AUTOMATED TWO-HOLE DRILLING USING RANGING

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

The present disclosure claims priority from U.S. Provisional Patent Application No. 63/656165, filed June 5, 2024, herein incorporated by reference in its entirety.

FIELD

The present disclosure relates to drilling systems that employ ranging tools to drill wellbores in a subterranean formation for access to resources, such as hydrocarbon resources or geothermal resources, within the subterranean formation.

BACKGROUND

Resources, such as hydrocarbon resources (e.g., oil and/or gas) or geothermal resources (steam or heat) are commonly extracted from subterranean formations using one or more wells that traverse or access the resource in the subterranean formation. The processes involved in extracting the resource from a subterranean formation can be complex and typically involve drilling one or more wellbores that traverse or access the resource in the subterranean formation, completing the wellbore for production, and performing the necessary operations to produce the resource from the subterranean formation.

Ranging tools are used to determine the position, direction, and orientation of a conductive pipe (for example, a metallic casing) for a variety of applications. In certain instances, such as in a blowout, a ranging tool can be used to drill a relief well that intersects a target well to stop the flow from the reservoir in the damaged target well. In other instances, the ranging tool can be used to drill parallel wells, for example, in steam assisted gravity drainage ("SAGD") well structures.

SUMMARY

Methods and systems are provided for drilling a secondary wellbore relative to a target wellbore, which involve drilling the secondary wellbore with a bottomhole assembly (BHA) that extends from a drill string. The BHA includes a magnetic field detector, a steering component, a drill bit, and at least one processor. The magnetic field detector can be configured to detect a time-varying magnetic field generated from a rotating magnetic source of a drilling tool disposed in the target wellbore. The at least one processor can be configured to i) use data output by the magnetic field detector to continually determine distance and direction or azimuth of the magnetic source relative to the BHA while drilling the secondary wellbore, and ii) use the distance and direction or azimuth of the magnetic source relative to the BHA while drilling the secondary wellbore to adjust the steering of the drilling performed by the BHA as controlled by the steering component of the BHA.

In embodiments, the at least one processor can be configured to adjust the steering of the drilling of the BHA in order to maintain a set distance and direction or azimuth relative to the target wellbore, autonomously without surface input or interference, whilst drilling the secondary wellbore with the BHA.

In embodiments, the adjustment of the steering of the drilling of the BHA can be part of a closed-loop drilling mode carried out under the control of the at least one processor.

In embodiments, the magnetic field detector can include a plurality of magnetometers.

In embodiments, the time-varying magnetic field generated from the rotating magnetic source in the target wellbore can be a time-varying sinusoidal magnetic field.

In embodiments, the rotating magnetic source in the target wellbore can be configured to generate the time-varying magnetic field while drilling the target wellbore, and the at least one processor can be configured to control steering of the drilling performed by the BHA such that the trajectory or path of the secondary wellbore follows the trajectory or path of the target wellbore.

In embodiments, the steering component of the BHA can include a rotary steerable system or part thereof.

BRIEF DESCRIPTION OF THE DRAWINGS

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

FIG. 1 is a schematic illustration of a two-hole drilling system in accordance with the present disclosure;

FIGS. 2A and 2B, collectively, is a flow chart of an example workflow for two-hole drilling in accordance with an aspect of the present application;

FIG. 3 is a schematic illustration of another two-hole drilling system in accordance with the present disclosure; and

FIG. 4 is a schematic view of a computer processing system.

DETAILED DESCRIPTION

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

Referring now to FIG. 1, a two-hole drilling system may be implemented at the earth's surface 11 with two wellbores extending into a subsurface formation 13. The system includes a first drilling assembly with a first drilling rig 15 and a first drill string 17 drilling a target wellbore 19 that traverses the subsurface formation 13. The first drilling rig 15 may include a derrick and a hoisting apparatus for raising and lowering the first drill string 17, which, as shown, extends into the target wellbore 19. The first drill string 17 can include drill pipe, jointed pipes, coiled tubing, etc. The target wellbore 19 can be completed with steel or nonmagnetic casing in some portions thereof. The lower end of first drill string 17 has a first bottomhole assembly (BHA) 21 that includes a first telemetry interface 23, a first MWD system 25, a first steering component 27, a first drill bit 29, and a magnetic field source 31. The first BHA 21 defines a first wellbore axis 33 while drilling as shown.

