Helical well architecture for enhanced geothermal systems

Abstract

Methods for forming wellbore systems include drilling a helical injection portion of the wellbore system through a formation, the helical injection portion defining a helix centerline, drilling a production portion of the wellbore system through the formation along the helix centerline, and performing a fracturing operation to form a fracture network within the formation and define a fluid connection between the injection portion and the production portion through the fracture network.

Description

65DDR-510199-WO-2 (INT1030PCT) HELICAL WELL ARCHITECTURE FOR ENHANCED GEOTHERMAL SYSTEMS CROSS REFERENCE TO RELATED APPLICATIONS This application claims the benefit of an earlier filing date from U.S. Provisional Application Serial No.63 / 562,291, 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 as a result of increase in exploration. 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 an injection well, and the fluid may flow through fractures and other fluid paths in the formation 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. As such, a looping system may be formed where a fluid is injected into a wellbore from an injection well 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. As such, the borehole through a downhole formation may operate as a thermal exchange system as the fluid is pumped therethrough.

[0003] The application of geothermal power plants has become more versatile and is applicable in different forms and scales. Use of deep geothermal systems may be employed such that the internal heat of the earth in a downhole formation is used as a heating system. Both open-loop and closed-loop geothermal systems exist. An open-loop system passes a65DDR-510199-WO-2 (INT1030PCT) working fluid directly through a formation, whereas a closed-loop system may use a single continuous wellbore through which a working fluid is passed (i.e., the working fluid does not permeate into the downhole formation). Currently, open-loop systems are known as Enhanced Geothermal Systems (EGS), while closed-loop systems are known as Advanced Geothermal Systems (AGS). Another geothermal system is a conventional hydrothermal system, where a formation reservoir contains a volume of heated water that is produced for heat and / or electricity.

[0004] In an open-loop system, the working fluid (e.g., water) may be extracted from a subsurface reservoir by a production well, used as a power source (e.g., hot water for turbine operation), and is then injected through the injection well as cooled fluid back into the formation for heating. Intermediate separators, within a power plant, may be configured to convert the relatively hot liquid (water) into steam to drive a generator turbine, where it cools, and the cooled water is then re-injected into the formation through the injection well. The water will then flow through a fractured or brittle zone of formation from the injection well back to the production well. This system is an open-loop system because the working fluid is directed into and through the material of the formation, such as through fractures, cracks, and brittle zones thereof.

[0005] Such open-loop systems typically are formed from two separate vertical wells with hydraulic stimulation between the two wells to create an artificial reservoir (or increase the fluid pathways in an existing reservoir). The formation of such dual-well systems may require high costs and installation activities because at least one rig mobilization (or use of two separate rigs) may be required between two different well pads to create the injection well and substantially adjacent production well. That is, to provide sufficient distance between the injection and production wells to allow for the heating of the working fluid, the injection and production wells, at the surface, must be separated to achieve a fluid flow from the injection well to the production well, and thereby heat the working fluid. It may be advantageous to improve the installation, formation, and operation of such open-loop hydrothermal and / or geothermal systems. SUMMARY

[0006] Methods for forming wellbore systems include drilling a helical injection portion of the wellbore system through a formation, the helical injection portion defining a helix centerline, drilling a production portion of the wellbore system through the formation along the helix centerline, and performing a fracturing operation to form a fracture network65DDR-510199-WO-2 (INT1030PCT) within the formation and define a fluid connection between the injection portion and the production portion through the fracture network. BRIEF DESCRIPTION OF THE DRAWINGS

[0007] The following descriptions should not be considered limiting in any way. With reference to the accompanying drawings, like elements are numbered alike:

[0008] 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;

[0009] FIG.2 depicts a block diagram of a processing system, which can be used for implementing embodiments of the present disclosure;

[0010] FIG.3 is a schematic illustration of a wellbore system in accordance with an embodiment of the present disclosure;

[0011] FIG.4A is a schematic illustration of a part of a drilling operation for forming a wellbore system in accordance with an embodiment of the present disclosure;

[0012] FIG.4B illustrates a further step of the drilling operation of FIG.4A;

[0013] FIG.4C illustrates a further step of the drilling operation of FIGS.4A-4B;

[0014] FIG.5 is a schematic illustration of a section of a wellbore system in accordance with an embodiment of the present disclosure;

[0015] FIG.6 is a schematic illustration of a wellbore system in accordance with an embodiment of the present disclosure;

[0016] FIG.7 is a flow process for forming and operating a wellbore system in accordance with an embodiment of the present disclosure; and

[0017] FIG.8 is a schematic illustration of a wellbore system in accordance with an embodiment of the present disclosure. DETAILED DESCRIPTION

[0018] 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 bottom hole 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.65DDR-510199-WO-2 (INT1030PCT)

[0019] 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).

[0020] 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), which 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.

[0021] 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).

[0022] 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 steering65DDR-510199-WO-2 (INT1030PCT) assemblies include, without limitation, steerable motor assemblies (e.g., bent housing motor assemblies), whipstocks, turbines, and rotary steerable systems.

[0023] 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.

[0024] 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).

[0025] In one embodiment, the drilling system 100 includes one or more sensor assemblies 132 configured to perform measurements of parameters related to position and / or 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.

[0026] 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 the65DDR-510199-WO-2 (INT1030PCT) 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 (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.

[0027] 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, 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.

[0028] 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 200.65DDR-510199-WO-2 (INT1030PCT)

[0029] 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).

[0030] 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). Additional 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.

[0031] 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.

[0032] 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, and65DDR-510199-WO-2 (INT1030PCT) 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.

[0033] 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, wired connection, wireless connection, or the like) that is configuration to enable communication between a surface system and the downhole BHA system.

