INTERNET OF THINGS IN MANAGED PRESSURE DRILLING OPERATIONS

Abstract

A control system for a pressure management device (PMA) in a drilling rig has an on-site device in close proximity to and communicating with the PMA, and an off-site device in a remote location. Both the on-site and off-site devices are connected to a network, such as the internet, through which they can communicate with each other. The on-site device receives real-time data from the PMA, and the off-site device can access this real-time data over the network. The off-site device can generate a command based on data or user input and send the command to the on-site device to modify one or more PMA settings. A control panel is displayed on the off-site device's user interface to allow an operator to remotely control the PMA.

Description

INTERNET OF THINGS IN MANAGED PRESSURE DRILLING OPERATIONS CROSS-REFERENCE WITH RELATED APPLICATIONS This application claims the benefit of United States Provisional Application Serial No. 63 / 169,684, filed on April 1, 2021, the contents of which are hereby incorporated by reference in their entirety. FIELD This disclosure relates generally to well drilling operations and, more specifically, to Internet of Things (IoT) monitoring and control systems and procedures for managed pressure drilling operations and / or equipment. BACKGROUND Managed pressure drilling (MPD) techniques are used to drill wells. In MPD drilling operations, an MPD system uses a closed, pressurizable mud return system, a rotary control device (RCD), and a choke manifold to control wellbore pressure during drilling. The various MPD techniques used in the industry allow operators to manage wellbore pressure in a controlled manner during drilling, especially in conditions where conventional drilling techniques cannot be applied (e.g., deepwater drilling). One function of MPD is to help control the influx of formation fluids into the well during drilling. This can be achieved using an automated choke response in a closed, pressurized circulating system made possible by the rotary control device. A control system manages the chokes with an automated response by monitoring the flow into and out of the well through various sensors, and software algorithms within the control system seek to maintain a mass flow balance. If a deviation from mass balance is identified, the control system initiates an automated choke response that changes the annular pressure profile of the well and, consequently, the equivalent mud weight in the well. This automated capability of the control system allows it to perform dynamic well control or constant bottom-hole pressure (CBHP) techniques. iviA / a / zuzo / uii ouu In addition to kick detection and automated choke control, several other rig operations are needed to drill the well effectively and efficiently. For example, the control system used for managed pressure drilling may require coordination or communication with sensors located on the rig to function optimally. Conventionally, the control system for MPD operations is located on the platform and requires a human operator on-site to monitor and operate it. Whether the platform is on land or water, any on-site operator presence poses a safety risk. For the control system to operate, large amounts of data are collected in real time from various sensors within the MPD system for analysis and use by the control system. While conventional MPD systems, one of which is described in U.S. Patent No. 10,113,408, can transmit such sensor data off-site for storage and subsequent analysis, the ability to monitor and control the MPD system in real time is limited to the on-site control system, which is operated by a human operator at the well site. Therefore, this disclosure aims to provide systems and procedures that allow MPD operations and / or devices to be at least partially monitored and controlled off-site, almost in real time from almost anywhere in the world, in such a way as to eliminate or at least reduce the need for a human operator on-site. BRIEF DESCRIPTION OF THE INVENTION According to a broad aspect of this disclosure, a control system is provided for controlling a pressure management apparatus in a drilling system at the drilling site, the pressure management apparatus comprising a controller and a plurality of components controllable by the controller, the control system comprising: a network accessible via the Internet; an on-site device in communication with the controller and connected to the network, the on-site device being configured to receive data from the controller, the on-site device being located at or near the drilling site;and an off-site device connected to the network and in communication with the on-site device via the network, the off-site device being configured to receive data from the on-site device via the network in real time and to receive user input, the off-site device being located at a remote location from the drilling site, wherein the off-site device is configured to generate a command based on data or user input and send the command to the on-site device; and wherein the on-site device is configured to receive the command and send the command to the controller to cause the controller to modify at least one setting of the plurality of components of the pressure management apparatus. In some implementations, the network is part of a virtual private cloud. In some implementations, the network comprises one or more data channels. In some embodiments, the network comprises one or more of: a proxy service; a managed pooled stream generation service; a drill data consumer; a client stream generation service; a managed large non-relational database service; a software security service; a CRUD service; and a user authentication proxy. In some embodiments, the pressure management apparatus comprises one or more data collection devices operatively coupled to the controller, and the controller is configured to receive data from the one or more data collection devices. In some embodiments, the drilling system comprises an electronic drilling recorder system and the on-site device is in communication with the electronic drilling recorder system. In some embodiments, the plurality of components comprises a choke having a choke motor and a choke valve motor, and the controller is configured to actuate the choke motor to make the choke more open or closed, and to actuate the choke valve motor to put the choke online or offline. In some embodiments, the choke comprises a choke housing; a choke cartridge configured to be removable into the choke housing; and a choke cartridge motor, and the controller is configured to drive the choke cartridge motor to cause the choke cartridge to move relative to the choke housing. In some embodiments, the plurality of components comprises a choke narrowing line; a flow line valve configured to control the fluid flow in the choke narrowing line; and a flow line valve motor operatively coupled to the flow line valve, and the controller is configured to drive the flow line valve motor to cause the flow line valve to open or close. In some embodiments, the plurality of components comprises a bearing assembly; a bowl for receiving the bearing assembly; and a coupling motor operatively coupled to the bearing assembly or the bowl, and the controller is