Spiral drilling mode for formation of wellbores

Abstract

Methods for forming wellbore systems and wellbore systems include drilling a borehole through a formation using a bottomhole assembly having a disintegrating device and a steering system to form a thermal exchange portion of the wellbore system, wherein the drilling is controlled to form the borehole having a trajectory through the formation that has a radius of curvature about a centerline. Thermal exchange wellbore systems include an injection portion extending from an injection system into a formation, a production portion extending from a production system into the formation, and a thermal exchange portion extending between the injection portion and the production portion to define a fluid circuit through the formation within a borehole defined by the injection portion, the thermal exchange portion, and the production portion. The thermal exchange portion comprises a borehole section having a spiral path about a central axis.

Description

65DDR-510201-WO-2 (INT1029PCT) SPIRAL DRILLING MODE FOR FORMATION OF WELLBORES CROSS REFERENCE TO RELATED APPLICATIONS This application claims the benefit of an earlier filing date from U.S. Provisional Application Serial No.63 / 562,286 filed March 07, 2024, the entire disclosure of which is incorporated herein by reference. BACKGROUND

[0001] Geothermal power generation can provide several advantages over other types of power generation. For example, geothermal energy can be more environmentally friendly than conventional fuel sources. Geothermal energy can be a source of renewable energy. The number of exploitable geothermal resources will increase with ongoing research and development in the industry. Geothermal energy is a sustainable source of energy that can be consistently available unlike some other renewable energy sources (e.g., wind and solar power). Geothermal energy can be a reliable source of energy and it can be easier to predict the power output from a geothermal plant with a high degree of accuracy. No additional fuel may be required for geothermal energy. New technologies are being created to improve the energy process because of the increase in exploration for geothermal energy. Geothermal energy production can result in much lower pollution levels as compared to fossil fuels.

[0002] Geothermal systems may be configured with hydraulic stimulation between two or more wells that are arranged in proximity to each other and fluidly coupled through a formation or a joining section of well. A first well may be used to inject a fluid into a formation or injection well, and the fluid may flow through fractures and other fluid paths or through a joining section of well to enter into one or more other wells that are adjacent the injection well (e.g., production wells) that direct the fluid to the surface. In other geothermal system configurations, a single wellbore may be drilled that is a continuous wellbore. For example, a single drilling of a wellbore from the surface through a formation and back to surface may be employed, or two separate wellbores may be drilled and joined together downhole to create a complete circuit. In either case, a looping system may be formed where a fluid is injected into a wellbore and / or formation from an injection well or section of wellbore at the surface and the fluid is thermally treated by the subsurface formation(s) (directly or indirectly) and then returned to the surface through one or more production wells or sections of wellbore. As such, the borehole through a downhole formation may operate as a thermal exchange system as the fluid is pumped there through.65DDR-510201-WO-2 (INT1029PCT)

[0003] In current geothermal systems, for example, multiple wellbores may be arranged in parallel orientation relative to each other. One or more of the parallel wellbores may be arranged as injection wells that are configured to supply a working fluid into a formation or through a borehole formed in the formation such that the working fluid picks up heat from the formation. Direct heat pickup may be achieved by passing the working fluid through fractures within the formation whereas indirect heat pickup may be achieved by thermal exchange between the working fluid within a borehole (lined or unlined) and the surrounding formation. In current system, multiple wellbores are arranged in parallel to each other to increase the heat / power generation provided by the wellbore system. It may be advantageous to develop systems that increase the heat exchange between the working fluid and the surrounding formation. SUMMARY

[0004] Methods for forming wellbore systems and wellbore systems are described. The methods include drilling a borehole through a formation using a bottomhole assembly having a disintegrating device and a steering system to form a thermal exchange portion of the wellbore system. The drilling is controlled to form the borehole having a trajectory through the formation that has a radius of curvature about a centerline.

[0005] Thermal exchange wellbore systems are described. The thermal exchange wellbore systems include an injection portion extending from an injection system into a formation, a production portion extending from a production system into the formation, and a thermal exchange portion extending between the injection portion and the production portion to define a fluid circuit through the formation within a borehole defined by the injection portion, the thermal exchange portion, and the production portion. The thermal exchange portion comprises a borehole section having a spiral path about a central axis. BRIEF DESCRIPTION OF THE DRAWINGS

[0006] The following descriptions should not be considered limiting in any way. With reference to the accompanying drawings, like elements are numbered alike:

[0007] FIG.1 depicts a schematic illustration of a wellbore operation system that may be used to form wells in accordance with embodiments of the present disclosure;

[0008] FIG.2 depicts a block diagram of a processing system, which can be used for implementing embodiments of the present disclosure;65DDR-510201-WO-2 (INT1029PCT)

[0009] FIG.3 is a schematic illustration of a wellbore system in accordance with an embodiment of the present disclosure;

[0010] FIG.4A is a schematic illustration of a wellbore system in accordance with another embodiment of the present disclosure;

[0011] FIG.4B is a schematic illustration of a portion of the wellbore system of FIG. 4A having an additional roll with a helical wellbore; and

[0012] FIG.5 is a schematic illustration of a wellbore system in accordance with another embodiment of the present disclosure. DETAILED DESCRIPTION

[0013] A detailed description of one or more embodiments of the disclosed apparatus and method are presented herein by way of exemplification and not limitation with reference to the Figures. Modern bottomhole assemblies (BHAs) are composed of several distributed components, such as sensors and tools, with each component performing data acquisition and / or processing of a special purpose. During a drilling operation, sensors and detectors may be used to determine the nature of a surrounding formation and / or for controlling directional drilling through the formation.

[0014] FIG.1 illustrates an embodiment of a drilling system 100 for forming a portion of a geothermal system, which may include two or more downhole boreholes for injection and production operations. The drilling system 100 includes a borehole string 102 that is shown disposed in a well or borehole 104 that penetrates at least one earth formation 106 during a drilling operation. As described herein, “borehole” or “wellbore” refers to a hole that makes up all or part of a drilled well. It is noted that the borehole 104 may include vertical, deviated, and / or horizontal sections, and may follow any suitable or desired path. As described herein, “formations” refer to the various features and materials (e.g., geological material) that may be encountered in a subsurface environment (e.g., surrounding the borehole 104 and the material removed during drilling).