The first telemetry interface 23 may be a bi-directional communication interface configured to send and receive data to/from the surface. Examples of suitable telemetry techniques include but are not limited to electromagnetic telemetry, mud pulse telemetry, acoustic telemetry, and combinations of multiple telemetry techniques.

The first MWD system 25 may be used to collect navigation data and other operating parameters in the target wellbore 19 while tripping and while drilling. The first MWD system 25 may include magnetic and/or inertial sensors, including without limitation multiple precision calibrated magnetometers, accelerometers, gyroscopes, and combinations thereof. The sensors may include filtering or processing to improve accuracy in static and/or dynamic conditions.

The first steering component 27 can include a rotary steerable system for dynamically controlling the direction of drilling of the first drill bit 29. The rotary steerable system can be a push-the-bit tool or point-the-bit tool. A push-the-bit tool uses pads on the outside of the tool which press against the wellbore thereby causing the drill bit to press on the opposite side causing a direction change. A point-the-bit tool causes the direction of the bit to change relative to the rest of the tool by bending the main shaft running through it. The latter require some kind of non-rotating housing or reference housing in order to create this deflection within the shaft. For drill strings that employ coiled tubing, rotary steerable system can include a power section that converts mud hydraulic power to mechanical energy that drives rotation of the rotary steerable system and the first drill bit 29.

The magnetic field source 31 can include one or more permanent magnets (or electromagnets) that generate a time-varying magnetic field 35 during rotation of the first BHA 21. In embodiments, the time-varying magnetic field 35 can be a dipole magnetic field that appears as an alternating magnetic field at points away from first BHA 21.

In embodiments, the first drill bit 29 can be a fixed cutter drill bit, a roller cone drill bit, an impregnated drill bit, or a hybrid drill bit (e.g., a combination with fixed cutter blades and roller cones). In the same or other embodiments, the first BHA 21 can include other cutting components, such as a fixed reamer, hole opener, expandable reamer, window mill, junk mill, taper mill, dress mill, or other cutting tools. In still other embodiments, the first BHA 21 can include other components, such as one or more LWD tools that include various sensors for sensing downhole characteristics of the wellbore and the surrounding formation. The disclosed embodiments are not limited in these regards.

Still referring to FIG. 1, the system further includes a second drilling assembly with a second drilling rig 55 and a second drill string 57 drilling a secondary wellbore 59 that traverses the subsurface formation 13. The second drilling rig 55 may include a derrick and a hoisting apparatus for raising and lowering the second drill string 57, which, as shown, extends into the secondary wellbore 59. The second drill string 57 may comprise drill pipe, jointed pipes, coiled tubing, etc. The secondary wellbore 59 can be completed with steel or nonmagnetic casing in some portions thereof. The lower end of second drill string 57 has a second bottomhole assembly (BHA) 61 that includes a second telemetry interface 63, a second MWD system 65, a second steering component 67, a second drill bit 69, and a magnetic field detector 71. The second BHA 61 defines a second wellbore axis 73 while drilling as shown.

The second telemetry interface 63 may be a bi-directional communication interface configured to send and receive data to/from the surface. Examples of suitable telemetry techniques include but are not limited to electromagnetic telemetry, mud pulse telemetry, acoustic telemetry, and combinations of multiple telemetry techniques.

The second MWD system 65 may be used to collect navigation data and other operating parameters in the secondary wellbore 59 while tripping and while drilling. The second MWD system 65 may include magnetic and/or inertial sensors, including without limitation multiple precision calibrated magnetometers, accelerometers, gyroscopes, and combinations thereof. The sensors may include filtering or processing to improve accuracy in static and/or dynamic conditions.