configured to drive the coupling motor to cause the bearing assembly to move relative to the bowl. In some embodiments, the pressure management apparatus comprises an optical sensing device. Pursuant to another broad aspect of this disclosure, a procedure is provided comprising: connecting, via an off-site device, to the Internet, the off-site device being located remotely from a well drilling site; connecting, via the off-site device, to an on-site device communicating with a pressure management apparatus (PMA) in a drilling system at the drilling site via an Internet service, the on-site device being at or near the drilling site; receiving, via the on-site device, PMA data from a PMA controller in real time; receiving, via the off-site device, real-time PMA data from the on-site device via the Internet;generate, using the off-site device, a command based, at least in part, on one or both of the PMA data and the user input on the off-site device; send, using the off-site device, the command to the on-site device; receive, using the on-site device, the command; send, using the on-site device, the command to the controller; receive, using the controller, the command; and modify, using the controller, a PMA setting based on the command. In some embodiments, the procedure comprises receiving, via the on-site device, EDR data from a real-time drilling system platform; and receiving, via the off-site device, real-time EDR data from the on-site device via the Internet. In some implementations, the command is generated based, at least in part, on EDR data. In some embodiments, the PMA setting modification occurs before, during, or after one of: well drilling, connecting a drill string at the drilling site, ejecting the drill string from the well, circulating fluid in the well, reaming the well, handling a kick or loss while drilling the well, and an offline operation. In some implementations, the command is generated by the off-site device based, at least in part, on PMA data and one or more pre-established rules. In some implementations, one or more pre-established rules are generated by the off-site device, generated by the on-site device, set by a user, or a combination thereof. In some embodiments, the command is generated based on PMA data, and the procedure comprises: generating, through the on-site device, an alert based on the PMA data; before generating the command, receiving, through the off-site device, the alert from the on-site device; and generating, through the off-site device, the command in response to the alert. In some embodiments, the command is generated based on user input, and the procedure comprises: generating, via the on-site device, an alert based on PMA data; before generating the command, receiving via the off-site device, the alert from the on-site device; notifying, via the off-site device, a user of the off-site device input based on the alert; and receiving, via the off-site device, the user input from the user in response to the notification. In some embodiments, PMA data comprises one or more of: a flow rate; a pressure; a temperature; a choke position; a choke valve position; a choke cartridge position; a flow line valve position; a bearing assembly position; an image; and a video. In some embodiments, the EDR data includes an injection pressure. In some embodiments, the procedure involves displaying, via the off-site device, a control panel to present at least some of the PMA data in real time and receive user input. In some embodiments, the procedure comprises, after modifying the PMA setting, receiving confirmation from the PMA via the on-site device; receiving confirmation from the on-site device via the off-site device; and updating the control panel via the off-site device. iviA / a / zuzo / uii ouu In some embodiments, the remote location is at a distance from a second drilling site of a second well, and the procedure comprises: connecting, by means of the off-site device, to a second on-site device in communication with a second PMA in a second drilling system at the second drilling site via the Internet service, the second on-site device being at or near the second drilling site; receiving, by means of the second on-site device, second PMA data from a controller of the second PMA in real time; receiving, by means of the off-site device, the second PMA data in real time from the second on-site device via the Internet; generating, by means of the off-site device, a second command based, at least in part, on one or both of the second PMA data and a second user input on the off-site device;send, via the off-site device, the second command to the second on-site device; receive, via the second on-site device, the second command; send, via the second on-site device, the second command to the controller of the second PMA; receive, via the controller of the second PMA, the second command; and modify, via the controller of the second PMA, a setting of the second PMA based on the second command. According to another broad aspect of this disclosure, a control system is provided for a pressure-managed drilling system having a drill string and drill bit extended in a well, an electric drilling recorder system, a mud pump, and a pressure management apparatus (PMA) in communication with a defined circular ring between the drill string and the well, the control system being in communication with the pressure management apparatus, the control system comprising: an on-site device in communication with a control unit of the pressure management apparatus and the electronic drilling recorder system to receive substantially real-time data, the data being collected by a plurality of sensors of the pressure management apparatus and the electronic drilling recorder; and an off-site device comprising: a user interface having a display;a control panel accessible through the display; and one or more processors in communication with the on-site device through a communication network, the one or more processors having access to a first set of instructions which, when executed by at least one of the one or more processors, cause the off-site device to: generate, on the control panel, one or more of: a hole depth indicator showing a depth of the well; a drill bit depth indicator showing a depth of the drill bit; a block height indicator showing a length remaining for a subsequent drill string segment connection; an inflow indicator showing a pump rate of a drilling fluid entering the well; an outflow indicator showing a flow rate of a drilling mud entering the pressure management apparatus;an inlet mud weight indicator that displays a mud weight of the drilling fluid entering the well; an outlet mud weight indicator that displays a mud weight of the drilling mud leaving the well; a surface backpressure indicator that displays a surface backpressure; a target surface backpressure indicator that displays a target surface backpressure; a casing midpoint pressure (ICP) indicator that displays an ICP pressure; and an equivalent circulating density (ECD) indicator of ICP that displays an ECD of ICP;iteratively update the control panel to display one or more of the following indicators: hole depth indicator, drill depth indicator, block height indicator, inflow flow indicator, outflow flow indicator, inflow mud weight indicator, outflow mud weight indicator, surface