[0034] As discussed above, during the formation of conventional geothermal or hydrothermal systems, two or more wells are required. A first well is formed as an injection well to inject a working fluid into and through a formation. A second well is formed a production well to receive the same fluid, as heated by the downhole formation, and return the fluid back to the surface. The two wells, at the surface, may be fluidly coupled to provide for a looping process of the working fluid. The above systems described with respect to FIGS.1 and 2 may be used to drill vertical or horizontal wells. When forming a geothermal system, the two wells are formed substantially adjacent to each other and in substantially the same shape, such that the two formed boreholes may run substantially parallel to each other. Such drilling may be costly, either in moving a rig to drill both wells or by using two drilling rigs in tandem to form the two wells. Either way, the costs associated with the formation of such wells may be high.

[0035] In accordance with embodiments of the present disclosure, improved hydrothermal and / or geothermal wells are described. The well systems are formed using directional drilling techniques to create a two-well system having a single surface pad location for the drilling operation. Further, embodiments of the present disclosure may improve stimulation in hard basement formation and thus improve project economics. These and other benefits and advantages maybe apparent to those of skill in the art. In accordance with embodiments of the present disclosure, single-pad (or single surface location), dual-well65DDR-510199-WO-2 (INT1030PCT) architecture is provided. For example, a vertical production well may be formed and enclosed or surrounded by a helical or corkscrew injection well. Such a formation process can reduce project time, rig time, surface footprint, and overall project costs.

[0036] For example, referring now to FIG.3, a schematic illustration of a geothermal system 300 in accordance with an embodiment of the present disclosure is shown. The geothermal system 300 includes a surface system 302 located at the Earth’s surface 304 that is used to form wellbore system 306 within a formation 308. The wellbore system 306 is formed having a primary portion 310 which for example initially extends to a point where two wellbores may be split apparated (e.g., at a junction 312), or slightly deeper than the location of the junction 312. This primary portion 310 is then split at the junction 312 into an injection portion 314 and a production portion 316. The split at the junction 312 may be caused by an operation such as the installation of a whipstock or the like to cause deviation of the injection portion 314 from the primary portion 310. That is, the injection portion 314 may deviate from a central axis through the primary portion 310, whereas the production portion 316 may continue to extend in a direction along the axis of the primary portion 310.

[0037] The injection portion 314 splits from the primary portion 310 at the junction 312 and is drilled or formed having a helical trajectory or wellpath. That is, the injection portion 314 is a spiral wellbore that is formed in a helical pattern or path extending through the formation 308. The production portion 316 is a substantially axial portion that extends from the primary portion 310 along an axis or centerline defined by the helical injection portion 314. The production portion 316 may be created by extending a wellbore from the junction 312 after drilling of the injection portion 314. That is, the production portion 316 may be formed within or through the helical pattern. Stated another way, the production portion 316 may be formed along a helix central axis or helix centerline 318. The helix centerline 318 is a line through the central region of the helical shape, where each point along the helix is substantially equidistance from the helix centerline 318, and thus the helix centerline 318 defines an axis about which the helical injection portion 314 is drilled. The helical injection portion 314 may be drilled using directional drilling techniques to be formed with a substantially constant radius of curvature in three-dimensions (3-D), thus resulting in the helical shape.

[0038] Once the helical injection portion 314 is formed, a second drilling operation may be performed to drill the production portion 316. The production portion 316 is drilled along the helix centerline 318 such that the production portion 316 is arranged substantially within the helical shape of the injection portion 314 and arranged such that a shortest distance65DDR-510199-WO-2 (INT1030PCT) from the helical injection portion 314 to the production portion 316 is substantially equal for all points on the helical injection portion 314 of the wellbore system 306. To achieve this dual-portion wellbore system 306, the drill string may be pulled from the helical injection portion 314, upon completion thereof, and the same or a different drill string may be used to start drilling the centerline production portion 316 starting at the junction 312. Although shown with a substantially vertical and straight centerline production portion 316, in other configurations, the centerline production portion 316 may include curvature and transition from a vertical wall to a horizontal well. This may be performed when the helical injection portion 314 does not follow a merely vertical path, but rather may be turned to form a helical shape with a substantially horizontal centerline. For example, with reference to FIG.1, as an example, the borehole 104 may represent a centerline production portion that has curved from vertical to horizontal. In such a case, a helical injection well may be drilled around some or all portions of the centerline production portion, similar to that shown in FIG.3.

[0039] As shown in FIG.3, the distal ends 320, 322 of the injection portion 314 and the production portion 316 are not joined together. Further, as discussed above, the injection portion 314 wraps around the production portion 316 in a helical shape, and thus no direct connection is formed between the two portions 314, 316. Accordingly, to achieve a geothermal heat exchange system, a fluid connection must be formed between the injection portion 314 and the production portion 316 such that fluid that is injected into and through the injection portion 314 may pass through the formation 308, pick up heat, and then enter the production portion 316. In some embodiments, a stimulation operation may be performed to fracture the formation 308 surrounding the injection portion 314 such that a fracture network 324 is formed. The fracture network 324 may define cracks and fractures that connect from the injection portion 314 to the production portion 316 and thus may define fluid paths along which a fluid may travel from the injection portion 314 to the production portion 316. It will be appreciated that the illustrative fracture network 324 is merely schematic and that the number, size, orientation, shape and other properties or characteristics of the fracture network 324 may be governed by the state of the formation stress, existing fractures or joints, or other properties and / or characteristics of the specific formation through which the geothermal system 300 is formed.