[0015] The borehole string 102 is operably connected to a surface structure or surface equipment such as a drill rig 108, which includes or is connected to various components such as a surface drive 110 (also referred to as top drive) and / or rotary table 112 for supporting the borehole string 102, rotating the borehole string 102, and lowering string sections or other downhole components into the borehole 104. In one embodiment, the borehole string 102 is a drill string including one or more drill pipe sections 114 that extend downward into the borehole 104 and is connected to one or more downhole components (downhole tools), which65DDR-510201-WO-2 (INT1029PCT) may be configured as a bottomhole assembly (BHA) 116. The BHA 116 may be fixedly connected to the borehole string 102 such that rotation of the borehole string 102 causes rotation of the BHA 116.

[0016] The BHA 116 includes a disintegrating device 118 (e.g., a drill bit), which in this non-limiting, illustrative configurations is driven from the surface, but may be driven from downhole (e.g., by a downhole mud motor). The drilling system 100 may include components to facilitate circulating fluid 120, such as drilling mud, through an inner bore of the borehole string 102 and an annulus between the borehole string 102 and a wall of the borehole 104. For example, in this illustrative embodiment, a pumping device 122 is located at the surface to circulate the fluid 120 from a mud pit or other fluid source 124 into the borehole 104 as the disintegrating device 118 is rotated (e.g., by rotation of the borehole string 102 and / or a downhole motor).

[0017] In the illustrative embodiment shown in FIG.1, the drilling system 100 includes a steering assembly 126 configured to steer or direct a section of the borehole string 102 and the disintegrating device 118 along a selected path. The steering assembly 126 may have any configuration suitable to direct or steer the drill string 102. Examples of steering assemblies include, without limitation, steerable motor assemblies (e.g., bent housing motor assemblies), whipstocks, turbines, and rotary steerable systems.

[0018] In one non-limiting embodiment, the steering assembly 126 is configured as a rotary steering assembly forming the BHA 116 or part of the BHA 116. The steering assembly 126 includes a non-rotating or slowly-rotating sleeve 128 that includes one or more radially extendable pads 130 (extendable in a direction perpendicular to a longitudinal axis of the sleeve). The pads 130 may be located at different circumferential locations on the sleeve 128 and are adjustable individually or in combination to deflect the disintegrating device 118 by engaging the wall of the borehole 104.

[0019] The drilling system 100 may also include a controller configured to operate or control operation of the pads 130 based on directional information derived from directional sensors located in the BHA 116 and / or the borehole string 102. The directional sensor(s) may be arranged at, in, or near the steering assembly 126. The directional sensor(s) can include one or more gyroscopes (e.g., gyroscope sensors or rotation rate sensors), and also include one or more magnetometers (i.e., magnetic field sensors) and / or one or more accelerometers (e.g., acceleration sensors and / or gravitational sensors).

[0020] In one embodiment, the drilling system 100 includes one or more sensor assemblies 132 configured to perform measurements of parameters related to position and / or65DDR-510201-WO-2 (INT1029PCT) direction of the borehole string 102, the disintegrating device 118, and / or the steering assembly 126. As shown in FIG.1, the sensor assemblies 132 may be located at one or more of various locations, such as on the sleeve 128, at or near the disintegrating device 118, and / or on other components of the borehole string 102 and / or the BHA 116. For example, a sensor assembly 132 can be located on one or more stabilizer sections 134 of the steering assembly 126. The sleeve 128 may be coupled to the borehole string 102 by a bearing assembly or other mechanism that allows rotation of the sleeve independent of the rotation of the borehole string, as will be appreciated by those of skill in the art. The sensor assembly 132 can include one or more sensors that may be configured to sample at different rates (e.g., 1000 samples per seconds, etc.) and synchronized at different tolerances with respect to time accuracy. The signals may contain different signals at different frequencies and amplitudes depending on their sample rate and applied filters.

[0021] One or more downhole components and / or one or more surface components may be in communication with and / or controlled by a processor such as a downhole processing unit 140 and / or a surface processing unit 142. The downhole processing 140 may be parts of the BHA 116 or may be otherwise arranged on or part of or disposed on the borehole string 102. The surface processing unit 142 (and / or the downhole processing unit 140) may be configured to perform functions such as controlling drilling and steering, controlling the flow rate and pressure of the fluid 120, controlling weight on bit (WOB), controlling rotary speed (revolutions per minute (RPM)) of the rotary table 112 or the surface drive 110, transmitting and receiving data, processing measurement data, and / or monitoring operations of the drilling system 100. The surface processing unit 142, in some embodiments, includes an input / output (I / O) device 144 (such as a keyboard and a monitor), a processor 146, and a data storage device 148 (e.g., memory, computer-readable media, etc.) for storing data, models, and / or computer programs or software that cause the processor to perform aspects of methods and processes described herein.

[0022] In one non-limiting embodiment, the surface processing unit 142 is configured as a surface control unit which controls various parameters such as rotary speed, weight-on- bit, fluid flow parameters (e.g., pressure and flow rate), and other parameters or aspects of the drilling system 100. The downhole processing unit 140, in some embodiments, may be a directional measurement controller or other processing device that controls aspects of operating the sensor assemblies 132, acquiring measurement data, and / or estimating directional parameters. The downhole processing unit 140 may also include functionality for controlling operation of the steering assembly 126 and / or other downhole components,65DDR-510201-WO-2 (INT1029PCT) assemblies, or systems. In one non-limiting embodiment, the methods and processes described herein may be performed in the downhole processing unit 140 located within the borehole string 102 or the BHA 116.

[0023] It is understood that embodiments of the present disclosure are capable of being implemented in conjunction with any other suitable type of computing environment now known or later developed. For example, FIG.2 depicts a block diagram of a processing system 200 (e.g., surface processing unit 142 and / or downhole processing unit 140 of FIG. 1), which can be used for implementing the techniques described herein. In examples, the processing system 200 has one or more central processing units 202a, 202b, 202c, etc. (collectively or generically referred to as processor(s) 202 and / or as processing device(s) 202). In aspects of the present disclosure, each processor 202 can include a reduced instruction set computer (RISC) microprocessor. The processor(s) 202, as shown, are coupled to system memory (e.g., random access memory (RAM) 204) and various other components via a system bus 206. Read only memory (ROM) 208 is coupled to the system bus 206 and can include a basic input / output system (BIOS), which controls certain basic functions of the processing system 200.