backpressure indicator, ICP pressure indicator, and ICP ECD indicator, substantially in real time; and control the pressure management apparatus, via the on-site device, based at least in part on the information displayed on the control panel. In some embodiments, the first set of instructions further causes the off-site device to: generate, on the control panel, one or more of: a bottomhole pressure indicator showing a bottomhole pressure; a bottomhole ECD indicator showing a bottomhole ECD; a surface backpressure limit indicator showing a surface backpressure limit; a peak pressure indicator showing a peak pressure; and an ejection rate indicator showing an ejection rate; and iteratively update the control panel to display one or more of the bottomhole pressure indicator, the bottomhole ECD indicator, the surface backpressure limit indicator, the peak pressure indicator, and the ejection rate indicator substantially in real time. In some embodiments, the pressure management apparatus has a first choke, wherein the first set of instructions further causes the off-site device to: generate, on the control panel: a first choke status indicator showing the status of the first choke; and a first choke position indicator showing an opening of the first choke; and iteratively update the control panel to show the first choke status indicator and the first choke position indicator substantially in real time. In some embodiments, the first set of instructions further causes the off-site device to: generate, on the control panel, a graphical representation showing one or more of: well depth; drill bit depth; remaining length; drilling fluid pump rate; drilling mud flow rate; drilling fluid mud weight; drilling mud weight; surface backpressure; target surface backpressure; ICP pressure; ICP ECO; bottom hole pressure; bottom hole ECD; surface backpressure limit; peak pressure; ejection rate; first choke status; and first choke opening, for a range of well block heights; and iteratively update the control panel to display the graphical representation in substantially real time. In some implementations, the control panel is configured to allow a user to select the range of block heights. In some embodiments, the pressure management apparatus has a second choke, wherein the first set of instructions further causes the off-site device to: generate, on the control panel, a second choke status indicator showing a status of the second choke; generate, on the control panel, a second choke position indicator showing an opening of the second choke; and iteratively update the control panel to show the second choke status indicator and the second choke position indicator substantially in real time. In some embodiments, the graphic representation shows the state of the second choke and the opening of the second choke. In some embodiments, the first set of instructions further causes the off-site device to: generate, on the control panel, a Formation Integrity Test (FIT) / Maximum Allowable Casing Pressure (MACP) section that allows the user to enter one or more of: a depth value, a bottom hole ECD value, and a pressure gradient value; and control the pressure management apparatus based at least in part on the depth value, the bottom hole ECD value, or the pressure gradient value. In some implementations, the first set of instructions also causes the off-site device to update, upon user request, information in the FIT / MACP section substantially in real time. In some embodiments, the first set of instructions further causes the off-site device to: generate, on the control panel, a pressure control section that allows the user to: select a pressure control mode for the pressure-managed drilling system; select a depth level; and enter a pressure value or an ECD value, the pressure control section displaying a corresponding depth value for the depth level and a pressure or ECD for the depth level; update, upon user request, information in the pressure control section substantially in real time; and control the pressure management apparatus based at least in part on the pressure value or the ECD value. In some embodiments, the first set of instructions further causes the off-site device to: generate, on the control panel, a choke control section displaying a first mode indicator showing whether the first choke is in automatic or manual mode, the first mode indicator being configured to allow the user to select between automatic and manual modes, wherein when the first mode indicator is in automatic mode, the first choke is controlled by the on-site device based at least in part on the information displayed on the control panel; and when the first mode indicator is in manual mode, the status and opening of the first choke are adjustable by the user through user input in the choke control section; update, upon user request, the information in the choke control section substantially in real time;and when the first mode indicator is in manual mode, control the pressure management device based at least in part on user input in the choke control section. In some embodiments, the first set of instructions further causes the off-site device to: generate, on the control panel, a choke operator safety settings section that allows the user to enter one or more of: a safe surface backpressure upper limit, an emergency choke opening for the first choke, and an emergency choke opening for the second choke; update, upon user request, information in the choke operator safety settings section substantially in real time; and control the pressure management apparatus based at least in part on the safe surface backpressure upper limit, the emergency choke opening for the first choke, and the emergency choke opening for the second choke. In some embodiments, the on-site device comprises a user interface having a display; an on-site control panel accessible through the on-site device display; and one or more processors having access to a second set of instructions which, when executed by at least one of the one or more processors of the on-site device, cause the on-site device to: generate, on the on-site control panel, one or more of: a gain / loss calibrator; a surface backpressure calibrator; an ICP pressure calibrator; a standpipe pressure calibrator; a downhole pressure calibrator; an ICP ECD calibrator; a downhole ECD calibrator; an annular friction loss calibrator; a custom depth ECD calibrator; and a custom depth pressure calibrator;and iteratively update the on-site control panel to display one or more of the gain / loss calibrator, surface backpressure calibrator, ICP pressure calibrator, standpipe pressure calibrator, downhole pressure calibrator, ICP ECD calibrator, and downhole ECD calibrator substantially in real time. In some implementations, the gain / loss gauge is displayed as a vertical bar chart visualization. In some embodiments, at least one of the surface backpressure gauge, ICP pressure gauge, standpipe pressure gauge, downhole pressure gauge, ICP ECD gauge, and downhole ECD gauge is shown as a dial indicator display. In some embodiments, the first choke comprises a choke cartridge, and the second set of instructions further causes the device on site to: generate, on the control panel on site, a choke cartridge status indicator showing whether the choke cartridge is inserted