[0040] Once the injection portion 314 and the production portion 316 are formed and fluidly connected by the fracture network 324, a fluid may be injected into the injection portion 314 and received by the production portion 316 for returning to the surface 304 to thus define a fluid circuit. The fluid circuit, in this configuration, initiates at the surface 304,65DDR-510199-WO-2 (INT1030PCT) such as at a power plant or working fluid source (e.g., reservoir) at or part of the surface system 302. That is, after completion of the drilling and formation of the wellbore system 306 (including the various portions 310, 314, 316) and the fracturing operation performed to form the fracture network 324, a drilling rig or the like may be replaced by a power plant or other system for providing, receiving, and using heated working fluid. In some embodiments, the power plant or other system may be fluidly connected to the wellbore system 306 by surface pipes or the like, and thus the drilling rig may not always be replaced by such a system, but rather both may be located at the surface 304 simultaneously.

[0041] In this configuration, because both the injection portion 314 and the production portion 316 are joined at the junction 312 and share the same primary portion 310, a means for preventing short circuiting of the fluid circuit may be necessary to prevent fluid mixing of a flow intended for the injection portion 314 and a return flow from the production portion 314. Such a means may be a packer 326 or other blockage that is installed below the junction 312. As such, mixing of cold injected fluid and hot returned production fluid may be prevented. For example, the means for preventing a short circuit of the fluid circuit may be the packer 326 that is positioned at a location below the junction 312 along the length of the production portion 316.

[0042] Along the primary portion 310, both an injection flow path and a production return path may be provided within the same borehole. In a non-limiting configuration, the primary portion 310 may be defined by a central solid-walled section that defines an internal passage within the solid-walled section and an external annular passage defined external to the solid-walled section and between the solid-walled section and a wall of the wellbore system 306 (e.g., formation, liner, etc.). The packer 326 may be positioned on the exterior of the solid-walled section of the production portion 316 at a location to prevent the injected fluid from flowing into the production portion 316. As such, the injected fluid, which may be injected into the external annular passage of the primary portion 310 will flow into the helical injection portion 314. The injected fluid will then flow through the fracture network 324 where it will pick up heat before entering the production portion 316 at locations below the packer 326. The structure of the production portion 316 below the packer 326 may be an open hole, a slotted liner, a perforated liner, or other type of structure that is arranged to permit a fluid to enter an open passageway defined by the production portion 316. Such open passageway may be defined by the formation itself or by installed components such as liners or the like. As such, fluid that flows through the fracture network 324 will enter the production portion 316 and may then be pumped uphole through the production portion and65DDR-510199-WO-2 (INT1030PCT) within the solid-walled section of the primary portion 310 that is above the junction 312 and returned to the surface 304.

[0043] Referring now to FIGS.4A-4C, schematic illustrations of a process for forming a dual-well or dual-portion wellbore in accordance with an embodiment of the present disclosure are shown. In FIG.4A, a first part of the formation process of a wellbore system 400 is illustrated. The wellbore system 400 includes a primary portion 402 which is drilled from the surface and may be a vertical section of well or may be a combination of vertical and horizontal sections. It will be appreciated that although the illustrated configuration is “vertical” the specific orientation is not intended to be limiting and the illustrations of FIGS.4A-4C may be used to represent horizontal wellbore system, or a curved section that turns from vertical to horizontal or horizontal to vertical or the like. That is, it will be appreciated that the illustrated configuration is merely provided for explanatory purposes and is not intended to be limiting on the scope of the present disclosure.

[0044] In the first part of formation of the wellbore system 400, as shown in FIG.4A, a helical drilling process 404 may be initiated to drill a helical wellbore or injection portion 406 (FIG.4B), similar to the injection portion 314 shown in FIG.3. The helical drilling process 404 is a drilling operation having a continuous curvature about a central axis or helix centerline 408. Although subject to various characteristics and properties of a subsurface formation, the intended path of the injection portion 406 as formed by the helical drilling process 404 is to have the formed injection portion 406 to be constantly the same distance from the helix centerline 408. That is, in a direction normal from the curvature of the path of the injection portion 406 along the helical drilling process 404 to the helix centerline 408, the distance to the helix centerline 408 is maintained as substantially constant. It will be appreciated that the helical drilling process 404 may result in a substantially helical (i.e., not perfect) wellbore path, and the radius of the helix may vary against depth and / or pitch (separation of loops of the helix). That is, variations in separation distance from the helix centerline 408 may not always be absolutely constant and the angle or pitch of the path may vary, based on various considerations, such as formation properties, drilling requirements and considerations, final system yield, production, and / or efficiency, or the like.

[0045] As shown in FIG.4B, the wellbore system 400 has the injection portion 406 formed by the helical drilling process 404. After completion of the injection portion 406, the production portion 410 is formed by a centerline drilling process 412. In this operation, a second drilling operation is performed to drill a centerline wellbore or the production portion 410 along the helix centerline 408. As such, the production portion 410 is arranged65DDR-510199-WO-2 (INT1030PCT) substantially within and central to the injection portion 406. Also shown in FIG.4B is a production portion return liner or production tubing 414. The production tubing 414 is arranged within the primary portion 402 and provides a fluid separation or barrier between an external annulus 415 for supplying an injected fluid into the injection portion 406 and the production fluids that are returned through the production portion 410 and the production tubing 415 thereof. As shown, a packer 416 or the like may be arranged to prevent injection fluids from flowing into the production portion 410.

[0046] Once the injection portion 406 and the production portion 410 are formed, a fracturing operation may be performed, as shown in FIG.4C. During the fracturing operation, in this illustrative embodiment, one or more fracturing packers 418 or the like may be disposed within the injection portion 406 to allow for a controlled or staged fracturing of the formation around and between the injection portion 406 and the production portion 410. The fracturing operation of FIG.4C will form a fracture network (generally referred to as fracture network 420) that includes first or primary fractures 420a and second or secondary fractures 420b. The first or primary fractures 420a are sections of fractures that extend inward from the injection portion 406 toward and connecting to the production portion 410. The second or secondary fractures 420b extend between different portions or limbs, turns, or other sections of the injection portion 406. In some embodiments, the fracturing packers 418 may be omitted, depending on the fracturing operation used in the formation of the wellbore system 400.

