lateral wellbore 150. In certain instances, in the context of the well systems of FIGS. 1A and IB, the diverter tools 204 are added to the drilling string 200 so that there is a diverter tool 204 in the vertical portion of the surface wellbores 120, 130, and in certain instances, in the top half of the surface wellbores 120, 130. In certain instances, the diverter tools 204 are added to the drilling string 200 based on the residence time needed for the drilling fluid, at the temperature it is release from the diverter tool 204, to cool the annulus fluid to at least the specified maximum temperature. Although, diverting a portion of the fluid with the diverter tool 204 reduces the amount of fluid that flows to the BHA 210 and through the drill bit 208, the drilling string 200 can be configured (e.g., by flow area) to allow higher flow rates in the upper portion of the drilling string 200 and maintain the flow rates in the lower portions of the drilling string 200 needed to cool the BHA 210 and components. Furthermore, the diverter tools 204 can be actuable (e.g., electrically, hydraulicly, mechanically and / or otherwise) between not diverting fluid and diverting fluid and / or to control (e.g., meter) the amount of fluid through the diverter tool 204 into the annulus. The amount of fluid diverted by the diverter tool 204 can be selected based on a specified maximum temperature of the annulus fluid and the temperature of the drilling fluid in the drilling string 200, the temperature of the fluid in the annulus, and the relative flow rates and volumes of the fluids. The use of flow diverter tools 204 can also allow circulation of the drilling fluid down the drilling string 200 and up the annulus when not drilling, to continue tomaintain fluid temperature in the annulus below the specified maximum temperature of the annulus fluid by bypassing fluid into the annulus so that the fluid going to the mud motor (if provided) is not enough to turn the drill bit 208 or not enough to turn the drill bit 208 with enough torque to drill the rock.

[0030] In certain instances, instead of or in addition to diverter tools 204, the tool 204 can be a separator configured to separate drilling fluid 226 into a water-rich stream and an oilrich (hydrocarbon and / or synthetic oil) stream and divert the water-rich stream to the annulus uphole of BHA 210. The positioning of the diverter tools in the drilling string 200, as the drilling string 200 is assembled, can be the same as described for the diverter tools (e.g., within 1000 m of surface, in the surface wellbores 120, 130, based on the residency time needed to cool the annulus fluid, etc.). One or multiple separators can be used, and the number, the configuration of separator tools in the drilling string 200, and, if actuable, when and to what degree the separator tools are actuated to separate and divert fluid can be selected based on the specified maximum temperature of the annulus fluid. Furthermore, by diverting a water-rich (and thus high heat-capacity) stream into the annulus, the stream better cools the annulus fluid, while flowing a relatively oil-rich remaining stream to the drill bit for lubricity (for reducing torque and drag of the bit on the wellbore and / or lubricate rotating components of tools in the string), chemical stability, and dielectric properties (such as those needed with pulsed power drilling bits) at the drill bit.

[0031] FIG. 3A illustrates detail of an example fluid separator 500 that could be used as fluid separator tool 204. Separator 500 includes a cyclone chamber 502 within a housing 504. An inlet 506 of cyclone chamber 502 is configured to receive drilling fluid 408 from tubing 402. The drilling fluid enters the cyclone unit tangentially. An outer vortex is generated in the cyclone which imparts a centripetal force that drives separation between the lower density oil phase and higher density water phase. The heavier water phased exits as water-rich stream 410 from outlet 508 to flow into the annulus exterior tubing 402. The lighter phase oil will migrate towards the center of the cyclone to emerge as oil-rich stream 412 flowing from outlet 510 to drilling bit 404.

[0032] FIG. 3B illustrates detail of another example fluid separator 600 that could be used as fluid separator tool 204. Separator 600 includes a helical vanes 602 above a chamber 604 within a housing 606. As drilling fluid 408 enters the separator, spin is imparted by helical vanes 602. The denser phase (water) is forced to the walls of the separator to exit as water-rich stream 410. The lighter oil phase remains in the center portion of the chamber toexit as where it leaves separately as oil-rich stream 412. In some instances, separator 600 may be a powered unit in which helical vanes 602 are rotated by an electrical or hydraulicly driven motor.