or removed; and iteratively update the control panel on site to display the choke cartridge status indicator substantially in real time. In some embodiments, the first choke cartridge indicator comprises interactive buttons to allow a choke cartridge position to be adjusted by the user, and the second set of instructions further causes the on-site device to control the pressure management apparatus based at least in part on the interactive buttons of the first choke cartridge indicator. In some embodiments, the second set of instructions causes the on-site device to: generate, on the on-site control panel, a PMA status indicator showing whether the fluid is flowing through one or both of the first and second chokes or bypassing both the first and second chokes, the PMA status indicator comprising interactive buttons to allow flow and bypass to be adjusted by the user; iteratively update the on-site control panel to display the PMA status indicator substantially in real time; and control the pressure management apparatus based at least in part on the interactive buttons of the PMA status indicator. In some embodiments, the second set of instructions further causes the on-site device to: generate, on the on-site control panel, an operation indicator showing the current operation of the managed pressure drilling system, the operation indicator comprising interactive buttons to allow the current operation to be adjusted by the user; iteratively update the on-site control panel to display the operation indicator substantially in real time; and control the pressure management apparatus based at least in part on the interactive buttons of the operation indicator. In some embodiments, the pressure management apparatus comprises a pressure management device positioned at a wellhead of the well. In some embodiments, the pressure management apparatus comprises an integrated pressure management device positioned at a wellhead of the well. In another broad aspect of this disclosure, a computer-implemented procedure for controlling a drilling operation of a managed pressure drilling system for a well is provided, the procedure comprising: ινΐΛ / a / zuzo / uii ouu (a) receive a data stream from a pressure management apparatus and an electric drilling recorder system, the data stream generated in real time by a plurality of sensors of the pressure management apparatus and the electronic drilling recorder; (b) process the data flow to generate operational information of the managed pressure drilling system, the operational information comprising one or more of: a well depth; a depth of a drill bit in the well; a remaining length for a subsequent drill string segment connection; a pump rate of a drilling fluid entering the well; a flow rate of drilling mud entering the pressure management apparatus; a weight of mud from the drilling fluid entering the well; a weight of mud from the drilling mud coming out of the well; a surface counterpressure; a casing midpoint pressure (ICP); an equivalent circulating density (ECD) of ICP; a bottomhole pressure; a bottom-hole ECD; surface backpressure limit; a pressure spike; an ejection speed; a state of a first throttle of the pressure management apparatus; a state of a second throttle of the pressure management apparatus; an opening of the first choke; and an opening of the second choke; (c) provide a visual presentation of operational information on a device outside the remote well site; (d) repeating (a) to (c) over time, to update the visual display throughout the drilling operation; and (e) controlling the pressure management apparatus on the basis of a command, the command being determined on the basis at least in part of the visual display. ΐνίΛ / α / ^υZ J / UI IOUU In some embodiments, the computer-implemented procedure involves receiving user input through the visual display, and the command is determined based at least in part on the user input. BRIEF DESCRIPTION OF THE DRAWINGS The embodiments described herein are illustrative only, with reference to the accompanying simplified, schematic, and not-to-scale drawings. Any dimensions provided in the drawings are for illustrative purposes only and do not limit the scope as defined in the claims. In the drawings: Figure 1A is a schematic view of a managed pressure drilling system having a control system in accordance with an embodiment of the present disclosure. Figure 1B is a schematic view of an alternative managed pressure drilling system having the control system in accordance with another embodiment of the present disclosure. Figure 1C is a schematic view of another managed pressure drilling system having the control system in accordance with yet another embodiment of this disclosure. Figures 1A through 1C may be collectively referred to herein as Figure 1. Figure 2 is a schematic view of a pressure management apparatus of a managed pressure drilling system, according to an embodiment of the present disclosure. Figure 3A is a schematic view of the control system, shown with its environment, according to an embodiment of the present disclosure. Figure 3B is a schematic view of the control system, shown with its environment, according to another embodiment of the present disclosure. Figure 3C is a schematic view of the control system, shown with its environment, according to yet another embodiment of the present disclosure. Figure 4 is a sample control panel screen for a user interface of a device at the control system site, according to an embodiment of the present disclosure. Figure 5A is a sample control panel display for an off-site device user interface of the control system, according to an embodiment of the present disclosure. iviA / a / zuzo / uii ouu Figure 5B is an alternative embodiment of the control panel in Figure 5A. Figure 6 is a schematic view of a sample configuration of a control system network, according to an embodiment of the present disclosure. Figure 7 is a flowchart of a sample procedure that can be performed by a device outside the control system site, according to an embodiment of this disclosure. Figure 8 is a flowchart of a sample procedure that can be performed by a device at the control system site, according to an embodiment of this disclosure. DETAILED DESCRIPTION OF THE ACHIEVEMENTS All terms not defined herein shall be understood to have their common meanings recognized in the art. To the extent that the following description relates to a specific embodiment or particular use, it is intended to be illustrative only and not limiting. The following description is intended to cover all alternatives, modifications, and equivalents included within the scope, as defined in the appended claims. According to the realizations in this document, a control system allows the monitoring and control of MPD operations and / or devices to be carried out remotely and almost in real time from an off-site location via the Internet. Figure 1A illustrates an MPD system 10a for drilling a well 16 through a formation F below the earth surface E. The MPD system 10a comprises a rotary control device (RCD) 12 and a blowout preventer (BOP) stack 28, through which a sealed drill string 14 extends. A portion of the drill string 14 extends into the bottom hole of well 16. The drill string 14 has a proximal end that is above the surface E, above the RCD 12, and is coupled