20. In addition, as described in greater detail herein, additional data (e.g., surface data) may be supplied by surface sensors 46 and/or stored in a memory location 48. By way of example, historical data and other useful data may be stored in the memory location 48 such as a cloud storage 50.

As illustrated, in certain embodiments, the coiled tubing 20 may be deployed from a CT reel 55 of a CT unit 52 and delivered downhole via an injector head 54. In certain embodiments, the injector head 54 may be controlled to slack off or pick up the coiled tubing 20 so as to control the tubing string weight and, thus, the weight-on-bit (WOB) acting on the drilling/milling bit 30 (or the downhole well tool(s) 36). In certain embodiments, the downhole well tool(s) 36 may be moved along the wellbore 14 via the coiled tubing 20 under control of the injector head 54 so as to apply a desired tubing weight and, thus, to achieve a desired rate of penetration (ROP) as the drilling/milling bit 30 is operated. Depending on the specifics of a given application, various types of data may be collected downhole, and transmitted to the surface processing system 42 in substantially real time to facilitate improved operation of the downhole well tool(s) 36. For example, as described in greater detail herein, the data may be used to fully or partially automate downhole operations, to optimize the downhole operations, and/or to provide more accurate predictions regarding components or aspects of the downhole operations.

In certain embodiments, fluid 32 may be delivered downhole under pressure from a pump unit 56. In certain embodiments, the fluid 32 may be delivered by the pump unit 56 through the downhole motor 28 to power the downhole motor 28 and, thus, the drilling/milling bit 30. In certain embodiments, the return fluid 34 is returned uphole, and this flow back of the return fluid 34 is controlled by suitable flowback equipment 58. In certain embodiments, the flowback equipment 58 may include chokes and other components/equipment used to control flow back of the return fluid 34 in a variety of applications, including well treatment applications.

As described in greater detail herein, the CT unit 52, the injector head 54, the pump unit 56, and the flowback equipment 58 may include advanced surface sensors 46, actuators, and local controllers, such as PLCs, which may cooperate together to provide sensor data to receive control signals from, and generate local control signals based on communications with, respectively, the surface processing system 42. In certain embodiments, as described in greater detail herein, the surface sensors 46 may include flow rate, pressure, and fluid rheology sensors 46, among other types of sensors. In addition, as described in greater detail herein, the actuators may include actuators for pump and choke control of the pump unit 56 and the flowback equipment 58, respectively, among other types of actuators.

In certain embodiments, surface sensors 46 of the CT unit 52 may be configured to detect positions of the coiled tubing 20, weights of the coiled tubing 20, and so forth. In addition, in certain embodiments, surface sensors 46 of the injector head 54 may be configured to detect wellhead pressure, and so forth. In addition, in certain embodiments, surface sensors 46 of the pump unit 56 may be configured to detect pump pressures, pump flow rates, and so forth. In addition, in certain embodiments, surface sensors 46 of the flowback equipment 58 may be configured to detect fluids production rates, solids production rates, and so forth.

Coiled tubing interventions often require manipulating the downhole tool string 12 while downhole. This manipulation can serve a variety of purposes, such as redirecting flow to a packer or orienting the downhole tool string 12 into a lateral drain. Conventionally, this manipulation is accomplished at the surface 24 through mechanical actuation (e.g., pushing and pulling on the coiled tubing) or hydraulic actuation (e.g., pumping fluid 32, dropping a ball, and so forth). Actuation from the surface 24 often requires relatively complex workflows, is prone to higher uncertainties, and lacks real control of downhole processes. Crew members usually have incomplete knowledge of what is happening because feedback may be somewhat limited. All of these limitations generate a higher risk when performing some of the most common applications, such as packer inflation, milling, or servicing multi-lateral wells.

FIG. 2 illustrates a well control system 60 that may include a surface processing system 42 to control the drilling/milling system 10 of FIG. 1, as described in greater detail herein. In certain embodiments, the surface processing system 42 may include one or more analysis modules 62 (e.g., a program of computer-executable instructions and associated data) that may be configured to perform various functions of the embodiments described herein. In certain embodiments, to perform these various functions, the one or more analysis modules 62 may execute on one or more processors 64 of the surface processing system 42, which may be connected to one or more storage media 66 of the surface processing system 42. Indeed, in certain embodiments, the one or more analysis modules 62 may be stored in the one or more storage media 66.

In certain embodiments, the one or more processors 64 may include a microprocessor, a microcontroller, a processor module or subsystem, a programmable integrated circuit, a programmable gate array, a digital signal processor (DSP), or another control or computing device. In certain embodiments, the one or more processors 64 may include machine learning and/or artificial intelligence (AI) based processors. In certain embodiments, the one or more storage media 66 may be implemented as one or more non-transitory computer-readable or machine-readable storage media. In certain embodiments, the one or more storage media 66 may include one or more different forms of memory including semiconductor memory devices such as dynamic or static random access memories (DRAMs or SRAMs), erasable and programmable read-only memories (EPROMs), electrically erasable and programmable read-only memories (EEPROMs) and flash memories; magnetic disks such as fixed, floppy and removable disks; other magnetic media including tape; optical media such as compact disks (CDs) or digital video disks (DVDs); or other types of storage devices. Note that the computer-executable instructions and associated data of the analysis module(s) 62 may be provided on one computer-readable or machine-readable storage medium of the storage media 66, or alternatively, may be provided on multiple computer-readable or machine-readable storage media distributed in a large system having possibly plural nodes. Such computer-readable or machine-readable storage medium or media are considered to be part of an article (or article of manufacture), which may refer to any manufactured single component or multiple components. In certain embodiments, the one or more storage media 66 may be located either in the machine running the machine-readable instructions, or may be located at a remote site from which machine-readable instructions may be downloaded over a network for execution.