[0047] Although shown and described with the formation of the fracture network 420 after drilling of the production portion 410, in other embodiments these two steps may be reversed. For example, in some embodiments, the drilling of the injection portion 406 is performed. Subsequently, the fracturing operation is performed to generate the fracture network 420. Once the fracture network 420 is formed, the production portion 410 may be drilled along the helix centerline 408. Such order of operation may be used to identify fracture clouds within the subsurface formation that are formed during the fracturing operation. Accordingly, if the production portion 410 may benefit from intersecting a fracture cloud or by avoiding such fracture cloud, drilling of the production portion 410 after the fracturing operation may be preferred. The intersecting or avoiding of such fracture clouds may be intended to ensure a desired rate of flow through a formation from the injection portion 406 to the production portion 410.

[0048] Additionally, although shown and described with the fracturing operation being performed from the injection portion 406, in other embodiments, the fracturing65DDR-510199-WO-2 (INT1030PCT) operation may be performed from the production portion 410 or a combination of the injection portion 406 and the production portion 410. Furthermore, staged fracturing, such as by using the fracturing packers 418 (in the injection portion 406 or the production portion 410) may be employed to ensure placement of fractures in target lithologies or in preferential intervals, such as recharge zones or the like.

[0049] Referring now to FIG.5, a schematic illustration of part of a wellbore system 500 in accordance with an embodiment of the present disclosure is shown. The wellbore system 500 may be formed using the process described with respect to FIGS.4A-4C, or variations thereon. The wellbore system 500 illustrates that an injection portion 502 and associated production portion 504 may be vertical, curved, and / or horizontal 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 injection portion 502 and a formation through which the wellbore system 500 is formed. As shown, the wellbore system 500 includes a vertical section 506, a horizontal section 508, and a curved section 510 that turns from the vertical section 506 to the horizontal section 508. As shown, the helical path of the injection portion 502 will curve and a helix centerline will define a similar curved path along which the production portion 504 will be formed.

[0050] Referring now to FIG.6, a schematic illustration of a wellbore system 600 in accordance with an embodiment of the present disclosure is shown. In the wellbore system 600, an injection portion 602 and a production portion 604 are both formed, similar to that shown and described above. However, in this embodiment, rather than being drilled from the same location, and thus having a primary portion as shown and described above, in this embodiment, the injection portion 602 and the production portion 604 are each drilled from separate or different locations at the surface 606. For example, as shown, a surface injection system 608 may be arranged at a first location on the surface 606 and a separate surface production system 610 may be arranged at a second location on the surface 606 difference from the first location. However, the resulting wellbore system 600 is substantially similar to that shown and described above, with the production portion 604 arranged along a helix centerline within the injection portion 602. A fracture network 612 may similarly be formed to provide a fluid path through an earth formation from the injection portion 602 to the production portion 604.

[0051] Referring now to FIG.7, a flow process 700 for forming a wellbore system in accordance with an embodiment of the present disclosure is shown. The flow process 700 may be used to form the various types of wellbore systems shown and described above (e.g.,65DDR-510199-WO-2 (INT1030PCT) as shown in FIGS.3, 4A-4C, 5, and 6). The formed wellbore system, as generated by the steps of the flow process 700, is a geothermal wellbore system that includes at least two distinct and fluidly separate portions (with respect to drilling) that are fluidly connected or coupled through fractures within an earth formation. Upon completion of the various portions of the wellbore system, fluid may be pumped into or injected into an injection portion, the fluid will then flow through the fractures to the production portion, and the fluid will then be produced back to the surface by pumping or the like. As the fluid passes through the formation, the fluid will pick up heat from the formation and thus the returned fluid will be warmer than the injected fluid and may be used for power generation or the like.

[0052] At block 702, a helical injection portion of the wellbore system is drilled. The drilling may be performed using a drilling rig or other system for forming wellbores within subsurface formations. The drilling of the injection portion, at block 702, will be completed using a steerable tool that drills in a continuously changing direction to form a helix shape within the formation. As such, the drilling is performed to both curve the trajectory while also increasing a distance from the surface system (e.g., the rig). The increased distance may be a vertical distance (e.g., vertical well) and / or a horizontal distance (e.g., horizontal well). The helical injection portion is drilled such that a helix centerline is defined within the helix shape of the drilled wellbore. As noted, the drilling is performed with a continuously changing drilling direction such that a substantially constant and continuous curvature is achieved. In some embodiments, the helical injection portion may be started from a primary portion which may be a vertical (and / or horizontal) section of drilling. That is, the helix shape of the helical injection portion may start at the surface or may be initiated at some downhole location some distance from the surface. The helix centerline may have vertical sections, horizontal sections, and curved sections transitioning between vertical and horizontal sections.

[0053] At block 704, a helix-centerline production portion is drilled along a centerline of the helical injection portion. As such, the helical injection portion defines a spiral path or shape around the drilled production portion, with the production portion being substantially equidistant from or centered on / within the injection portion along the length of production portion. As noted, the helical injection portion may include both vertical and horizontal sections. As such, with the production portion following the helix centerline, the production portion may also be formed with both vertical and horizontal sections, such as shown in FIG. 7.

[0054] During the formation of the helical injection portion and the helix-centerline production portion, the two portions of the wellbore are intentionally kept separate such that65DDR-510199-WO-2 (INT1030PCT) the two portions of wellbore do not intersect. In some embodiments, the two portions may share a common primary portion that extends from a surface location, such as shown in FIG. 3, but after the split at a junction, the two portions are maintained as separate from each other such that the drilled path or trajectory of the two portions do not intersect. In other embodiments, the two portions (injection and production) may be maintained separate, including at the surface, such as shown in FIG.6, with respect to the drilled boreholes.