to an upper drive (not shown) that is supported on a platform 26. The drill string 14 has a distal end that extends into well 16 and to which a drill bit 18 is attached. A circular wellbore crown 24 is defined between the outer surface of the drill string 14 and the inner surface of the well 16.System 10a also includes mud pumps 60, a standpipe (not shown), a mud tank (not shown), mud handling equipment 50, and various flow lines, as well as other conventional components such as a multi-phase flow meter 30 and a gas evaluation device 40. iviA / a / zuzo / uii ouu RCD 12 can be a conventional RCD comprising a bearing assembly (not shown) having a sealing element and a bowl (not shown) to receive the bearing assembly. Drill string 14 slides across the sealing element of the bearing assembly. The sealing element seals around the outside diameter of drill string 14 and rotates with the drill string 14 as the drill string 14 rotates relative to the bowl during drilling operations. MPD System 10a further comprises a choke manifold 20 that is positioned between and operatively coupled to the RCD 12 and the mud handling equipment 50 via flow lines. The choke manifold 20 is downstream of the RCD 12 and upstream of the mud handling equipment 50. The choke manifold 20 is in fluid communication with the circular crown 24 via the RCD 12 and operates to manage the pressure within the well 16 during drilling. In some embodiments, the manifold 20 has one or more chokes (not shown), a mass flow meter (not shown), one or more pressure sensors (not shown), a controller (not shown) for controlling the operation of the manifold 20, and a hydraulic power unit (not shown) and / or electric motor (not shown) for driving the chokes. The mass flow meter may be a Coriolis-type flow meter. The mud handling rig 50 can include a variety of equipment, such as shale shakers, mud tanks, degassers, etc., and a person skilled in the technique will appreciate that the specific equipment used in the rig 50 may vary depending on the drilling requirements. The mud handling rig is operationally coupled to, and in fluid communication with, the mud pumps 60. In operation, the MPD system 10a is used to control the pressure in the bottom hole by manipulating the pressure applied at the surface while drill bit 18 extends the reach or penetration of well 16 into formation F. To this end, drill string 14 is rotated, and overbit weight is applied to drill bit 18, causing it to rotate against the bottom of well 16. Simultaneously, mud pumps 60 circulate drilling fluid to drill bit 18 through the inner hole of drill string 14. Drilling fluid is discharged from drill bit 18 into well 16 to remove drill cuttings from the bit. The drill cuttings are carried back to the surface by the drilling fluid through the circular crown 24.Drilling fluid and drill cuttings, in combination, are also referred to in this document as drilling mud. From the circular crown 24, the drilling mud flows into the RCD 12, and the RCD sends the drilling mud to the choke manifold 20 while isolating well 16 from atmospheric conditions. The RCD 12 may include any suitable pressure containment device that maintains well 16 in a closed loop at all times while the well is being drilled. The choke manifold 20 provides adjustable surface backpressure to the drilling mud to maintain a desired pressure profile within well 16. As the drilling mud flows through the choke manifold 20, the choke manifold 20 flow meter measures the return flow and density. The drilling mud exiting the choke manifold 20 flows to the mud handling equipment 50, where the drilling fluid is separated from the drilling mud.The separated drilling fluid is then recirculated by mud pumps 60 to drill bit 18, through drill string 14. Figure 1B shows an alternative MPD system 10b. MPD system 10b has the same components as MPD system 10a (Figure 1A) except that system 10b comprises a pressure management device (PMD) 22 instead of the choke manifold 20. In the illustrated embodiment, the PMD 22 is positioned at the wellhead, attached to the RCD 12 on top of the BOP stack 28, and is configured to receive fluid from the circular wellbore crown 24 through the BOP stack 28 and RCD 12. Like the manifold 20, the PMD 22 operates to exert adjustable backpressure in the well 16.In some embodiments, the PMD 22 comprises one or more chokes (not shown), a flow meter (not shown), one or more pressure sensors (not shown), one or more position sensors (not shown), a controller (not shown) for controlling the operation of the PMD 22, and one or more hydraulic power units (not shown) and / or electric motors (not shown) for operating the PMD 22. An example of the PMD 22 is disclosed by the applicant in PCT patent application No. PCT / CA2021 / 050042, which is incorporated herein by reference in its entirety. Drilling mud exiting the circular wellhead 24 flows into the PMD 22 through the BOP stack 28, and from the PMD 22, the drilling mud is sent to the mud handling equipment 50 for processing and recirculation as described above. Figure 1C shows another alternative MPD system 10c. MPD system 10c has the same components as MPD system 10a (Figure 1A) except that system 10c comprises an integrated pressure management device (IPMD) 32 instead of the RCD 12 and choke manifold 20. In the illustrated embodiment, the IPMD 32 is connected to the BOP stack 28 at the wellhead and is configured to receive fluid from the circular wellbore crown 24 through the BOP stack 28. The IPMD 32 is configured to perform the functions of both the RCD 12 and the choke manifold 20, i.e., to apply backpressure to well 16 while sealing well 16 from the atmosphere.In some embodiments, the IPMD 32 comprises a bearing assembly (not shown), a bowl (not shown), one or more chokes (not shown), a flow meter (not shown), one or more pressure sensors (not shown), one or more position sensors (not shown), a controller (not shown) for controlling the operation of the IPMD 32, and one or more hydraulic power units (not shown) and / or electric motors (not shown) for operating the IPMD 32. An example of the IPMD 32 is also described in PCT Patent Application No. PCT / CA2021 / 050042. Drilling mud exiting the circular wellhead 24 flows into the IPMD 32 through the BOP stack 28, and from the IPMD 32, the drilling mud is sent to the mud handling equipment 50 for processing and recirculation as described above. In this disclosure, each of the combinations of RCD 12 and choke manifold 20; RCD 12 and PMD 22; and IPMD 32 may be referred to as a pressure management appliance (PMA). With reference to Figure 1, MPD system 10a, 10b, 10c has a control system 100 configured to monitor and control the operating parameters of system 10a, 10b, 10c, or at least the PMA of system 10a, 10b, 10c. In some embodiments, the control system 100 is communicatively coupled to MPD system 10a, 10b, 10c and has processing capabilities to monitor and control system 10a, 10b, 10c. Figure 2 shows sample components of the PMA 122. In some embodiments, the PMA 122 has a control unit 170. In some embodiments, the control unit 170 comprises a controller 172, a communication module 174, a motor drive module 176, and a radio remote control module 178. In some embodiments, the controller 172 may include a processor or other control circuitry configured to execute instructions