In certain embodiments, the processor(s) 64 may be connected to a network interface 68 of the surface processing system 42 to allow the surface processing system 42 to communicate with the multiple downhole sensors 40 and surface sensors 46 described herein, as well as communicate with the actuators 70 and/or PLCs 72 of the surface equipment 74 (e.g., the CT unit 52, the injector head 54, the pump unit 56, the flowback equipment 58, and so forth) and of the downhole equipment 76 (e.g., the BHA 26, the downhole motor 28, the drilling/milling bit 30, the downhole well tool(s) 36, and so forth) for the purpose of controlling operation of the drilling/milling system 10, as described in greater detail herein. In certain embodiments, the network interface 68 may also facilitate the surface processing system 42 to communicate data to the cloud storage 50 (or other wired and/or wireless communication network) to, for example, archive the data or to enable external computing systems 78 to access the data and/or to remotely interact with the surface processing system 42.

It should be appreciated that the well control system 60 illustrated in FIG. 2 is only one example of a drilling/milling system, and that the well control system 60 may have more or fewer components than shown, may combine additional components not depicted in the embodiment of FIG. 2, and/or the well control system 60 may have a different configuration or arrangement of the components depicted in FIG. 2. In addition, the various components illustrated in FIG. 2 may be implemented in hardware, software, or a combination of both hardware and software, including one or more signal processing and/or application specific integrated circuits. Furthermore, the operations of the well control system 60 as described herein may be implemented by running one or more functional modules in an information processing apparatus such as application specific chips, such as application-specific integrated circuits (ASICs), field-programmable gate arrays (FPGAs), programmable logic devices (PLDs), systems on a chip (SOCs), or other appropriate devices. These modules, combinations of these modules, and/or their combination with hardware are all included within the scope of the embodiments described herein.

The embodiments described herein introduce modular, multi-functional downhole well tools 36 that integrate hydraulic and electronic actuation, additive metering, orientation control, and intelligent pressure management. By combining these capabilities into a compact, stackable design, the downhole well tools 36 enhance operational flexibility, reduces tool string size, and enables precise, responsive interventions.

Unlike traditional downhole well tools that perform single functions and require separate systems for hydraulic and electric control, the embodiments described herein utilize a unified, modular platform. These embodiments allow for interchangeable actuation methods, integrated chemical delivery, and intelligent flow and pressure control, all within a customizable, stackable architecture that can be tailored to specific job requirements.

A modular downhole well tool system was invented that combines hydraulic and electric actuation, directional control, additive metering, and intelligent pressure management into a single, adaptable platform. The system enables more efficient, targeted, and responsive well interventions, especially in coiled tubing operations. Its stackable design allows for scalable functionality and integration with third-party components.

It will be appreciated that the modular actuation modules 80 described herein are configured to be utilized in a “plug and play” manner in a stackable manner to enable the interchangeable actuation methods provided by the respective actuation modules. To that end, in certain embodiments, each of the modular actuation modules 80 may include substantially identical mechanical attachment mechanisms (e.g., having substantially similar electrical wiring connections, hydraulic flow lines, and so forth) both at their upper (e.g., uphole) and lower (e.g., downhole) axial ends to facilitate the interchangeability between the various modular actuator modules 80 within a single downhole well tool 36.

FIG. 3 illustrates a first example of a downhole well tool 36 that includes multiple actuator modules 80 stacked together along an axial length of the downhole well tool 36 to greatly increase capabilities for a single coiled tubing job. As illustrated, as with most of the other embodiments described herein, electrical wires 82 and fluid flow paths 84 from uphole components (e.g., the coiled tubing 20 or other intermediate components) in the downhole tool string 12 may be connected to the components of the downhole well tool 36. The embodiment illustrated in FIG. 3 shows how multiple actuator modules 80 may be used within a single downhole well tool 36. In certain embodiments, the different actuator modules 80 may interact with each other (e.g., communicatively via their electrical wiring 82 and/or hydraulically via their fluid flow paths 84) either directly or indirectly, for example, via intermediate components of the downhole well tool 36. However, in other embodiments, the different actuator modules 80 need not necessarily interact with each other (e.g., either directly or indirectly, for example, via intermediate components of the downhole well tool 36) and may, in fact, perform drastically different tasks for the downhole well tool 36.

As illustrated in the embodiment of FIG. 3, in certain embodiments, two hydraulic pistons 86A, 86B may be used together. In this fashion, a tractor could pull the tool string 12 downhole. As illustrated, in certain embodiments, both of the actuator modules 80 may include a printed wiring assembly (PWA) 88, a motor 90, and a bi-directional hydraulic pump 92 to control the positions of the respective hydraulic pistons 86A, 86B to enable (or block) fluid flow downhole through the downhole well tool 36. For example, as illustrated in FIG. 3, in certain embodiments, a first (e.g., uphole) hydraulic piston 86A (e.g., acting as a linear actuator tool) may be controlled by its respective actuator module 80A to enable (or block) a first flow of fluid downhole through the downhole well tool 36, and a second (e.g., downhole) hydraulic piston 86B may be controlled by its respective actuator module 80B to control the first flow of fluid to be distributed at an axial end of the downhole well tool 36 (e.g., as a hydraulic anchor, for example).

In certain embodiments, the pumps 92 of the actuator modules 80 may also include pressure relief valves to prevent excess pressure from building. As such, it will be appreciated that a single actuator module 80 may be used for both pressure control and shifting (e.g., of pistons 86A, 86B as well as other mechanical components, such as valves, and so forth). For example, in certain embodiments, the hydraulics of one actuator module 80 may be used for multiple tasks within the downhole well tool 36. In addition, utilizing bi-directional hydraulic pumps