[0055] At block 706, a fracturing operation is performed to fluidly connect the injection portion and the production portion through fractures in the subsurface formation(s). That is, a fracturing fluid is injected into one or both of the injection portion and the production portion to fracture the material of the downhole formation(s) through which the wellbore system is drilled. Fluid paths within the formation(s) may be generated to fluidly connect or fluidly couple the injection portion and the production portion. Other fractures may be formed that fluidly connect or fluidly couple different parts of the helical injection portion together. As such, in some configurations, fluid within a first part of the helical injection portion may flow through the formation to a second section of the helical injection portion.

[0056] The fracturing operation of block 706 is not required to be performed after the formation of both the injection portion and the production portion. For example, in some embodiments, the fracturing operation of block 706 may be performed after formation of the helical injection portion. In such configurations, the fracturing that occurs prior to formation of the production portion may be used to identify fracture clouds within the formation, and thus allow optimization of the structure or arrangement of the production portion which can be configured to pass through or avoid such fracture clouds, depending on the specific needs of the system. As noted, in some embodiments, the fracturing may be performed from the helical injection portion. In other embodiments, the fracturing may be performed from the helix-centerline production portion. In still other embodiments, a combination of fracturing may be achieved from both the injection portion and the production portion. Further, staged fracturing may be performed through use of packers or the like and may allow for placement of fractures in target lithologies or in preferred intervals, such as thermal recharge zones.

[0057] With the injection portion and the production portion formed and fluidly connected by fractures (blocks 702-706), the wellbore system may be prepared for thermal exchange, at block 708. For example, the drilling and / or fracturing tools and components may be removed from the wellbore system, and liners or the like may be installed as necessary. For example, a perforated liner or permeable line may be installed within the production65DDR-510199-WO-2 (INT1030PCT) portion, allowing for fluid to flow from the injection portion, through the fractures in the formation, and then into the production portion. In other embodiments, the production portion may be an open hole with no liner. Various other configurations are possible without departing from the scope of the present disclosure. Similarly, a liner or the like may be installed within the helical injection portion, with orifices or the like for injecting fluid from the injection portion into the surrounding formation and the fractures formed therein.

[0058] Further, as noted above with respect to FIG.3, at block 708 a means for preventing short circuiting of a fluid circuit may be installed at a junction where the injection portion and the production portion separate into distinct wellbore portions. The means for preventing short circuiting of the fluid circuit may be a packer or other installed component or structure (e.g., cemented section around a liner that connects the production portion to the surface within a primary portion of the wellbore. It will be appreciated that such means for preventing short circuiting is not required if the two portions (injection and production) are separated from the surface (e.g., as shown in FIG.6). In accordance with some embodiments, insulation or insulating material may be provided on the production tubing, to reducing the cooling effect of downward travelling injection fluid impacting upward travelling production fluid. Further, although shown and described with an axial production fluid flow in the bore of the pipe, this arrangement could be reversed with annular production flow and injection fluid in the bore. Furthermore, in accordance with some non-limiting examples, smart downhole flow systems may be employes to close and or open fracture systems to balance thermal cooling of the formation and optimize heat production. Additionally, in some configurations, downhole sensor systems may be provided for monitoring heat flow within the stimulated reservoir and / or in the injection and production systems. Other components and / or systems may be included without departing from the scope of the present disclosure.

[0059] At block 710, with the completed wellbore system having an injection portion and a production portion, a working fluid may be injected into the injection portion. The working fluid may be water, supercritical carbon dioxide, or other fluid as will be appreciated by those of skill in the art. The working fluid is selected to be a fluid that can pass through the formed fractures in the formation and pick up heat from the formation as the working fluid flows from the injection portion to the production portion (or between parts of the injection portion). As the working fluid is directed into the injection portion of the wellbore system, the fluid will exit the injection portion through various mechanisms, such as orifices, nozzles, openings in a liner, or the like, as will be appreciated by those of skill in the art. The working fluid will then flow through the fracture network formed at block 706 and pick up65DDR-510199-WO-2 (INT1030PCT) heat as the working fluid flows toward and into the production portion (and / or toward other parts of the injection portion).

[0060] At block 712, the heated working fluid received in the production portion from the injection portion through the fracture network will flow back to the surface or may be pumped back toward the surface. That is, in some configurations, the temperature of the fluid itself may cause the flow to return to the surface (e.g., thermal siphon). In other configurations, a downhole pumping mechanism (e.g., mounted internal to the production well) may be employed to drive the fluid through the circuit. In some configurations, a back pressure may be applied to prevent a hot fluid from flashing within the production string (i.e., preventing steam generation within the downhole system). As such, heated working fluid may be provided back to the surface from downhole or subsurface locations. The heated working fluid may then be used to generate steam or be used in other ways to generate power at the surface or may be used for other purposes. After the heated working fluid is consumed (e.g., heat is extracted therefrom), the cooled working fluid may be reinjected back into the injection portion, and thus block 710 and block 712 may be a cycle of operation, forming a fluid circuit. In some embodiments, one or both of the injection portion and the production portion may be configured to pass through a downhole (e.g., non-potable) aquifer (in the case of water as a working fluid), and this aquifer may be used to thermally recharge or resupply the working fluid with additional volume.