The second steering component 67 can include a rotary steerable system for dynamically controlling the direction of drilling of the second drill bit 69. The rotary steerable system can be a push-the-bit tool or point-the-bit tool. A push-the-bit tool uses pads on the outside of the tool which press against the wellbore thereby causing the drill bit to press on the opposite side causing a direction change. A point-the-bit tool causes the direction of the bit to change relative to the rest of the tool by bending the main shaft running through it. The latter require some kind of non-rotating housing or reference housing in order to create this deflection within the shaft. For drill strings that employ coiled tubing, rotary steerable system can include a power section that converts mud hydraulic power to mechanical energy that drives rotation of the rotary steerable system and the second drill bit 69.

The magnetic field detector 71 can include one or more sensors that can be configured to sense the time-varying magnetic field generated by the magnetic field source 31 of the first BHA 21 and output data representing the time-varying magnetic field as detected by the sensor(s) while drilling the secondary wellbore 59. Such data may be supplied to a downhole processor provided in a sonde or cartridge as part of the second BHA 61. The downhole processor can be configured to receive and process the data as part of an automatic closed-loop drilling mode as described below with respect to FIGS. 2A and 2B. In embodiments, the magnetic field detector 71 can include an array of magnetometers provided in a sonde or cartridge as part of the second BHA 61.

In embodiments, the second drill bit 69 can be a fixed cutter drill bit, a roller cone drill bit, an impregnated drill bit, or a hybrid drill bit (e.g., a combination with fixed cutter blades and roller cones). In the same or other embodiments, the second BHA 61 can include other cutting components, such as a fixed reamer, hole opener, expandable reamer, window mill, junk mill, taper mill, dress mill, or other cutting tools. In still other embodiments, the second BHA 61 can include other components, such as one or more LWD tools that include various sensors for sensing downhole characteristics of the wellbore and the surrounding formation. The disclosed embodiments are not limited in these regards.

The system shown in FIG. 1 further includes a control system 81 located at the surface 11. The control system 81 can communicate with the first telemetry interface 23 via bi-directional data link 83 to receive real-time data communicated from the first BHA 21 while tripping and while drilling. Such data can be sourced from the first MWD system 25 or other parts of the first BHA 21, and used to monitor position and orientation of the first BHA 21 while tripping and while drilling. Such data can also be used to control the first drilling rig 15 as appropriate. The control system 81 can also communicate with the first telemetry interface 23 via bi-directional data link 83 to send commands to the first BHA 21 while drilling. Such commands can be used to control the first steering component 27 to control the direction of drilling of the first drill bit 29 and possible other operating parameters of the first BHA 21.

The control system 81 can also communicate with the second telemetry interface 63 via bi-directional data link 75 to receive real-time data communicated from the second BHA 61 while tripping and while drilling. Such data can be sourced from the second MWD system 65 or other parts of the second BHA 61, and used to monitor position and orientation of the second BHA 61 while tripping and while drilling. Such data can also be used to control the second drilling rig 55 as appropriate. The control system 81 can also communicate with the second telemetry interface 63 via bi-directional data link 75 to send commands to the second BHA 61 while drilling. Such commands can be used to control the second steering component 67 to control the direction of drilling of the second drill bit 69 and possible other operating parameters of the second BHA 61. The system may also include one or more surface transceivers, each located at or near a drilling rig and configured to engage a downhole telemetry interface, as well as additional sensors, power supplies, surface electrodes and/or rig controls, all of which may be connected to a surface computer.

In alternate embodiments, the control system 81 can be partitioned into two parts: a first control system that communicates with the first telemetry interface 23 and controls the first drilling rig 15 as described herein, and a second control system that communicates with the second telemetry interface 63 and controls the second drilling rig 55 as described herein. The first and second control systems can communicate with one another for coordinated control or to configure independent control as deemed suitable for the particular application.