[0033] Flow from drilling string 200 can additionally or alternatively be supplied into the annulus from one or multiple tubes in the drilling string 200 that open to the annulus above the BHA 210. One or more of the tubes are coupled to the BHA for supplying drilling fluid to the BHA and drilling bit, and one or more of the tubes can be open to the annulus and be configured to release the fluid into the annulus at one or multiple locations along the length of the drilling string 200, much like the diverter tools 204 discussed above. The opening of these tubes into the annulus, as the drilling string 200 is assembled, can be the same as described for the diverter tools (e.g., within 1000 m of surface, in the surface wellbores 120, 130, based on the residency time needed to cool the annulus fluid, etc.). Because these one or more tubes configured to release fluid into the annulus are separate from the tube or tubes supplying drilling fluid to the BHA, they can supply the drilling fluid and / or one or more other fluids, e.g., cooling fluids, into the annulus. If multiple tubes are provided to supply fluid into the annulus, different fluids can be released into the annulus at different locations along the drilling string 200. Thus, the number, the configuration of multiple tubes in the drilling string 200, the fluids in each of the tubes, and where along the drilling string 200 the tubes introduce flow into the annulus can be selected based on specified maximum temperature of the annulus fluid, discussed above.

[0034] In particular, FIG. 4 shows an end cross-sectional view of example tubing 802 constructed of multiple bundled tubes 804 within a protective sheath 806 that can be used as drilling string 200 (FIGS. 2A-2B). Such multiple tubes 804 enable flowing different fluids through different tubes 804, while maintaining the fluids separate. Furthermore, the tubes 804 can have different destinations within the drilling string, enabling different fluids to be directed to different locations along the wellbore.

[0035] FIG. 4 shows five tubes 804 bundled around a cable 808, although fewer or more tubes could be provided and, in certain instances, the cable 808 can be omitted. In certain instances, the cable 808 can be a support cable configured to support the full weight of the drilling string, including BHA, and other tension loads, such as during manipulating and running the tubing 802 in / out of the wellbore, without needing contribution from the remaining aspects of the tubing 802. In certain instances, the support cable carries just a portion of the tension loads, and the remainder are carried by the other aspects of the tubing802. In certain instances, the support cable can be periodically anchored to the other aspects of the tubing 802, so as to support these other aspects. The support cable can be stranded (as shown) or solid, and may be metallic (e.g., steel, titanium, aluminum and / or another metallic material) or non-metallic (e.g., carbon fibers, aramid fibers, fiberglass, e-glass, polymer fibers and / or another non-metallic material).

[0036] In certain instances, cable 808 can be or include an umbilical cable that has one or multiple electrical, fiber optic, hydraulic and / or other type of lines, and when multiple lines are provided within the umbilical cable, multiple different types of lines can be included. In certain instances, the umbilical cable supplies electrical power and / or communications, such as control signals, data, and / or other communications to components in the drilling string, including in the BHA.

[0037] The tubes 804 can be bundled at the time of manufacture and brought to the drill site bundled together or brought to the drill site as separate tubes 804 and bundled on site before and / or as the drilling string is run into the wellbore. The tubes 804 can be jointed tubing or coiled tubing. In the case of coiled tubing, bundling the tubes 804 at the drill site enables transporting the spools of the individual tubes 804 rather than spools of the bundled tubes 804. The spools of individual tubes 804 will be smaller diameter for a given length than a spool of the bundled tubes 804. Such smaller diameter spools are easier and less expensive to transport, particularly if transported by road, which has payload width and height restrictions.