[0061] In the above-described configurations, a single injection portion is arranged about a central production portion. However, such single wellbore portions are not intended to be limiting. For example, referring now to FIG.8, a schematic illustration of a wellbore system 800 in accordance with an embodiment of the present disclosure is shown. The wellbore system 800 may be substantially similar to the above-described embodiments, including injection portions and production portions. However, in this embodiment, the wellbore system 800 includes two injection portions 802, 804, which share a common central axis or centerline. Arranged along the common central axis or centerline of the two injection portions 802, 804 is a production portion 806. The injection portions 802, 804 and the production portion 806 may be fluidly connected or coupled through primary fractures 808 of a fracture network. Further, secondary fractures 810 may fluidly connect or couple the two separate injection portions 802, 804, allowing for the working fluid to pick up heat as it passes through the formation from one injection portion 802 to the other injection portion 804 (or vice versa). The wellbore system 800 will otherwise function substantially the same as the above-described embodiments.65DDR-510199-WO-2 (INT1030PCT)

[0062] In the configuration of FIG.8, the wellbore system 800 includes two injection portions 802, 804 and one production portion 806. In other embodiments, more than two injection portions may be employed. Furthermore, in some embodiments, multiple parallel production portions maybe formed and arranged along the helix centerline or central axis, allowing for increased volume to be passed through the fluid circuit. As such, the present disclosure is not intended to be limited to a single injection portion and / or a single production portion, but rather multiples of either or both may be implemented without departing from the scope of the present disclosure.

[0063] Furthermore, although shown and described herein with the production wellbore being a substantially straight wellbore, such geometry is not intended to be limiting. Rather, the production wellbore is defined as a wellbore drilled and formed along an axis of a spiral or helical injection wellbore. Accordingly, in some configurations, the production wellbore may include curves, turns, vertical sections, horizontal sections, or even spiraled sections.

[0064] Embodiments of the present disclosure are directed to geothermal and hydrothermal wells drilled having two (or more) wellbores or wellbore portions that are drilled relative to each other, but not directly connected. A spiral or helical wellbore portion is drilled having a three-dimensional helix or spiral shape as it is formed in the earth. The helical wellbore may be used as an injection portion for injecting a working fluid into a formation. A production wellbore is then drilled along a centerline or central axis of the spiral / helical wellbore. As such, the production wellbore or wellbore portion may be an axial wellbore formed along an axis of the spiral / helical injection wellbore or wellbore portion.

[0065] In accordance with some embodiments, the two wellbores may be drilled from the same or different pads (i.e., surface locations). In some embodiments, both an injection wellbore and a production wellbore are drilled from the same initial vertical section (primary section), and the spiral / helix separates out from the primary section to then form a spiral about a central axis. In accordance with some embodiments of the present disclosure, the distal ends (e.g., bottom of borehole) of the two wellbores are not connected by the drilling or formation process. Rather, a fracturing operation is performed to perforate or fracture the formation between the two wellbores / portions such that a fluid path is formed from the helical injection wellbore to the axial production wellbore.

[0066] In accordance with some embodiments, the fracturing may be performed from the helical injection wellbore, the axial production wellbore, or both. The fracturing may be segmented or staged to achieve desired placement of fractures in a target lithology and / or in65DDR-510199-WO-2 (INT1030PCT) preferential intervals, such as recharge zones. In such recharge zones, additional fluid may be picked up and carried into the production wellbore. The fractures from the helical injection wellbore may be paths to the axial production wellbore and / or may be fractures to other parts (e.g., between limbs or turns of the spiral shape) of the same helical injection wellbore.

[0067] In accordance with some embodiments of the present disclosure, the process for forming the wellbore(s) may include drill a helical injection wellbore followed by drilling of an axial production wellbore along an axis of the helical injection wellbore. A fracturing operation may be performed from the helical injection wellbore before or after formation of the axial production wellbore. In embodiments where the fracturing from the helical injection wellbore occurs before drilling of the axial production wellbore, fracture clouds may be identified, allowing for optimized heat pickup by a working fluid and / or for control of flow rates and the like through a formation having such fracture clouds. If fracture clouds from the helical injection portion are identified and such fracture clouds are not penetrated by the production portion, then bores or micro bores may be drilled from the production portion to intersect the fracture clouds to ensure fluid connection between the fracture clouds and the production portion of the wellbore system.

[0068] In operation, the helical injection wellbore is used to inject a working fluid from a surface source into a formation. The working fluid will exit the injection wellbore and enter fractures within the formation, thus picking up heat from the formation. The working fluid will continue to flow through the fractures in the formation and subsequently enter the production wellbore. The production wellbore receives the working fluid through the fractures from the injection wellbore and returns the heated fluid (or supercritical fluid) to the surface for use for power generation, heating and / or cooling, or for other purposes.

[0069] In accordance with some embodiments of the present disclosure, if both the injection portion and the production portion stem from the same initial primary portion, a packer may be deployed in the beginning of the production portion of the wellbore system to ensure the fluid injected to perform fracturing does not enter the production portion. Furthermore, during the drilling of such single primary portion with bifurcated injection and production portions, then the second drilled wellbore portion (e.g., preferably the production portion) may be sidetracked from helical well, such as by using a whipstock. This drilling technique may involve placing a temporary plug in the junction region of the helical injection portion, below the whipstock. Examples of temporary plugs and / or means for preventing short circuiting of fluid circuits include, but are not limited to, cement or packer(s).65DDR-510199-WO-2 (INT1030PCT)

[0070] During operation of injection and production through a fluid circuit in accordance with embodiments of the present disclosure, the use of a common primary or initial section means that the production fluid will flow through and exit from an insulated pipe bore, while the injection fluid flows down through the annular space between that pipe bore and a cased wellbore wall. To prevent the injection fluid entering the production portion, a plug may be provided around the outside of the production tubing, below the point of sidetrack or split between the injection portion and the production portion (e.g., at the junction). In some such embodiments, the portion of the production wellbore that is co- aligned with the injection portion (e.g., along the primary portion) may be formed from vacuum tubing or other fluidly sealed tubing to prevent mixing of the two flows of the working fluid. That is, the cool or cold injected working fluid flows on an exterior of the production tubing in a downward direction (e.g., into the formation), and the heated production working fluid is passed upward to the surface through the interior production tubing. As noted above, in other embodiments, this may be reversed, with the cool or cold injected working fluid flowing through an interior pipe and the heated production working fluid is passed upward to the surface along an exterior surface of the injection tubing or through an annular space between the injection tube and a borehole wall. Further, in operation, packers or restrictions can be added to the helical injection well to ensure preferential fluid flow through fractured intervals of the formation, rather than along the helical bore.