In other embodiments, the first telemetry interface 23 can communicate with the second telemetry interface 63 via one or more communication links at the surface to allow the first BHA 21 (e.g., including one or more downhole processors as described herein) to communicate data and/or commands to the second BHA 61 (e.g.,, one or more downhole processors therein), or to allow the second BHA 61 (e.g.,, one or more downhole processors therein) to communicate data and/or commands to the first BHA 21 (e.g.,, including one or more downhole processors as described herein). This communication can be used for coordinated control (optionally, autonomous control) of the direction of drilling and other drilling parameters for the BHAs 21, 61 in the target and secondary wellbores while drilling the target and secondary wellbores.

FIGS. 2A and 2B illustrate a workflow for two-hole drilling of a target wellbore and a secondary wellbore in accordance with the present disclosure.

In block 201, a magnetic field source (e.g., magnetic field source 31 of FIG. 1) that is part of the BHA in the target wellbore (e.g., target wellbore 19 of FIG. 1) is operated to generate a time-varying magnetic field while drilling the target wellbore (e.g., while rotating the drill string in the target wellbore).

In block 203, an automatic closed-loop drilling mode for drilling the secondary wellbore (e.g., secondary wellbore 59 of FIG. 1) is configured with a predefined offset or path relative to the magnetic field source of 201.

In block 205, a magnetic field detector (e.g., magnetic field detector 71 of FIG. 1) that is part of the BHA in the secondary wellbore (e.g., second BHA 61 of FIG. 1) is operated to sense/detect the time-varying magnetic field generated by the magnetic field source of 201 and output data representing the time-varying magnetic field as detected by the magnetic field detector while drilling the secondary wellbore (e.g., while rotating the BHA in the secondary wellbore).

In block 207, data output by the magnetic field detector can be processed to determine distance and direction/azimuth of the magnetic field source of 201 relative to the magnetic field detector of 205 while drilling the secondary wellbore (e.g., while rotating the BHA in the secondary wellbore). Details of processing that can be performed to compute the distance and direction/azimuth between the magnetic field source of 201 relative to the magnetic field detector of 205 is described in PCT Publication No.: WO 2024/011087, commonly owned by assignee of the subject application and herein incorporated by reference in its entirety.

In block 209, the distance and direction/azimuth of 207 as determined over time can be evaluated or compared to the predefined offset or path of 203 while drilling the secondary wellbore (e.g., while rotating the BHA in the secondary wellbore).

In block 211, the results of the evaluating/comparing of 209 can be used to automatically generate a command for controlling direction of drilling in the secondary wellbore while drilling the secondary wellbore (e.g., while rotating the BHA in the secondary wellbore). The generation of the command in block 211 can be performed without input from the surface (e.g., without input from the surface controller 81 of FIG. 1).

In block 213, the command of 211 is communicated to the steering component of the BHA in the secondary wellbore (e.g., steering component 67 of FIG. 1) to control direction of drilling in the secondary wellbore while drilling the secondary wellbore (e.g., while rotating the BHA in the secondary wellbore).

In block 215, the operations determine if the closed-loop drilling mode should be terminated. This condition can be based on input or commands communicated from the surface (e.g., by commands communicated from the surface controller 81 of FIG. 1), by analysis of navigation data or other operating parameters of the drill string/BHA in the secondary wellbore, or by hybrid analysis involving both input or commands communicated from the surface and analysis of navigation data or other operating parameters of the drill string/BHA in the secondary wellbore. If it is determined that the closed-loop drilling mode should not be terminated, the operations return to block 205 to repeat the operations of the closed-loop drilling mode of blocks 205 to 215. If it is determined that the closed-loop drilling mode should terminate, the operations of the closed-loop drilling mode end. In this case, the drilling operations for the secondary wellbore can stop or transition to other drilling operations deemed suitable by the drilling operator or application.

In embodiments, one or more of the operations of blocks 203 to 215 can be performed by a downhole processor that is part of the BHA of the drill string that drills the secondary wellbore (e.g., second BHA 61 of FIG. 1).