[0038] In certain instances, the individual tubes 804 are steel, titanium, aluminum, polymer, fiber resin composite (e.g., carbon fiber, aramid fiber, fiberglass) and / or another material. Different individual tubes 804 in a bundle can be different materials. Some or all of the individual tubes 804 can be provided with an interior and / or exterior insulative coating (such as the coatings described above), and different tubes 804 can have different coatings. The bundled tubing 802 is shown including a protective tubing, as sheath 806. Not only can the sheath 806 maintain the individual tubes 804 together, the sheath 806 can be configured to endure the abrasion and impact of running the bundled tubing 802 through the wellbore and abrasive drilling fluids. Thus, the individual tubes 804 need not be steel or another material selected to withstand the abrasion and impact, or if the tubes 804 are covered in an insulative coating, the coating need not be designed to withstand the abrasion and impact. For example, the sheath 806 enables using polymer or fiber composite materials having properties selected for their thermal resistance over endurance to abrasion and impact. Incertain instances, the sheath 806 is steel or aluminum, polymer (e.g., thermoplastic), composite or another material. In certain instances, the sheath 806 is 0.25” steel or aluminum.

[0039] In other instances, the bundled tubes 804 can be provided without the sheath 806 and clamped together with ring clamps, bonded with adhesive, welded and / or otherwise maintained together.

[0040] In certain instances, the individual tubes 804 can all be the same size or one or more can be different sizes, selected based on the relative fluid flow rates through the tubes 804. Although any sizes of individual tubes 804 are within the concepts herein, in certain instances, the individual tubes 804 can be standard, commercially available tubing sizes (e.g., 1”, 1.25”, 1.5”, 1 / 75”, 2”, 2.375”, 2.625”, 2.875” outer diameter). In certain examples, the bundled tubing 802 includes size 2” outer diameter / 1.8” inner diameter individual tubes 804 around a 2” umbilical cable 808. Such a configuration would have a flow area equivalent to a 4.4” diameter single tubing, and provide sufficient hydraulic flow capacity for drilling an 8.5” wellbore. The flow area would be greater than that of a standard 4” coiled tubing, while being yet easier to transport to the drill site.

[0041] In certain instances, or more of the tubes 804 can be coupled to the drilling bit (e.g., bit 208) and used to flow a drilling fluid from the terranean surface and out through the bit into the wellbore being drilled, while one or more than one of the remaining tubes 804 can be open to the annulus surrounding the drilling string at one or more locations above the BHA (e.g., BHA 210) to flow a cooling fluid into the annulus around the drilling string above the BHA 210. The tubes 804 can be open to the annulus, for example by stopping short of the BHA 210 or by having one or more ports through a sidewall of the tube 804 above the BHA 210. Different of the tubes 804 can be open to the annulus at different locations along the drilling string to allow release of the cooling fluid at different locations, much like the multiple fluid diverters discussed above. Moreover, the multiple tubes 804 allow different fluids with different properties (e.g., different thermal properties such as heat capacity and conductivity, different density, different lubricity and / or other properties) to be directed to different locations, as well as at different flow rates, by flowing the different fluids through selected ones of the tubes 804.

[0042] Although described as parallel bundled tubes 804, in other instances one or more of the tubes 804 could be within another of the tubes 804. For example, the tube(s) 804 destined to supply fluid to the BHA could be within a larger tube 804 that stops short of theBHA and / or has ports, enabling the larger tube 804 to release fluid into the annulus to cool the annulus fluid.

[0043] Another temperature control technique that can be employed alone or together with any of the techniques above can include maintaining the annulus fluids in enclosed surface piping, such as is done for managed pressure drilling, and maintaining the annulus fluids within the wellbore and in this surface piping at a pressure selected to prevent flashing and to keep workers near the piping protected from the hot fluids within. Such surface piping could route the fluid to be cooled at the terranean surface, after exiting the annulus and prior to cuttings removal (and any other treatment) and reinjection into the drilling string 200. The cooling can be accomplished via a cooler 230 (FIGS. 2A and 2B) 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.

[0044] The term “uphole” as used herein means in the direction along a wellbore from its distal end towards the surface, and “downhole” as used herein means the direction along a wellbore from the surface towards its distal end. A downhole location means a location along a wellbore downhole of the surface.