[0024] Further illustrated in FIG.2 are an input / output (I / O) adapter 210 and a network adapter 212 coupled to the system bus 206. The I / O adapter 210 can be a small computer system interface (SCSI) adapter that communicates with a memory, such as a hard disk 214 and / or a tape storage drive 216 or any other similar component(s). The I / O adapter 210 and associated memory, such as the hard disk 214 and / or the tape storage device 216, may be collectively referred to herein as a mass storage 218. An operating system 220 for execution on the processing system 200 can be stored in the mass storage 218. The network adapter 212 may be configured to interconnect the system bus 206 with an outside network 222 enabling the processing system 200 to communicate with other systems and / or remote systems (e.g., internet, extranet, and / or cloud-based systems).

[0025] A display (e.g., a display monitor) 224 is connected to the system bus 206 by a display adaptor 226, which can include, for example, a graphics adapter to improve the performance of graphics intensive applications and a video controller. In one aspect of the present disclosure, the adapters 210, 212, and / or 226 can be connected to one or more I / O busses that are connected to system bus 206 via an intermediate bus bridge (not shown), as will be appreciated by those of skill in the art. Suitable I / O buses for connecting peripheral devices such as hard disk controllers, network adapters, and graphics adapters typically include common protocols, such as the Peripheral Component Interconnect (PCI). Additional65DDR-510201-WO-2 (INT1029PCT) input / output devices are shown connected to the system bus 206 via a user interface adapter 228 and the display adapter 226. For example, as shown, a keyboard 230, a mouse 232, and speaker 234 can be interconnected to the system bus 206 via the user interface adapter 228, which can include, for example, a Super I / O chip integrating multiple device adapters into a single integrated circuit.

[0026] In some aspects of the present disclosure, and as shown, the processing system 200 includes a graphics processing unit 236. Graphics processing unit 236 may be a specialized electronic circuit designed to manipulate and alter memory to accelerate the creation of images in a frame buffer intended for output to a display (e.g., display 224). In general, the graphics processing unit 236 is very efficient at manipulating computer graphics and image processing and has a highly parallel structure that makes it more effective than general-purpose CPUs for algorithms where processing of large blocks of data is done in parallel.

[0027] Thus, as configured herein, the processing system 200 includes processing capability in the form of processors 202, storage capability including system memory (e.g., RAM 204 and mass storage 218), input means such as keyboard 230 and mouse 232, and output capability including speaker 234 and display 224. In some aspects of the present disclosure, a portion of system memory (e.g., RAM 204 and mass storage 218) may be configured to collectively store an operating system (e.g., operating system 220) to coordinate the functions of the various components shown in the processing system 200.

[0028] It will be appreciated that the processing system 200 of FIG.2 is presently described as a surface system (e.g., surface processing unit 142 of FIG.1). However, it will be appreciated that similar electronic components may be employed in downhole systems (e.g., as part of a BHA and / or downhole processing unit 140). In such configurations, certain features of the processing system may be omitted. For example, in a downhole BHA system, the user interface components may be omitted. Further, the system bus may be arranged to span multiple different downhole components and the network connection may be a communication means (e.g., mud pulse telemetry, electromagnetic telemetry, acoustic telemetry, wired-pipe telemetry, wired connection, wireless connection, or the like) that is configuration to enable communication between a surface system and the downhole BHA system.

[0029] During the formation of geothermal or hydrothermal systems, two or more wellbores may be drilled to form a thermal heat exchange system for a working fluid pumped through the wellbores. By maximizing the contact surface between the injected working fluid65DDR-510201-WO-2 (INT1029PCT) and the formation, thermal exchange may be maximized. In conventional systems, multiple parallel wellbores are drilled through a formation, where having a greater number of wellbores is used to increase the surface contact area between the formation and the working fluid. However, it may be advantageous to have fewer wellbores while maintaining the same or greater contact area and / or it may be desirable to have greater contact area within a prescribed subsurface volume. The volume may be prescribed by legal arrangements (e.g., land ownership), by geology (e.g., within fault delineated blocks, within a particular thermally advantageous formation, etc.), or the like. In view of this, embodiments of the present disclosure are directed to processes for drilling or otherwise forming wellbores with increased surface area contact with a formation over the same linear distance as a conventional substantially straight wellbore.

[0030] In accordance with embodiments of the present disclosure, improved hydrothermal and / or geothermal wells and methods for forming the same are described. The well systems are formed using directional drilling techniques to create spiral or helical shaped wellbores through a formation. For example, as described herein, drilling wellbores in a helical mode (or spiral mode) along vertical and / or horizontal sections can significantly increase heat production in geothermal wells. Such drilling techniques, as described herein, can be applied to advanced geothermal systems and / or enhanced (or engineered) geothermal systems. Advanced Geothermal Systems (AGS) are deep, large, artificial closed-loop circuits in which a working fluid is circulated and heated by sub-surface rocks through conductive heat transfer, such as through one or more wellbores drilled through one or more subsurface formations. The AGS systems are, in essence, closed-loop heat exchangers that contain the working fluid within a fluid circuit defined within a drilled wellbore. In contrast, enhanced (or engineered) geothermal systems (EGS) is typically configured with two separate wellbores that are arranged substantially parallel or near each other, and a working fluid is pumped into an injection well, flows through fractures and / or a permeable formation, and is extracted and pumped back to the surface through a production well.