FIG. 3 is a schematic illustration of another two-hole drilling system in accordance with the present disclosure, which illustrates components that perform active ranging for the two-hole drilling. In this diagram, the BHA 300 of the drill string that drills the target wellbore employs a magnetic field source 301 having a plurality of permanent magnets that are arranged to create a magnetic dipole at ninety degrees relative to the tool axis as shown. The rotation of the BHA 300 (and the magnetic field source 301) causes the magnetic dipole to rotate, leading to a time-varying sinusoidal magnetic field that can be detected using magnetometers 303 on board another drilling tool (BHA 302) located at a distance from the magnetic field source 301 in the adjacent, secondary wellbore, either being drilled simultaneously or perhaps after the target wellbore.

The detection of the time-varying sinusoidal magnetic field by the magnetometers 303 in the secondary wellbore and tracking it over time enables a calculation to be made that gives the distance 305 and direction or azimuth 307 of the magnetic source 301 relative to the magnetometers 303 of the drilling tool (BHA 302) that is drilling the secondary wellbore.

In this embodiment, the BHA 302 can be equipped with a steering component to drill the secondary wellbore together with magnetometers or other magnetic field detectors or sensors 303, and the output of such sensors 303 can be processed to automatically calculate the distance and direction or azimuth of the magnetic source 301 relative thereto. This result can be processed in conjunction with previous results of distance and direction or azimuth over time to determine if the BHA 302 that is drilling the secondary wellbore is converging or diverging from a predefined offset or path relative to the target wellbore. If the BHA 302 that is drilling the secondary wellbore is given a set distance and direction or azimuth relative to the target wellbore to maintain, then the steering component of the BHA 302 can be supplied with commands, automatically calculated downhole by a processor, that adjust the steering of the drilling of the secondary wellbore such that the set distance and direction or azimuth relative to the target wellbore is maintained autonomously without surface input or interference, whilst drilling the secondary wellbore. The path or trajectory of the secondary wellbore relative to the target wellbore and the path of the secondary wellbore itself can follow arbitrary orientations for one or more sections of the secondary wellbore and the target wellbore. For example, such orientations can include a vertical orientation, curved orientation, an s-curved path, a horizontal orientation or other suitable orientation.

In embodiments, a downhole processor integral to the BHA 302 that drills the secondary wellbore can be configured to i) continually determine (e.g., determine one or more times per second) the distance and direction/azimuth of the magnetic source 301 relative to the BHA 302 in the secondary wellbore whilst drilling and ii) automatically adjust the steering of the drilling of the secondary wellbore as controlled by the steering component of the same BHA 302 based on the distance and direction/azimuth of the magnetic source 301 relative to the BHA 302 in the secondary wellbore. Alternatively, such operations could be partitioned between processor functionality implemented by any number of downhole tools of the BHA 302 drilling the secondary wellbore. In embodiments, the magnetometers or other magnetic field detectors or sensors 303 can be located adjacent or close to the drill bit of the BHA 302 in order to minimize the offset between the magnetometers or other magnetic field detectors or sensors 302 and the drill bit of the BHA 302.

FIG. 4 illustrates an example device 2500, with a processor 2502 and memory 2504 that can be configured to implement various embodiments of the methods and processes as discussed in the present application, including the automatic closed-loop drilling mode as described above with respect to FIGS. 2A and 2B. Memory 2504 can also host one or more databases and can include one or more forms of volatile data storage media such as random-access memory (RAM), and/or one or more forms of nonvolatile storage media (such as read-only memory (ROM), flash memory, and so forth).

Device 2500 is one example of a computing device or programmable device and is not intended to suggest any limitation as to scope of use or functionality of device 2500 and/or its possible architectures. For example, device 2500 can comprise one or more computing devices, programmable logic controllers (PLCs), etc.

Further, device 2500 should not be interpreted as having any dependency relating to one or a combination of components illustrated in device 2500. For example, device 2500 may include one or more computers, such as a laptop computer, a desktop computer, a mainframe computer, etc., or any combination or accumulation thereof.

Device 2500 can also include a bus 2508 configured to allow various components and devices, such as processors 2502, memory 2504, and local data storage 2510, among other components, to communicate with each other.