from a program that controls the operation of the PMA 122. The controller 172 may be a programmable logic controller (PLC) or any suitable controller known to those skilled in the art. In some embodiments, the controller 172 is configured to receive input from sensors and / or other components in the PMA 122 and to control the operation of one or more components of the PMA 122.In some embodiments, controller 172 can use the WITS (Well Site Information Transfer Specification) communication format for a variety of data monitored and collected at the drilling site. In some embodiments, controller 172 is configured to control the operation of one or more of the communication module 174, motor drive module 176, and radio remote control module 178. In some embodiments, controller 172 is configured to execute commands it receives from another device and / or commands based on pre-written code within controller 172 to control the various components described below in PMA 122. The communication module 174 is a communication device configured to exchange communications with another device via a wired or wireless connection. For example, the communication module 174 might be a wireless communication device configured to exchange communications over a wireless network. In some embodiments, the wireless communication device might include one or more GSM modules, radio modems, cellular transmission modules, or any type of module configured to exchange communications in one of the following formats: GSM or GPRS, CDMA, EDGE or EGPRS, EV-DO or EVDO, UMTS, or IP. In another example, the communication module 174 might be a wired communication device configured to exchange communications using a wired connection.In some implementations, the communication module 174 may be a modem, a network interface card, or another type of network interface device. In some implementations, the communication module 174 may be an Ethernet network card configured to allow the control unit 170 to communicate over a local area network and / or the Internet. iviA / a / zuzo / uii ouu The motor drive module 176 is configured to communicate with and receive commands from controller 172. The motor drive module 176 is operationally coupled and in communication with one or more motors in the PMA 122 and, based on the commands received from controller 172, the motor drive module 176 operates to drive the one or more motors. The radio remote control module 178 is configured to communicate with and receive commands from controller 172. In some embodiments, the radio remote control module 178 receives commands from controller 172 via radio signals. The radio remote control module 178 is configured to communicate wirelessly with one or more mechanical devices (not shown), such as a joystick coupled to an actuator, to move one part of PMA 122 relative to another part of the PMA. For example, an actuator can be used to move the bearing assembly relative to the bowl of PMA 122, and the actuator's movement is controlled by a joystick, which can be operated manually by the operator or remotely by the radio remote control module 178 via radio signals.Based on commands from controller 172, radio remote control module 178 can actuate the joystick to move the bearing assembly relative to the bowl. In some embodiments, the PMA 122 has a plurality of data acquisition devices, which may include one or more of: a pressure sensor, a temperature sensor, a position sensor, a flow meter, etc. In some embodiments, the PMA 122 comprises a pressure sensor 124, a temperature sensor 126, and a flow meter 128, which may be located at or near an inlet (not shown) of the PMA 122 to measure the pressure, temperature, and flow rate of the fluid entering the PMA 122. The pressure sensor 124, the temperature sensor 126, and the flow meter 128 may communicate with the control unit 170 via a wired connection (e.g., Ethernet, USB, etc.) or wirelessly (e.g., Wi-Fi, Bluetooth®, etc.) and may be configured to transmit data to the control unit 170. In some embodiments, the PMA 122 has one or more chokes 130a, 130b. Each choke 130a, 130b may have a respective choke position sensor 132a, 132b to determine the position of the choke cutout relative to the choke orifice. The closer the choke cutout is to the choke orifice, the more "closed" the choke will be. A choke is completely closed if substantially no fluid can flow through it. Likewise, the farther the choke cutout is from the choke orifice, the more "open" the choke will be. In some embodiments, the opening ΐνίΛ / α / ^υZ J / UI IOUU of a choke can be indicated by a percentage value, 100% being fully open and 0% being fully closed.In the illustrated embodiment, each choke 130a, 130b of the PMA 122 has a respective choke motor 142a, 142b to drive a choke actuator (not shown) to change the position of the choke cutout relative to the choke hole of the choke, to make the choke more open or more closed. In some embodiments, a respective choke valve position sensor 134a, 134b is associated with each choke 130a, 130b to determine whether the choke is online or offline. A choke is online if it is in fluid communication with the wellbore circular crown 24. A choke is offline if it is not in fluid communication with the wellbore circular crown 24. Each choke 130a, 130b may comprise a respective choke valve motor 144a, 144b to actuate an actuator (not shown) to put the choke online or offline. In some embodiments, one or more of the chokes 130a, 130b may be of a cartridge-style choke type, as described in PCT patent application No. PCT / CA2021 / 050042, wherein the choke comprises a choke housing and a choke cartridge removably received in the choke housing. In these embodiments, the choke 130a, 130b may have a respective choke cartridge position sensor 136a, 136b to determine the position of the choke cartridge relative to the choke housing, i.e., whether the choke cartridge is fully installed in the choke housing. When the choke cartridge is fully installed in the choke housing, the choke cartridge may be referred to as inserted.When the choke cartridge is removed from the choke housing, the choke cartridge may be referred to as removed. When the choke 130a, 130b is a choke cartridge style type, the choke may comprise a choke cartridge motor 146a, 146b to drive an actuator (not shown) to move the choke cartridge relative to the choke housing. The choke position sensors 132a and 132b, the choke valve position sensors 134a and 134b, and the choke cartridge position sensors 136a and 136b can communicate with the control unit 170 via a wired or wireless connection and are configured to transmit data to the control unit 170. The choke motor 142a and 142b, the choke valve motor 144a and 144b, and the choke cartridge motor 146a and 146b can communicate with the control unit 170 via a wired or wireless connection and are configured to be driven by the motor drive module 176. The PMA 122 may have a flow line valve 150 that controls fluid flow in a choke narrowing line (not shown) of the PMA 122. In some embodiments, if the choke narrowing line is open, fluid entering the PMA 122 flows through the choke narrowing line while bypassing chokes 130a and 130b and exits the PMA 122. If the choke narrowing line is closed, fluid entering the PMA 122 flows through one or more of the chokes 130a and 130b and