[0031] In accordance with embodiments of the present disclosure, a modified “hold” mode is employed where a well or section thereof is drilled and formed with a constant radius of curvature in three-dimensional space (e.g., spiral or helix). As will be appreciated by those of skill in the art, a hold mode is, essentially, a directional drilling mode in which the downhole tool is instructed to hold or maintain inclination (i.e., inclination hold) and / or azimuth (i.e., azimuth hold) constant while drilling ahead. In “conventional drilling” when transitioning from the vertical (e.g., zero inclination) to the horizontal (e.g., approximately 9065DDR-510201-WO-2 (INT1029PCT) degrees of inclination) steering forces are applied to deliver a constant radius of curvature. There may also be a change in azimuth (e.g., a turn) if required. In order to drill a helix or spiral wellbore path, a constant radius of curvature in three-dimensions (3-D) is needed. As such, in accordance with embodiments of the present disclosure, a steering force is applied that delivers a 3-D helical well path, about a centerline. That is, in accordance with embodiments of the present disclosure, a drilling mode that is implemented in a BHA (e.g., a rotary steerable system (RSS)) may be programed to generate or yield a helical wellbore path of constant radius of curvature. The constant radius of curvature, in this drilling operation, is not related to a curve or bend from a vertical section to a horizontal section, but rather is a constant radius of curvature about a centerline or central axis, which results in a spiral or helical wellbore path.

[0032] Referring now to FIG.3, schematic illustrations of a drilling process for forming a spiral or helical wellbore system 300 in accordance with an embodiment of the present disclosure is shown. The wellbore system 300 includes a wellbore 302 that is drilled in a spiral or helical drilling path 304, as illustrated by the dashed arrows in FIG.3. The wellbore 302 may be drilled from the surface using a system and components, such as shown and described above with respect to FIGS.1-2. The spiral shape of the wellbore 302 may be initiated from the surface or may be initiated at a downhole location, such as at the end of a substantially straight section of the wellbore, as indicated at starting location 306. As such, in accordance with some embodiments, the starting location 306 may represent a drill rig (e.g., similar to drill rig 108) located at the surface of the earth. In some such embodiments, the rig may be a slant rig, with the rig having a slanted orientation for insertion into the earth and / or coiled tubing could be used in such configurations. In other embodiments, the starting location may be at the end of a straight section of drilling, which may be formed using normal or conventional drilling techniques, including conventional hold modes. In some such embodiments, the starting location 306 may be representative of a vertical section of wellbore. In other embodiments, the starting location 306 may be representative of a horizontal section of wellbore. As such, it will be appreciated that the starting location 306 is not intended to be limited to a specific location, orientation, and / or configuration.

[0033] As shown in FIG.3, the helical drilling path 304 may be initiated from the starting location 306 to drill a helical wellbore 302. The spiral drilling process along the helical drilling path 304 is a drilling operation having a continuous curvature about a central axis or helix centerline 308. Although subject to various characteristics and properties of a subsurface formation, the intended path of the helical wellbore 302 as formed along the65DDR-510201-WO-2 (INT1029PCT) helical drilling path 304 is to have the formed helical wellbore 302 to be constantly the same distance from the helix centerline 308. That is, in accordance with some embodiments, in a direction normal from the curvature of the path 304 of the wellbore 302 to the helix centerline 308, the distance to the helix centerline 308 is maintained as substantially constant. In other embodiments, the amplitude of the helix (i.e., measured departure from the centerline) may be changed as the drilling operation is performed. In still other embodiments, the pitch of the helix may be changed (i.e., number of wraps per unit length of the centerline). In some embodiments, the amplitude is varied such that it goes to zero in a proscribed (e.g., cyclical) fashion, the end result is a snaking wellbore. It will be appreciated that various combinations of changes may be implemented to achieve the helical or spiral wellbore path about a centerline, without departing from the scope of the present disclosure. In each case, the wellbore or borehole is drilled about a centerline.

[0034] Although illustratively shown with the arrows representing the helical drilling path 304 located at the sides / curves in the illustration, it will be appreciated that the curvature continues along the helix centerline 308 for the length thereof. That is, where the illustration crosses the helix centerline 308, in FIG.3, the helical wellbore 302 is also curved and arranged at substantially the same distance from the helix centerline 308 as the rest of the illustrated helical wellbore 302. In some embodiments, the drilling operation may include varying properties. For example, in some configurations, at least one of varying a distance between the borehole and the centerline (e.g., departure or separation distance), varying a radius of curvature of the borehole about the centerline (e.g., tightness of spiral / helix), and / or varying both a distance and a radius of curvature in a plane through the centerline. As such, a continuously constant curvature helix is not a limiting configuration but rather is an example of one drilling operation to achieve the wellbores described herein.

[0035] The drilling operation performed to drill the helical wellbore 302 may be performed using conventional drill pipe, coiled tubing, or other drilling tool / system. Embodiments that employ coiled tubing may be able to achieve higher radius of curvature and tighter spirals / helixes. The helical wellbore 302 provides for substantially increased contact area between the walls of the wellbore 302 and a surrounding formation as compared to a drilled section that is substantially straight (e.g., that runs along the helix centerline 308). That is, for the same linear length or distance (e.g., from a surface drilling location), the helical wellbore 302 and similar wellbores formed in accordance with the present disclosure, the amount of surface area contact between a working fluid within the helical wellbore 302 may be substantially larger than a linear or straight wellbore extending along the same linear65DDR-510201-WO-2 (INT1029PCT) length or distance. The length of a helix (or helical path) is given by the square root of the circumference of the helix squared plus the rise squared. The rise is the distance between the loops of the helix (the distance along the centerline) To increase the surface area, the number of loops or turns of the helix may be defined, as may the circumference of the helix, which is defined by the allowed or desired dogleg severity. For any given dogleg severity, the increase in surface area will be at least 34% more than the centerline wellbore. However, with a much closer looping of the helical shape, the increase in surface area as compared to a centerline wellbore may be 9x (or about 800% increase in surface area). The separation between loops of the helix may depend on many variables, such as torque and drag while drilling the wellbore, thermal recharge in the reservoir, and so on. Further, based on this, it may be possible to achieve a desired or predetermined amount of surface area contact through embodiments of the present disclosure. That is, predetermined amounts of thermal exchange may be determined for a specific application and the spacing of the loops of the helix may be drilled to achieve such a target. It will be appreciated that any amount of increase in surface area contact (e.g., 10%, 100%, 500%, etc.) over a centerline drilled wellbore may be achieved, based, at least in part, on the closeness of turns or loops of the helical path and on the circumference of the helix path.