[0045] While this disclosure contains many specific implementation details, these should not be construed as limitations on the subject matter or on what may be claimed, but rather as descriptions of features that may be specific to particular implementations. Certain features that are described in this disclosure in the context of separate implementations can also be implemented, in combination, or 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 suitable 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, be excised from the combination, and the claimed combination may be directed to a sub-combination or variation of a sub-combination.

[0046] Particular implementations of the subject matter have been described. Nevertheless, it will be understood that various modifications, substitutions, and alterations may be made. 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 (someoperations may be considered optional), to achieve desirable results. Accordingly, the previously described example implementations do not define or constrain this disclosure.

Claims

What is claimed is:

1. A method, comprising: supplying fluid from a drilling string residing in a wellbore into an annulus between the drilling string and the wellbore based on a specified maximum temperature of the fluid at aterranean surface; and cooling the fluid in the annulus to at least the specified maximum temperature before the fluid exits the wellbore to the terranean surface.

2. The method of claim 1, where supplying fluid from a drilling string comprises supplying fluid through a diverter in the drilling string into the annulus.

3. The method of claims 1 or 2, where supplying fluid from a drilling string comprises supplying fluid through a fluid separator in the drilling string into the annulus.

4. The method of claim 3, where supplying fluid through a fluid separator comprises supplying a water rich fluid into the annulus and supplying an oil rich fluid through the drilling string below the fluid separator.

5. The method of claim 1, where supplying fluid from a drilling string comprises supplying fluid from one of multiple tubes of the drilling string into the annulus from an opening in the tube uphole from a bottom hole assembly of the drilling string.

6. The method of any one of claims 1 to 5, where supplying fluid from a drilling string comprises supplying fluid from the drilling string into the annulus at 1000 m or less from the terranean surface while a bottom of the drilling string is at a total depth of greater than 1000 m.

7. The method of any one of claims 1 to 6, comprising maintaining the fluid that exits the wellbore at the terranean surface in piping at the terranean surface until flowed into a cooler.

8. The method of any one of claims 1 to 7, where the specified maximum temperature is 80° C.

9. The method of any one of claims 1 to 7, where the specified maximum temperature is selected based on an ambient atmospheric pressure at a wellsite where the wellbore is being drilled.

10. The method of any one of claims 1 to 7, where the specified maximum temperature is below atemperature at which the fluid can flash to vapor at 101.325 kPa.

11. A method, comprising: drilling a geothermal well from a terranean surface into a geothermal subterranean zone; and while drilling the geothermal well, cooling fluid returned to the terranean surface through a wellbore of the well to a specified temperature below which the fluid can flash to vapor at ambient atmospheric conditions at the terranean surface.

12. The method of claim 11, comprising supplying the fluid through a drilling string into an annulus between the drilling string and a wellbore of the well being drilled, the fluid being supplied based on the specified temperature; and cooling the fluid in the annulus to at least the specified temperature.

13. The method of claim 12, where supplying the fluid through a drilling string into an annulus comprises diverting fluid from within the drilling string into the annulus at multiple locations above a bottom hole assembly of the drilling string.

14. The method of claim 12, where supplying the fluid through a drilling string into an annulus comprises separating the fluid into a water rich fluid and an oil rich fluid and supplying the water rich fluid from the drilling string into the annulus at a location above a bottom hole assembly of the drilling string and supplying the oil rich fluid to the bottom hole assembly.

15. The method of claim 12, where supplying the fluid through a drilling string into an annulus comprises supplying the fluid from one of multiple tubes of the drilling string into the annulus from an opening in the tube uphole from a bottom hole assembly of the drilling string.

16. The method of claim 12, where supplying fluid from a drilling string into an annulus comprises supplying fluid from the drilling string into the annulus at 1000 m or less from the terranean surface while a bottom of the drilling string is at a total depth of greater than 1000 m.

17. The method of any of claims 11 to 16, where the specified temperature is 100° C or lower.

18. The method of any of claims 11 to 17, where the specified temperature is 80° C or lower.

19. The method of any of claims 11 to 18, where the Earth surrounding the drilling string is at a temperature greater than 200° C.

20. The method of any of claims 11 to 18, where the fluid comprises a drilling fluid.

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