Automated Two-Hole Drilling Using Ranging

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.

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.

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.

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.

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, a two-hole drilling system may be implemented at the earth's surfacewith two wellbores extending into a subsurface formation. The system includes a first drilling assembly with a first drilling rigand a first drill stringdrilling a target wellborethat traverses the subsurface formation. The first drilling rigmay include a derrick and a hoisting apparatus for raising and lowering the first drill string, which, as shown, extends into the target wellbore. The first drill stringcan include drill pipe, jointed pipes, coiled tubing, etc. The target wellborecan be completed with steel or nonmagnetic casing in some portions thereof. The lower end of first drill stringhas a first bottomhole assembly (BHA)that includes a first telemetry interface, a first MWD system, a first steering component, a first drill bit, and a magnetic field source. The first BHAdefines a first wellbore axiswhile drilling as shown.

The first telemetry interfacemay 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 systemmay be used to collect navigation data and other operating parameters in the target wellborewhile tripping and while drilling. The first MWD systemmay 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 componentcan include a rotary steerable system for dynamically controlling the direction of drilling of the first drill bit. 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.

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

In embodiments, the first drill bitcan 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 BHAcan 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 BHAcan 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, the system further includes a second drilling assembly with a second drilling rigand a second drill stringdrilling a secondary wellborethat traverses the subsurface formation. The second drilling rigmay include a derrick and a hoisting apparatus for raising and lowering the second drill string 57, which, as shown, extends into the secondary wellbore. The second drill stringmay comprise drill pipe, jointed pipes, coiled tubing, etc. The secondary wellborecan be completed with steel or nonmagnetic casing in some portions thereof. The lower end of second drill stringhas a second bottomhole assembly (BHA)that includes a second telemetry interface, a second MWD system, a second steering component, a second drill bit, and a magnetic field detector. The second BHAdefines a second wellbore axiswhile drilling as shown.

The second telemetry interfacemay 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 systemmay be used to collect navigation data and other operating parameters in the secondary wellborewhile tripping and while drilling. The second MWD systemmay 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 componentcan include a rotary steerable system for dynamically controlling the direction of drilling of the second drill bit. 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.

The magnetic field detectorcan include one or more sensors that can be configured to sense the time-varying magnetic field generated by the magnetic field sourceof the first BHAand output data representing the time-varying magnetic field as detected by the sensor(s) while drilling the secondary wellbore. Such data may be supplied to a downhole processor provided in a sonde or cartridge as part of the second BHA. 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. In embodiments, the magnetic field detectorcan include an array of magnetometers provided in a sonde or cartridge as part of the second BHA.

In embodiments, the second drill bitcan 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 BHAcan 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 BHAcan 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 infurther includes a control systemlocated at the surface. The control systemcan communicate with the first telemetry interfacevia bi-directional data linkto receive real-time data communicated from the first BHAwhile tripping and while drilling. Such data can be sourced from the first MWD systemor other parts of the first BHA, and used to monitor position and orientation of the first BHAwhile tripping and while drilling. Such data can also be used to control the first drilling rigas appropriate. The control systemcan also communicate with the first telemetry interfacevia bi-directional data linkto send commands to the first BHAwhile drilling. Such commands can be used to control the first steering componentto control the direction of drilling of the first drill bitand possible other operating parameters of the first BHA 21.

The control systemcan also communicate with the second telemetry interfacevia bi-directional data linkto receive real-time data communicated from the second BHAwhile tripping and while drilling. Such data can be sourced from the second MWD systemor other parts of the second BHA, and used to monitor position and orientation of the second BHAwhile tripping and while drilling. Such data can also be used to control the second drilling rigas appropriate. The control systemcan also communicate with the second telemetry interfacevia bi-directional data linkto send commands to the second BHAwhile drilling. Such commands can be used to control the second steering componentto control the direction of drilling of the second drill bitand possible other operating parameters of the second BHA. 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 systemcan be partitioned into two parts: a first control system that communicates with the first telemetry interfaceand controls the first drilling rigas described herein, and a second control system that communicates with the second telemetry interfaceand controls the second drilling rigas 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 interfacecan communicate with the second telemetry interfacevia one or more communication links at the surface to allow the first BHA(e.g., including one or more downhole processors as described herein) to communicate data and/or commands to the second BHA(e.g.,, one or more downhole processors therein), or to allow the second BHA(e.g.,, one or more downhole processors therein) to communicate data and/or commands to the first BHA(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,in the target and secondary wellbores while drilling the target and secondary wellbores.