[0036] In accordance with some embodiments, the helical wellbore 302 may be drilled with a radius of curvature of 6 degrees per 30 meters, or less. It will be appreciated that any radius of curvature may be selected, such as from close to zero to in excess of 30 deg / 30m, depending on the drilling system used, torque and drag, lithology, etc. It will be appreciated that there may be a practical lower limit of about 2 to 3 deg / 30m because this would result is a long circumference (> 3,600m), although lower deg / 30m may be employed without departing from the scope of the present disclosure. In accordance with some embodiments of the present disclosure, use of relatively smaller BHA configurations (e.g., 8 inches or smaller in diameter) and / or use of coiled tubing which can achieve tighter helical paths (e.g., 45 degrees / 30 m), may be used without departing from the scope of the present disclosure.

[0037] Referring now to FIG.4A, a schematic illustration of part of a wellbore system 400 in accordance with an embodiment of the present disclosure is shown. The wellbore system 400 may be formed using the process described with respect to FIG.3, or variations thereon. The wellbore system 400 illustrates a spiral or helical wellbore 402 formed by a drilling process having a constant radius of curvature drilling path or trajectory. As shown, the helical wellbore 402 is arranged along or about a helix centerline 404. The65DDR-510201-WO-2 (INT1029PCT) helix centerline 404 may include vertical sections, curved sections, and / or horizontal sections along the length thereof, in order to reach desired formations, lithologies, or the like, and to achieve maximum thermal exchange between a working fluid injected through the helical wellbore 402 and a formation through which the wellbore system 400 is formed. As shown, the wellbore system 400 includes a vertical section 406, a horizontal section 408, and a curved section 410 that turns from the vertical section 406 to the horizontal section 408. As shown, the helical path of the wellbore 402 will curve from the vertical section 406 to the horizontal section 408 while maintaining the spiral drilling path about the helix centerline 404 from the vertical section 406, through the curved section 410, and to the horizontal section 408.

[0038] FIG.4B illustrates a portion of the wellbore system 400 having an additional roll built into the drilling operation to produce the helical wellbore 402 having a roll 412. That is, the helical wellbore 402 may include a sub-spiral about a path defined by the helical wellbore 402, which in turn is arranged about the helix centerline 404. Such roll 412 may further increase the total surface area contact between a fluid passed through the helical wellbore 402 and a surrounding formation. To achieve such a roll 412 along the helical wellbore 402, a roll operation may be performed during drilling to add the additional sub- spiral shape to the wellbore 402. It will be appreciated that combinations of sections with roll and without roll may be employed in various wellbore systems formed in accordance with embodiments of the present disclosure.

[0039] In accordance with embodiments of the present disclosure, a process for drilling a spiral or helical wellbore through a formation is provided. The drilling process includes the use of a steering system that employs a constantly varying or constantly changing direction of drilling. The constantly varying or constantly changing direction may be maintained at a constant rate such that a wellbore is drilled in a spiral pattern or path about a helix centerline or central axis. This spiral / helical wellbore shape may substantially increase the surface area of contact between a working fluid (e.g., water, supercritical CO2, etc.) within the helical or spiral wellbore and a surrounding formation. Such geometric shape of the wellbore path allows for greatly increased heat exchange for geothermal wells (e.g., as compared to conventional substantially straight wellbores). As noted, the helical wellbore may be drilled using a modified “hold” mode using a rotary steerable system, which may be part of a BHA or other downhole drilling tool / system. The modified hold mode does not use a constant steering angle and / or direction, but rather uses a time-varying steering angle within a downhole controller. Accordingly, over time, the direction of drilling will be constantly65DDR-510201-WO-2 (INT1029PCT) changing at a predetermined rate to achieve a substantially continuous curvature, while also drilling in a downhole direction (e.g., away from a surface location, whether vertical or horizontal).

[0040] The time-varying steering angle allows for adjustment of the drilling direction over time to build a helical path to be drilled through the formation, which results in the spiral / helical wellbore with increased surface area of contact (for the same axial length compared to a non-helical (straight) wellbore). The wellbore may vary azimuth and inclination such that the wellbore lies in a 2D plane (e.g., a snaking wellbore), or it may vary azimuth and inclination in 3D (e.g., a helical wellbore), or it may vary azimuth and inclination against depth or time (e.g., 4D; a spiraling wellbore).

[0041] The steering operation may be performed using a downhole controller or the like which varies the steering force and / or direction, such that the desired wellbore paths are achieved. In accordance with some embodiments, the helical or spiral trajectory may be achieved using an open-loop process or implementation. In such an open-loop processing, a constantly varying “target” or steering angle may be set, which is varying over time. In such an open-loop configuration, the time-varying drilling trajectory may be set and drilled and may not rely upon feedback obtained downhole. For example, the steering system may be set to vary a steering angle at a constant rate against time, and the drilling rate is kept constant by surface manual control or automatic device (e.g., an Autodriller).

[0042] In other embodiments, a closed-loop drilling operation may be performed to achieve a spiral or helical wellbore path. Such a closed-loop system may rely upon feedback obtained during the drilling operation. Such feedback may be obtained from various sensors and / or systems, which may be located downhole within a BHA, along a drill string, or at the surface. The sensors may be configured to detect and / or monitor weight-on-bit, rate-of- penetration, or the like and / or may be configured to monitor and detect features and / or characteristics of the formation being drilled through, which may provide information to enable adjusting the drilling process to ensure the desired helical path is followed. The obtained sensor data in the closed-loop drilling process may be used to adjust a “varying target” (similar to the open-loop system) based on disturbances that may occur downhole during the drilling operation. As such, downhole disruptions may be adjusted for and the desired spiral / helical path may be maintained without substantial deviation therefrom. For example, in accordance with a non-limiting example, depth information may be downlinked to the steering system or progress through the rock may be measured by the steering system. The steering system may then use such information (e.g., depth) to change a steering angle65DDR-510201-WO-2 (INT1029PCT) such that a helical path is maintained. Various factors or data that may be employed in closed-loop drilling systems, in accordance with embodiments of the present disclosure, may include, but are not limited to, measured depth, North-East-Down (“NED”) position estimate, and drill vector. The NED position estimate is with respect to a 3D coordinate system used while drilling and any feedback control system would require knowledge of where the BHA / bit is located in order to correct deviations. These and other factors and / or information may be used to determine an appropriate correction and ensure that a desired helical or spiral path is maintained.