[0071] As described herein, in accordance with some embodiments, both the injection portion and the production portion may be drilled from the same pad or surface location (e.g., FIGS.3, 4A-4C). Such drilling operation may minimize movement of a single rig or eliminate the need to build multiple rigs, which can result in improved cost reductions and efficiencies. In embodiments wherein the injection portion and the production portion are drilled separately, then the rig may simply be skidded between the drilling locations. In the two well-portion embodiments of the present disclosure, the order of drilling may be a factor for consideration. For example, the helical injection wellbore or portion may be drilled first, and the axis of the helix that the injection portion forms or defines may not be vertical (e.g., as shown in FIG.5). That is, the helical injection portion be inclined due to geological conditions or may transition between vertical sections and horizontal section. In such configurations, the axial production well is drilled second and is intended to follow the central axis of the helix (e.g., helix centerline).65DDR-510199-WO-2 (INT1030PCT)

[0072] When drilling the two portions of the wellbore system, whether from a single location at the surface or from two locations, the path of the helical injection portion is set to be substantially equidistant from the helix centerline production portion. As such, the shortest distance (through a formation) from the injection portion to the production portion is substantially equal for the length of the wellbore system. With such an arrangement of the injection portion relative to the production portion, fracturing may be controlled to achieve the fluid connection between the injection portion and the production portion. In accordance with some embodiments, fracturing may be initiated from the helical injection portion. During the fracturing operation, the formed fracture network may include fractures that extend perpendicular to the axis of the helix centerline production portion, but also parallel or at an angle to it. These non-perpendicular fractures may connect limbs or different parts of the helical injection portion, facilitating slower fluid flow through the formation, with optimized working fluid heating or heat pickup.

[0073] As illustrated and discussed above, the wellbore systems of the present disclosure may be formed with a single injection portion and a single production portion, with the injection portion defining a spiral or helical path and the production portion arranged along the helix centerline. In other embodiments, a multiple helix wellbore system may be provided (e.g., as shown in FIG.8). The simplest case of such multiple-helix systems is a double-helix, but embodiments having a triple-helix or quadruple-helix, etc., may be employed without departing from the scope of the present disclosure. In such configurations, the multiple helical injection wellbore portions may have a common axis or centerline, and thus would define a set of injection portions, and the production portion will be drilled along the common central axis of the multi-helix injection portion. Further, in some configurations, multiple parallel or adjacent production wellbore portions may be drilled along the helix centerline to provide for increased production / return flow, or such increased flow may be defined, at least in part, upon the wellbore diameter drilled to form the production portion.

[0074] Advantageously, in accordance with embodiments of the present disclosure, improved geothermal and / or hydrothermal wellbore systems may be provided. The wellbore systems of the present disclosure provide improvements and advantages in both formation / installation and in production. With respect to formation and installation, in accordance with some embodiments, the drilling of two separate, but related wellbore sections (i.e., injection section and production section) may be drilled from a single well pad or location at the surface. Such configurations can eliminate the need to move a skid / rig and / or eliminate the need for two separate skids / rigs. Further, a single location rig for both65DDR-510199-WO-2 (INT1030PCT) portions of the wellbore system can reduce surface footprint, rig time, and overall project costs. Moreover, by drilling both portions (injection and production) from a single initial or primary portion, the alignment of the production portion along the helix centerline may be easily achieved.

[0075] Additionally, advantageously, in accordance with embodiments of the present disclosure, improved thermal exchange may be achieved between a working fluid and a formation. For example, advantageously, improved fracturing operations may be performed to identify fracture clouds and / or to develop fracture networks that provide fractures between the injection portion and the production portion and between different parts of the injection portion of the wellbore system.

[0076] Set forth below are some embodiments of the foregoing disclosure:

[0077] Embodiment 1: A method for forming a wellbore system, the method comprising: drilling a helical injection portion of the wellbore system through a formation, the helical injection portion defining a helix centerline; drilling a production portion of the wellbore system through the formation along the helix centerline; and performing a fracturing operation to form a fracture network within the formation and define a fluid connection between the injection portion and the production portion through the fracture network.

[0078] Embodiment 2: The method of any preceding embodiment, further comprising drilling a primary portion of the wellbore system, wherein the primary portion extends from a surface location to a junction and wherein the injection portion and the production portion separately extend from the primary portion at the junction.

[0079] Embodiment 3: The method of any preceding embodiment, further comprising installing a production tubing within the primary portion to fluidly connect the production portion to a surface system, wherein an injected fluid is configured to be directed through the primary portion in an annular passage defined between an exterior surface of the production tubing and a borehole wall of the primary portion of the wellbore system.

[0080] Embodiment 4: The method of any preceding embodiment, further comprising installing a whipstock proximate the junction to cause the injection portion to deviate from the primary portion to form a spiral path of the helical injection portion.

[0081] Embodiment 5: The method of any preceding embodiment, further comprising installing a means for preventing short circuiting of a fluid circuit that flow through the injection portion and the production portion, wherein the means for preventing short circuiting of the fluid circuit is arranged proximate the junction.65DDR-510199-WO-2 (INT1030PCT)

[0082] Embodiment 6: The method of any preceding embodiment, wherein the means for preventing short circuiting of the fluid circuit comprises a packer.

[0083] Embodiment 7: The method of any preceding embodiment, wherein the helical injection portion is drilled before the helix centerline production portion is drilled.

[0084] Embodiment 8: The method of any preceding embodiment, wherein the fracturing operation is performed from the helical injection portion.

[0085] Embodiment 9: The method of any preceding embodiment, wherein the fracturing operation is performed after the drilling of the helical injection portion and before the drilling of the helix centerline .