then exits the PMA 122. In some embodiments, the PMA 122 has a flow line valve position sensor 152 to determine whether the choke narrowing line is open or closed.The flow line valve position sensor 152 can communicate with the control unit 170 via a wired or wireless connection and is configured to transmit data to the control unit 170. In some embodiments, the PMA 122 has a flow line valve motor 154 to drive an actuator (not shown) to change the position of the flow line valve 150 to open and close the choke narrowing line. The flow line valve motor 154 can communicate with the control unit 170 via a wired or wireless connection and is configured to be driven by the motor drive module 176. In some embodiments, the PMA 122 comprises an RCD module 160 having a bearing assembly (not shown) and a bowl (not shown) for receiving the bearing assembly. In some embodiments, the RCD module 160 comprises at least one position sensor 162 for determining the position of the bearing assembly relative to the bowl, i.e., whether the bearing assembly is attached to the bowl. The position sensor 162 can communicate with the control unit 170 via a wired or wireless connection and can be configured to transmit data to the control unit 170. In some embodiments, the RCD module 160 has a latching motor 164 for driving an actuator (not shown) to move the bearing assembly relative to the bowl, for the purpose of securing the bearing assembly to the bowl and releasing the bearing assembly from the bowl.The coupling motor 164 can be in communication with the control unit 170 by wired or wireless connection and can be configured to be driven by the motor drive module 176. In some embodiments, the bearing assembly can be rotatably secured to the bowl, as described by the Applicant in U.S. Provisional Patent Application No. 63 / 115,720, which is incorporated herein by reference in its entirety. In some embodiments, the PMA 122 comprises a digital camera 180 or other type of optical sensing device for capturing images and / or video of the PMA 122. In some embodiments, the camera 180 is used to capture images and / or video of the RCD module 160 to help determine the position of the bearing assembly relative to the bowl. The camera 180 can communicate with the control unit 170 via a wired or wireless connection and can be configured to transmit data to the control unit 170. In some embodiments, the bearing assembly and / or the bowl may have visual indicators on their outer surfaces that can be easily captured by the camera 180 to facilitate the determination of the relative positions of the bearing assembly and the bowl. It can be seen that other embodiments of the PMA 122 may comprise only some of the components mentioned above. In alternative embodiments, instead of motors, the PMA may comprise other drive mechanisms, such as hydraulic power units, pneumatic power units, etc., to drive one or more actuators (not shown) in the PMA. Each of the sensors, flow meter 128, and camera 180 mentioned above in the PMA may transmit data continuously to the control unit 170, transmit data periodically to the control unit 170, or transmit data to the control unit 170 in response to a change in previously collected data. Figure 3A shows a sample configuration of the control system 100 in its environment. In the illustrated embodiment, the control system 100 is configured to allow an operator (also referred to as a user) to monitor and control the PMA 122 of a drilling system (e.g., MPD system 10a, 10b, 10c in Figure 1) from both an on-site and an off-site location. Although the control system 100 is described herein in connection with the monitoring and control of a PMA, it can be seen that the control system 100 can be configured to monitor and control other or additional components of the drilling system. ΐνίΛ / α / ^υZ J / UI IOUU System 100 comprises at least one on-site communication device 202 and at least one off-site communication device 204, both connected to and communicating with an interactive communication network 222. Also connected to the network 222 are one or more server computers 224, which store information and make it available to the on-site and off-site devices 202 and 204. The network 222 enables communication between and within the on-site device 202, the off-site device 204, and the servers 224. The network 222 may be a collection of interconnected public and / or private networks linked together by a set of standard protocols to form a distributed network.Although the 222 network is intended to refer to what is now commonly called the Internet, it is also intended to encompass variations that may be made in the future, including changes and additions to existing standard protocols. It may also include various networks used to connect mobile and wireless devices, such as cellular networks. When 224 servers are physically remote from users of 202, 204 devices on-site and off-site, but are accessible to those users through the 222 network, the 224 servers are sometimes referred to in this document as being in the cloud. In some implementations, the 222 network and 224 servers are part of a virtual private cloud (VPC). The 224 servers can use a variety of operating systems and software optimized for content delivery across networks. The 222 network may include one or more networks that have wireless data channels.In some implementations, network 222 is configured to host data stream generation platforms, such as Apache Kafka®, and / or database management services, such as Apache Cassandra®, to support the operation of system 100. Device 202 on-site and devices 204 off-site can connect to network 222 via a broadband connection such as a digital subscriber line (DSL), cellular radio, or other form of broadband connection to the Internet. In some embodiments, the on-site device 202 and / or the off-site devices 204 can access the 222 network via an internet service, such as a web browser or application on the device, which establishes a communication link with the 222 network. The off-site device 204 can receive data from the on-site device 202 via the 222 network, or the 224 servers can relay data received from the on-site device 202 to the off-site device 204 via the 222 network. In some embodiments, the 224 servers can facilitate communication between the on-site device 202 and the off-site device 204. The on-site communication device 202 is located at the drilling site, in close physical proximity to the PMA 122 control unit 170. The on-site device 202 may comprise one or more processors and may be equipped with communications hardware such as a modem or a network interface card. The one or more processors may be, for example, general-purpose processors, multi-chip processors, embedded processors, etc. In some embodiments, the on-site device 202 has a user interface and hosts one or more software programs and / or applications. The user interface may comprise one or more of the following: a keyboard, a mouse, a touchpad, a display, a touchscreen, audio speakers, and a printer. In some embodiments, the on-site device 202 may receive user input through the user interface.Device 202 on site may comprise a storage medium, which may include one or more of: random access memory (RAM), electronically erasable programmable read-only memory (EEPROM), read-only memory (ROM), hard