[0043] The controller steering provided by a downhole system (e.g., bottomhole assembly (BHA), rotary steerable system (RSS), or the like) may include two actuatable elements for achieving the desired drilling trajectory in a spiral about a helix centerline or central axis. The first controllable property is a steering direction and the second is a steering force. These two elements may be adjusted (i.e., direction and / or force) over time, to achieve a constant curvature of radius or radius of curvature (i.e., a spiral or helix). The controllable aspects may be modified based on period and / or frequency of adjustment (e.g., time-varying, depth-varying, etc.). In other configurations, the downhole system may be configured as a push-the-bit steer force system or a point-the-bit steer force system. Further, in some configurations, a helical wellbore path may be drilled using a bent motor assembly, alternating slide and rotary drilling operations to achieve a substantially helical path. As such, it will be appreciated that the specific drilling technique and associated components and tools may be varied without departing from the scope of the present disclosure.

[0044] As noted above, the steering operation of the present disclosure may be referred to as a modified “hold” mode. The steering operation is not directed to a constant target or steering direction, but rather is a time-varying or depth-varying mode of drilling that constantly changes the target / steering direction over time or depth. It is noted that depth- varying steering may be based on measured-depth or true-vertical-depth, as will be appreciated by those of skill in the art. As such, the “hold” of the disclosed systems is related to achieving a constant radius of curvature of a drill path about a central axis of helix centerline. The hold is relative to the curvature about the centerline and is not intended to be a desired single angle or target.

[0045] In accordance with some embodiments of the present disclosure, the drilling operation may be independent of formation characteristics, particularly when forming a closed-loop working fluid circuit. That is, in accordance with some embodiments, no stimulation of the formation is required because the thermal exchange between the working65DDR-510201-WO-2 (INT1029PCT) fluid and the formation may be provided at the borehole walls of the wellbore. Stated another way, being independent of formation characteristics allows for formation of helical or spiral wellbores in any subsurface formation to achieve a heat exchange between a working fluid and a formation, without requiring additional operations, such as stimulation, porosity and / or permeability testing, or the like.

[0046] Referring now to FIG.5, an illustration of a wellbore system 500 in accordance with an embodiment of the present disclosure is shown. The wellbore system 500 includes a wellbore 502 drilled through a formation 504. The wellbore 502 extends into the formation 504 from an injection system 506 through the formation 504 and to a production system 508. The injection system 506 and the production system 508 may be fluidly coupled at the surface 510 (e.g., earth’s surface) by a surface fluid connection 512. Although shown at separate locations at the surface 510, it will be appreciated that the surface systems (injection system 506 and production system 508) may be arranged at a single location, such as within a single facility at the surface. The wellbore 502 and the surface fluid connection 512 define a fluid circuit through which a working fluid may be passed. The working fluid may be water, supercritical carbon dioxide, or other fluid, as will be appreciated by those of skill in the art.

[0047] The wellbore 502 may be drilled and formed using the techniques described above. For example, as shown, the wellbore 502 may include an injection portion 514 that extends into the formation 504 (e.g., subsurface formation) from the injection system 506. The injection portion 514 may include a vertical well or the like and / or may include a helical or spiral path, curves, bends, and / or horizontal sections of wellbore. After the injection portion 514, the wellbore 502 may transition into a spiral or helical thermal exchange portion 516. The thermal exchange portion 516 may be drilled using a BHA or other steering assembly or system that drills using a constantly varying drilling trajectory such that the wellbore 502 spirals about a central axis or helix centerline through the formation 504. The thermal exchange portion 516 may extend in a generally horizontal direction, as shown, and / or may include various curves or vertical portions (defined by the helix centerline, such as shown in FIG.4A), and then connect or transition to a production portion 518. The wellbore 502 returns toward the surface 510 along the production portion 518 to reach the production system 508. In some embodiments, two separate boreholes may be drilled into the formation 504 and joined together at a downhole or subsurface location rather than drilling a single continuous borehole from a single location. That is, in some embodiments, the injection portion 514 may be drilled from a first surface location (e.g., at injection system 506) and the production portion 518 may be drilled from a second surface location (e.g., at65DDR-510201-WO-2 (INT1029PCT) production system 508), and the two drilled boreholes may be joined at a location downhole. In some embodiments, the thermal exchange portion 516 may be drilled from one of the two locations (injection or production location) and joined with a borehole drilled from the other location.

[0048] Upon completion and connection between the production system 508 and the injection system 506, a complete fluid circuit is formed. In operation, a working fluid (e.g., water, supercritical CO2, etc.) may be injected from the injection system 506 into the injection portion 514 of the wellbore 502. The working fluid will flow along the wellbore 502 through the injection portion 514 and the thermal exchange portion 516 where the working fluid will pick up heat from the surrounding formation 504. The heated working fluid may then continue to flow through the wellbore 502 in a direction toward the surface 510 to be received at the production system 508. At the production system 508, the heated working fluid may be used to generate power or provide other work at the surface (e.g., heating, cooling, thermal exchange, steam production, etc.). The used working fluid may then be supplied through the surface fluid connection 512 back to the injection system 506 to complete the fluid circuit. As such, a closed-loop fluid thermal exchange system may be defined by the wellbore system 500.