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

In block, a magnetic field source (e.g., magnetic field sourceof) that is part of the BHA in the target wellbore (e.g., target wellboreof) 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, an automatic closed-loop drilling mode for drilling the secondary wellbore (e.g., secondary wellboreof) is configured with a predefined offset or path relative to the magnetic field source of.

In block, a magnetic field detector (e.g., magnetic field detectorof) that is part of the BHA in the secondary wellbore (e.g., second BHAof) is operated to sense/detect the time-varying magnetic field generated by the magnetic field source ofand 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, data output by the magnetic field detector can be processed to determine distance and direction/azimuth of the magnetic field source ofrelative to the magnetic field detector ofwhile 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 ofrelative to the magnetic field detector ofis 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, the distance and direction/azimuth ofas determined over time can be evaluated or compared to the predefined offset or path ofwhile drilling the secondary wellbore (e.g., while rotating the BHA in the secondary wellbore).

In block, the results of the evaluating/comparing ofcan 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 blockcan be performed without input from the surface (e.g., without input from the surface controllerof).

In block, the command ofis communicated to the steering component of the BHA in the secondary wellbore (e.g., steering componentof) 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, 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 controllerof), 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 blockto 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 BHAof).

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 BHAof the drill string that drills the target wellbore employs a magnetic field sourcehaving 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(and the magnetic field source) causes the magnetic dipole to rotate, leading to a time-varying sinusoidal magnetic field that can be detected using magnetometerson board another drilling tool (BHA) located at a distance from the magnetic field sourcein 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 magnetometersin the secondary wellbore and tracking it over time enables a calculation to be made that gives the distanceand direction or azimuthof the magnetic sourcerelative to the magnetometersof the drilling tool (BHA) that is drilling the secondary wellbore.

In this embodiment, the BHAcan be equipped with a steering component to drill the secondary wellbore together with magnetometers or other magnetic field detectors or sensors, and the output of such sensorscan be processed to automatically calculate the distance and direction or azimuth of the magnetic sourcerelative thereto. This result can be processed in conjunction with previous results of distance and direction or azimuth over time to determine if the BHAthat is drilling the secondary wellbore is converging or diverging from a predefined offset or path relative to the target wellbore. If the BHAthat 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 BHAcan 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 BHAthat 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 sourcerelative to the BHAin 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 BHAbased on the distance and direction/azimuth of the magnetic sourcerelative to the BHAin the secondary wellbore. Alternatively, such operations could be partitioned between processor functionality implemented by any number of downhole tools of the BHAdrilling the secondary wellbore. In embodiments, the magnetometers or other magnetic field detectors or sensorscan be located adjacent or close to the drill bit of the BHAin order to minimize the offset between the magnetometers or other magnetic field detectors or sensorsand the drill bit of the BHA.

illustrates an example device, with a processorand memorythat 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. Memorycan 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).

Deviceis 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 deviceand/or its possible architectures. For example, devicecan comprise one or more computing devices, programmable logic controllers (PLCs), etc.

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

Devicecan also include a busconfigured to allow various components and devices, such as processors, memory, and local data storage 2510, among other components, to communicate with each other.

Buscan 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. Buscan also include wired and/or wireless buses.

Local data storagecan 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)may also communicate via a user interface (UI) controller, which may connect with I/O device(s)either directly or through bus.

In one possible implementation, a network interfacemay communicate outside of devicevia a connected network or telemetry system (e.g., wired drill pipe). A media drive/interfacecan accept removable tangible media, 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 modulemay reside on removable mediareadable by media drive/interface.

In one possible embodiment, input/output device(s)can allow a user (such as a human annotator) to enter commands and information into device, and also allow information to be presented to the user and/or other components or devices. Examples of input device(s)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.