[0086] Embodiment 10: The method of any preceding embodiment, wherein the fracturing operation comprises a staged fracturing operation along the length of the helical injection portion.

[0087] Embodiment 11: The method of any preceding embodiment, wherein the fracture network comprises primary fractures that extend from the injection portion to the production portion to fluidly connect the injection portion to the production portion and secondary fractures that extend from one part of the injection portion to another part of the injection portion to fluidly connect the two parts of the injection portion.

[0088] Embodiment 12: The method of any preceding embodiment, wherein the drilling of the injection portion and the drilling of the production portion are performed from a single surface location.

[0089] Embodiment 13: The method of any preceding embodiment, further comprising: injecting a working fluid into the injection portion from a surface system; causing the working fluid to flow through the fracture network to pick up heat from the formation to form heated working fluid; receiving the heated working fluid in the production portion; and returning the heated working to the surface system.

[0090] Embodiment 14: The method of any preceding embodiment, wherein the working fluid is water.

[0091] Embodiment 15: The method of any preceding embodiment, wherein the working fluid is supercritical carbon dioxide.

[0092] Embodiment 16: The method of any preceding embodiment, further comprising: identifying fracture clouds within the fracture network; and fluidly connecting the production portion to the fracture clouds by at least one of drilling the production portion through the fracture clouds and drilling bores from the production portion into the fracture clouds.65DDR-510199-WO-2 (INT1030PCT)

[0093] Embodiment 17: The method of any preceding embodiment, wherein the helix centerline comprises both vertical sections and horizontal section.

[0094] Embodiment 18: The method of any preceding embodiment, wherein the helical injection portion is a first helical injection portion, the method further comprising: drilling a second helical injection portion relative to the first helical injection portion, wherein the second helical injection portion shares the same helix centerline as the first helical injection portion.

[0095] Embodiment 19: The method of any preceding embodiment, wherein the injection portion is drilled from a first location at a surface above the formation and the production portion is drilled from a second location at the surface that is different from the first location.

[0096] Embodiment 20: The method of any preceding embodiment, wherein the helical injection portion is drilled having a substantially constant radius of curvature about the helix centerline.

[0097] 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.

[0098] 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, fracturing 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 fracturing, stimulation, tracer injection, cleaning, acidizing, steam injection, water flooding, cementing, etc.

[0099] 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 various65DDR-510199-WO-2 (INT1030PCT) 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 the 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-510199-WO-2 (INT1030PCT) What is claimed is:

1. A method for forming a wellbore system, the method comprising: drilling a helical injection portion of the wellbore system through a formation, the helical injection portion defining a helix centerline; drilling a production portion of the wellbore system through the formation along the helix centerline; and performing a fracturing operation to form a fracture network within the formation and define a fluid connection between the injection portion and the production portion through the fracture network.

2. The method of claim 1, further comprising drilling a primary portion of the wellbore system, wherein the primary portion extends from a surface location to a junction and wherein the injection portion and the production portion separately extend from the primary portion at the junction.

3. The method of claim 2, further comprising installing a production tubing within the primary portion to fluidly connect the production portion to a surface system, wherein an injected fluid is configured to be directed through the primary portion in an annular passage defined between an exterior surface of the production tubing and a borehole wall of the primary portion of the wellbore system.

4. The method of claim 2, further comprising installing a whipstock proximate the junction to cause the injection portion to deviate from the primary portion to form a spiral path of the helical injection portion.

5. The method of claim 2, further comprising installing a means for preventing short circuiting of a fluid circuit that flow through the injection portion and the production portion, wherein the means for preventing short circuiting of the fluid circuit is arranged proximate the junction.

6. The method of claim 5, wherein the means for preventing short circuiting of the fluid circuit comprises a packer.

7. The method of claim 1, wherein the helical injection portion is drilled before the helix centerline production portion is drilled.

8. The method of claim 1, wherein the fracturing operation is performed from the helical injection portion.

9. The method of claim 8, wherein the fracturing operation is performed after the drilling of the helical injection portion and before the drilling of the helix centerline.65DDR-510199-WO-2 (INT1030PCT) 10. The method of claim 8, wherein the fracturing operation comprises a staged fracturing operation along the length of the helical injection portion.

11. The method of claim 8, wherein the fracture network comprises primary fractures that extend from the injection portion to the production portion to fluidly connect the injection portion to the production portion and secondary fractures that extend from one part of the injection portion to another part of the injection portion to fluidly connect the two parts of the injection portion.

12. The method of claim 1, wherein the drilling of the injection portion and the drilling of the production portion are performed from a single surface location.

13. The method of claim 1, further comprising: injecting a working fluid into the injection portion from a surface system; causing the working fluid to flow through the fracture network to pick up heat from the formation to form heated working fluid; receiving the heated working fluid in the production portion; and returning the heated working to the surface system.

14. The method of claim 13, wherein the working fluid is water.

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

16. The method of claim 1, further comprising: identifying fracture clouds within the fracture network; and fluidly connecting the production portion to the fracture clouds by at least one of drilling the production portion through the fracture clouds and drilling bores from the production portion into the fracture clouds.

17. The method of claim 1, wherein the helix centerline comprises both vertical sections and horizontal section.

18. The method of claim 1, wherein the helical injection portion is a first helical injection portion, the method further comprising: drilling a second helical injection portion relative to the first helical injection portion, wherein the second helical injection portion shares the same helix centerline as the first helical injection portion.

19. The method of claim 1, wherein the injection portion is drilled from a first location at a surface above the formation and the production portion is drilled from a second location at the surface that is different from the first location.65DDR-510199-WO-2 (INT1030PCT) 20. The method of claim 1, wherein the helical injection portion is drilled having a substantially constant radius of curvature about the helix centerline.

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