[0049] As noted, as the working fluid is injected into and through the wellbore 502, the working fluid will be heated by the surrounding formation. In contrast to conventional systems that employ substantially linear wellbores, the wellbore 502, having at least the thermal exchange portion 516, will provide for significant increase in area of contact between the working fluid (direct with a borehole wall or through a casing or liner) and the surrounding formation. This increased contact area increases the efficiency of heat pick up such that the total length of the wellbore 502 may be shorter (relative to a horizontal length) than a conventional straight or linear wellbore. That is, the total path length of the wellbore 502 from the surface 510 at the injection system 506 to the surface 510 at the production system 508 may be substantially longer due to the spiral path the wellbore 502 follows, resulting in an increase in total surface area contact over the same linear length. That is, for the same horizontal (e.g., surface) distance, a helical wellbore will have a greater path length as compared to a centerline drilled (straight) wellbore). As such, even with a linear length defined by a helix centerline or central axis, the spiral path the wellbore 502 takes about the helix centerline will substantially increase the total path length and therefore surface area contact between a working fluid and a relatively hot formation (direct formation contact on borehole walls or through a liner / casing).65DDR-510201-WO-2 (INT1029PCT)

[0050] As illustrated in FIG.5, the injection portion 514 includes a spiral or helical shape. In this non-limiting illustrative configuration, both the thermal exchange portion 516 and the injection portion 514 include a spiral or helical path or trajectory. In other embodiments, the production portion 518 may also be formed to have a helical or spiral trajectory similar to the thermal exchange portion 516 and / or the injection portion 514. Further, in other embodiments, both the injection portion 514 and the production portion 518 may be substantially straight or linear, and the thermal exchange portion 516 may be the only section that includes a helical or spiral path or trajectory.

[0051] The wellbore system may be described as a thermal exchange wellbore system that includes an injection portion or injection borehole that extends from an injection system into a formation. A production portion or production borehole similarly extends from a production system into the formation. A thermal exchange portion or thermal exchange borehole extends between the injection portion and the production portion, downhole, to define a fluid circuit through the formation within a borehole defined by the injection portion, the thermal exchange portion, and the production portion. The thermal exchange portion comprises a borehole section having a spiral path about a central axis which provides for increased thermal exchange between a working fluid within the borehole and the surrounding rock / formation.

[0052] Embodiments of the present disclosure are directed to geothermal and hydrothermal wells drilled having wellbores that are drilled having a spiral or helical path, shape, or trajectory. The spiral or helical wellbore provides for an increase in surface area contact between a working fluid passing through the wellbore and the surrounding formation. The helical wellbore is drilled having a three-dimensional helix or spiral shape as it is formed in the earth. The increase in increased surface contact and thus heat exchange may reduce the number of total wells drilled for a geothermal or hydrothermal system and / or the total length of such wellbore systems may be reduced due to the increased thermal exchange along a defined linear length (e.g., as compared to a wellbore without such spiral path).

[0053] It is noted that the described drilling technique is contrary to conventional drilling techniques. That is, in conventional drilling operations, the operator may intentionally avoid spirals or rolling of the wellbore trajectory as straight wellbores are conventionally considered quality wellbores. In contrast, the drilling techniques described herein are directed to systems where an intentional spiral or helical path is created. That is, in conventional drilling operations, the drilling is performed along a prescribed path. In contrast, embodiments of the present disclosure are directed to drilling operations where the drilling is65DDR-510201-WO-2 (INT1029PCT) around (e.g., helical path) a prescribed path (e.g., helix centerline). Further, in addition to a large spiral or helical path, in some embodiments, additional rolling may be induced to achieve further increase in surface area generation over the same axial length. Such a spiral or helical wellbore can reduce the number of required wellbores, shorten the horizontal length thereof, and / or increase the total thermal exchange between the working fluid and the subsurface formation(s).

[0054] Advantageously, embodiments of the present disclosure provide for improved geothermal and / or hydrothermal systems having improved thermal exchange between a working fluid and subsurface formations which heat the working fluid. The increased thermal exchange may be increased (relative to a conventional borehole path) by increasing the number of turns or loops of the helical path. For example, the increased surface area, and thus increased thermal exchange, may be increased by as little as 5% and as high as 800% or greater, over the same horizontal length. Accordingly, the number of total wellbores may be reduced and / or the efficiency of a system may be increased by implementing systems as shown and described herein. The returned, heated working fluid may be used in power plants for electricity generation and / or for heating / cooling systems at the surface.

[0055] Set forth below are some embodiments of the foregoing disclosure:

[0056] Embodiment 1: A method for forming a wellbore system, the method comprising: drilling a borehole through a formation using a bottomhole assembly having a disintegrating device and a steering system to form a thermal exchange portion of the wellbore system, wherein the drilling is controlled to form the borehole having a trajectory through the formation that has a radius of curvature about a centerline.

[0057] Embodiment 2: The method of any preceding embodiment, further comprising: drilling an injection portion of the wellbore system from a first surface location; and drilling the thermal exchange portion from the injection portion.

[0058] Embodiment 3: The method of any preceding embodiment, further comprising: drilling a production portion of the wellbore system from a second surface location to connect with the thermal exchange portion.

[0059] Embodiment 4: The method of any preceding embodiment, wherein the formed borehole has a helical path and the centerline is a helix centerline.

[0060] Embodiment 5: The method of any preceding embodiment, wherein the drilling of the borehole comprises drilling with a time-varying steering angle.

[0061] Embodiment 6: The method of any preceding embodiment, wherein the drilling of the borehole comprises drilling with a measured-depth-varying steering angle.65DDR-510201-WO-2 (INT1029PCT)

[0062] Embodiment 7: The method of any preceding embodiment, wherein the drilling of the borehole comprises drilling with a true-vertical-depth-varying steering angle.

[0063] Embodiment 8: The method of any preceding embodiment, wherein the drilling comprises at least one of varying a distance between the borehole and the centerline, varying a radius of curvature of the borehole about the centerline, and varying both a distance and a radius of curvature in a plan through the centerline.

[0064] Embodiment 9: The method of any preceding embodiment, further comprising connecting the thermal exchange portion of the wellbore system to an injection system and a production system at the earth’s surface.

[0065] Embodiment 10: The method of any preceding embodiment, wherein the injection system and the production system are located at substantially the same location at the earth’s surface.

[0066] Embodiment 11: The method of any preceding embodiment, wherein the injection system is at a first location and the production system is at a second location different from the first location.

[0067] Embodiment 12: The method of any preceding embodiment, further comprising injecting a working fluid into the thermal exchange portion of the wellbore system to cause the working fluid to pick up heat from the formation.

[0068] Embodiment 13: A thermal exchange wellbore system comprising: an injection portion extending from an injection system into a formation; a production portion extending from a production system into the formation; and a thermal exchange portion extending between the injection portion and the production portion to define a fluid circuit through the formation within a borehole defined by the injection portion, the thermal exchange portion, and the production portion; wherein the thermal exchange portion comprises a borehole section having a spiral path about a central axis.