Bus 2508 can include one or more of any of several types of bus structures, including a memory bus or memory controller, a peripheral bus, an accelerated graphics port, and a processor or local bus using any of a variety of bus architectures. Bus 2508 can also include wired and/or wireless buses.

Local data storage 2510 can include fixed media (e.g., RAM, ROM, a fixed hard drive, etc.) as well as removable media (e.g., a flash memory drive, a removable hard drive, optical disks, magnetic disks, and so forth). One or more input/output (I/O) device(s) 2512 may also communicate via a user interface (UI) controller 2514, which may connect with I/O device(s) 2512 either directly or through bus 2508.

In one possible implementation, a network interface 2516 may communicate outside of device 2500 via a connected network or telemetry system (e.g., wired drill pipe). A media drive/interface 2518 can accept removable tangible media 2520, such as flash drives, optical disks, removable hard drives, software products, etc. In one possible implementation, logic, computing instructions, and/or software programs comprising elements of module 2506 may reside on removable media 2520 readable by media drive/interface 2518.

In one possible embodiment, input/output device(s) 2512 can allow a user (such as a human annotator) to enter commands and information into device 2500, and also allow information to be presented to the user and/or other components or devices. Examples of input device(s) 2512 include, for example, sensors, a keyboard, a cursor control device (e.g., a mouse), a microphone, a scanner, and any other input devices known in the art. Examples of output devices include a display device (e.g., a monitor or projector), speakers, a printer, a network card, and so on.

Various systems and processes of present disclosure may be described herein in the general context of software or program modules, or the techniques and modules may be implemented in pure computing hardware. Software generally includes routines, programs, objects, components, data structures, and so forth that perform particular tasks or implement particular abstract data types. An implementation of these modules and techniques may be stored on or transmitted across some form of tangible computer-readable media. Computer-readable media can be any available data storage medium or media that is tangible and can be accessed by a computing device. Computer readable media may thus comprise computer storage media. “Computer storage media” designates tangible media, and includes volatile and non-volatile, removable, and non-removable tangible media implemented for storage of information such as computer readable instructions, data structures, program modules, or other data. Computer storage media include, but are not limited to, RAM, ROM, EEPROM, flash memory or other memory technology, CD-ROM, digital versatile disks (DVD) or other optical storage, magnetic cassettes, magnetic tape, magnetic disk storage or other magnetic storage devices, or any other tangible medium which can be used to store the desired information, and which can be accessed by a computer.

Some of the methods and processes described above can be performed by a processor. The term “processor” should not be construed to limit the embodiments disclosed herein to any particular device type or system. The processor may include a computer system. The computer system may also include a computer processor (e.g., a microprocessor, microcontroller, digital signal processor, general-purpose computer, special-purpose machine, virtual machine, software container, or appliance) for executing any of the methods and processes described above.

The computer system may further include a memory such as a semiconductor memory device (e.g., a RAM, ROM, PROM, EEPROM, or Flash-Programmable RAM), a magnetic memory device (e.g., a diskette or fixed disk), an optical memory device (e.g., a CD-ROM), a PC card (e.g., PCMCIA card), or other memory device.

Alternatively or additionally, the processor may include discrete electronic components coupled to a printed circuit board, integrated circuitry (e.g., Application Specific Integrated Circuits (ASIC)), and/or programmable logic devices (e.g., a Field Programmable Gate Arrays (FPGA)). Any of the methods and processes described above can be implemented using such logic devices.

Some of the methods and processes described above can be implemented as computer program logic for use with the computer processor. The computer program logic may be embodied in various forms, including a source code form or a computer executable form. Source code may include a series of computer program instructions in a variety of programming languages (e.g., an object code, an assembly language, or a high-level language such as C, C++, or JAVA). Such computer instructions can be stored in a non-transitory computer readable medium (e.g., memory) and executed by the computer processor. The computer instructions may be distributed in any form as a removable storage medium with accompanying printed or electronic documentation (e.g., shrink wrapped software), preloaded with a computer system (e.g., on system ROM or fixed disk), or distributed from a server or electronic bulletin board over a communication system (e.g., the Internet or World Wide Web).

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