[0069] Embodiment 14: The system of any preceding embodiment, further comprising a working fluid configured to be injected into the borehole at the injection system and returned at the production system.

[0070] Embodiment 15: The system of any preceding embodiment, wherein the working fluid is supercritical carbon dioxide.

[0071] Embodiment 16: The system of any preceding embodiment, wherein the working fluid is water.

[0072] Embodiment 17: The system of any preceding embodiment, wherein the injection portion comprises a section of borehole having spiral path about a central axis.65DDR-510201-WO-2 (INT1029PCT)

[0073] Embodiment 18: The system of any preceding embodiment, wherein the injection system is fluidly coupled to the production system by a surface fluid connection.

[0074] Embodiment 19: The system of any preceding embodiment, wherein a closed- loop fluid circuit is defined through the injection portion, the thermal exchange portion, the production portion, the surface fluid connection, and back to the injection portion.

[0075] Embodiment 20: The system of any preceding embodiment, wherein the spiral path of the thermal exchange portion has a radius of curvature of 6 degrees per 30 meters or less.

[0076] The use of the terms “a” and “an” and “the” and similar referents in the context of describing the invention (especially in the context of the following claims) are to be construed to cover both the singular and the plural, unless otherwise indicated herein or clearly contradicted by context. Further, it should be noted that the terms “first,” “second,” and the like herein do not denote any order, quantity, or importance, but rather are used to distinguish one element from another. The terms “about”, “substantially” and “generally” are intended to include the degree of error associated with measurement of the particular quantity based upon the equipment available at the time of filing the application. For example, “about” and / or “substantially” and / or “generally” can include a range of ± 8% of a given value.

[0077] The teachings of the present disclosure may be used in a variety of well operations. These operations may involve using one or more treatment agents to treat a formation, the fluids resident in a formation, a borehole, and / or equipment in the borehole, such as production tubing. The treatment agents may be in the form of liquids, gases, solids, semi-solids, and mixtures thereof. Illustrative treatment agents include, but are not limited to, stimulation fluids, acids, steam, water, brine, anti-corrosion agents, cement, permeability modifiers, drilling muds, emulsifiers, demulsifiers, tracers, flow improvers etc. Illustrative well operations include, but are not limited to, hydraulic stimulation, tracer injection, cleaning, acidizing, steam injection, water flooding, cementing, etc.

[0078] While the invention has been described with reference to an exemplary embodiment or embodiments, it will be understood by those skilled in the art that various changes may be made and equivalents may be substituted for elements thereof without departing from the scope of the invention. In addition, many modifications may be made to adapt a particular situation or material to the teachings of the invention without departing from the essential scope thereof. Therefore, it is intended that the invention is not limited to the particular embodiment disclosed as the best mode contemplated for carrying out this invention, but that the invention will include all embodiments falling within the scope of the65DDR-510201-WO-2 (INT1029PCT) claims. Also, in the drawings and the description, there have been disclosed exemplary embodiments of the invention and, although specific terms may have been employed, they are unless otherwise stated used in a generic and descriptive sense only and not for purposes of limitation, the scope of the invention therefore not being so limited.

Claims

65DDR-510201-WO-2 (INT1029PCT) What is claimed is:

1. A method for forming a wellbore system, the method comprising: drilling a borehole through a formation using a bottomhole assembly having a disintegrating device and a steering system to form a thermal exchange portion of the wellbore system, wherein the drilling is controlled to form the borehole having a trajectory through the formation that has a radius of curvature about a centerline.

2. The method of claim 1, further comprising: drilling an injection portion of the wellbore system from a first surface location; and drilling the thermal exchange portion from the injection portion.

3. The method of claim 2, further comprising: drilling a production portion of the wellbore system from a second surface location to connect with the thermal exchange portion.

4. The method of claim 1, wherein the formed borehole has a helical path and the centerline is a helix centerline.

5. The method of claim 1, wherein the drilling of the borehole comprises drilling with a time-varying steering angle.

6. The method of claim 1, wherein the drilling of the borehole comprises drilling with a measured-depth-varying steering angle.

7. The method of claim 1, wherein the drilling of the borehole comprises drilling with a true-vertical-depth-varying steering angle.

8. The method of claim 1, wherein the drilling comprises at least one of varying a distance between the borehole and the centerline, varying a radius of curvature of the borehole about the centerline, and varying both a distance and a radius of curvature in a plan through the centerline.

9. The method of claim 1, further comprising connecting the thermal exchange portion of the wellbore system to an injection system and a production system at the earth’s surface.

10. The method of claim 9, wherein the injection system and the production system are located at substantially the same location at the earth’s surface.

11. The method of claim 9, wherein the injection system is at a first location and the production system is at a second location different from the first location.

12. The method of claim 1, further comprising injecting a working fluid into the thermal exchange portion of the wellbore system to cause the working fluid to pick up heat from the formation.65DDR-510201-WO-2 (INT1029PCT) 13. A thermal exchange wellbore system comprising: an injection portion extending from an injection system into a formation; a production portion extending from a production system into the formation; and a thermal exchange portion extending between the injection portion and the production portion to define a fluid circuit through the formation within a borehole defined by the injection portion, the thermal exchange portion, and the production portion; wherein the thermal exchange portion comprises a borehole section having a spiral path about a central axis.

14. The system of claim 13, further comprising a working fluid configured to be injected into the borehole at the injection system and returned at the production system.

15. The system of claim 13, wherein the working fluid is supercritical carbon dioxide.

16. The system of claim 13, wherein the working fluid is water.

17. The system of claim 13, wherein the injection portion comprises a section of borehole having spiral path about a central axis.

18. The system of claim 13, wherein the injection system is fluidly coupled to the production system by a surface fluid connection.

19. The system of claim 18, wherein a closed-loop fluid circuit is defined through the injection portion, the thermal exchange portion, the production portion, the surface fluid connection, and back to the injection portion.

20. The system of claim 13, wherein the spiral path of the thermal exchange portion has a radius of curvature of 6 degrees per 30 meters or less.

Images