disk, floppy disk, CD-ROM, optical memory, or other mechanisms for storing data. The on-site device 202 can be operationally coupled and in communication with the PMA 122 control unit 170. The on-site device 202 can be connected via a wired connection (e.g., Ethernet) or wirelessly to the control unit 170 on, for example, a local communication network (e.g., local area network (LAN)) at the drilling site. In some embodiments, the on-site device 202 can also be in communication with an electronic drilling recorder (EDR) system 206 of the drilling system. The EDR system communicates with and collects data from a variety of sensors located on the rig. The on-site device 202 can be coupled via a wired connection or wirelessly to the EDR system 206 on, for example, a local communication network at the drilling site. In some embodiments, the on-site device 202 is configured to host software programs and / or applications for managing the PMA 122 (“PMA software 212”). In some embodiments, the on-site device 202 can operate the PMA software 212 locally or within a local network at the drilling site. The PMA software 212 can access data collected by the sensors and the flow meter of the PMA iviA / a / zuzo / uii ouu 122 through the control unit 170. The PMA software 212 can also send electronic communications (e.g., commands, data, etc.) to the control unit 170 to cause the control unit 170 to change one or more settings of the PMA 122. When the on-site device 202 is connected to the EDR system 206, the PMA software 212 can access data from the sensors on the platform. In some embodiments, the PMA software 212 can send communications (e.g., data) to the EDR system. The data provided to the PMA software 212 by the control unit 170 and the EDR system can be direct data captured by the sensors and the flow meter or it can be processed before being received by the PMA software 212. In some embodiments, PMA software 212 can send and receive communications to and from network 222. In some embodiments, PMA software 212 is configured to communicate with and control aspects of PMA 122 through control unit 170 and to communicate with off-site devices 204 through network 222. In additional or alternative embodiments, at least some of PMA software 212 may be stored on servers 224. In some embodiments, servers 224 may receive data from PMA software 212, store the received data, and perform analysis on the received data. Based on the analysis, servers 224 may send communications to one or both of on-site devices 202 and off-site devices 204. In some embodiments, with reference to Figures 1 and 3, by exchanging communications with the control unit 170 and, optionally, the EDR system 206, the PMA software 212 of the device 202 on-site is configured to allow an operator to monitor and control the PMA 122 during a drilling operation. This operation may include one or more of the following, for example: drilling well 16, connecting drill string 14, ejecting drill string 14, circulating fluid in well 16, reaming well 16, handling a kick or loss while drilling well 16, and any offline operations. In some embodiments, the PMA software 212 provides a platform for monitoring all sensors on the PMA 122 (and optionally the EDR system sensors) and for controlling the settings of various components on the PMA 122.In some embodiments, the on-site device 202 can store data collected from the control unit 170 and, optionally, the EDR system. In some embodiments, the PMA software 212 can receive user input from the operator via the user interface to adjust one or more PMA 122 settings. Upon receiving user input, the PMA software 212 generates an appropriate command and sends it to the control unit 170. When a command is generated by the PMA software 212 based on user input, the command is referred to as manually generated. In some implementations, based at least in part on the collected data, the PMA 212 software can perform various analyses on the operating parameters of the drilling system and subsequently send commands to the PMA 122 control unit 170 to obtain the desired parameters for the drilling operation. When a command is generated by the PMA 212 software based on an analysis performed by the software, the command is referred to as auto-generated. Commands for the PMA 122 can thus be obtained manually or auto-generated by the PMA 212 software through an automated sequence of actions. Whether obtained manually or auto-generated, the commands can be sent by the PMA 212 software to the control unit 170 to adjust the PMA 122 settings, for example, to manage well pressure during drilling.In one example, PMA software 212 can signal control unit 170 to change the position of one or both of the chokes 130a, 130b. In some embodiments, the PMA 212 software may include preset rules that dictate acceptable values ​​for the monitored variables, for example, acceptable ranges. In some embodiments, the preset rules may be generated by the PMA 212 software based on its own analysis. In additional or alternative embodiments, the preset rules are based on user input and / or may be modified by user input. In some embodiments, based on data provided by the control unit 170, if the PMA 212 software determines that any of the preset rules are violated, the PMA 212 software may notify the operator of the user input by sending an alert, such as a pop-up box on the screen of the device 202 on site, a text message or email to the operator, or other procedures known to those in the art.In alternative or additional embodiments, after determining that a pre-established rule has been violated, the PMA software can send a self-generated command to the control unit 170 to correct the problem. In some embodiments, PMA's 212 software can employ real-time hydraulic, torque and drag (T&D), and / or wellbore stability (WBS) models. In some embodiments, PMA's 212 software provides real-time analysis and predictions of future drilling events. By monitoring data provided by the 170 control unit and optionally the 206 EDR system, PMA's 212 software can predict future drilling problems and events before they occur. For example, PMA's 212 software can provide real-time hydraulic analysis and control using algorithms that incorporate the effects of temperature and pressure on downhole fluid hydraulics. With reference to Figures 2 and 3, in some embodiments, based on data provided by the PMA 122 control unit 170 and the EDR system 206, the on-site PMA software 212 of device 202 can monitor the fluid flow rate entering the PMA 122 (measured by flow meter 128), the injection pressure (or standpipe pressure) provided by the EDR system 206, the surface backpressure (measured by pressure sensor 124), the position of chokes 130a and 130b (determined by position sensors 132a and 132b), and the mud density of the drilling fluid (measured by flow meter 128). By monitoring any deviations in these variables, the PMA software 212 can identify fluid inflows to the well from the formation and drilling mud losses to the formation in real time.After detecting such inflows or losses, the PMA 212 software can automatically send the necessary commands to the control unit 170 to control or correct the inflows or losses, or it can notify the operator of the device 202 on site of a specific user input by sending an alert. In some embodiments, by monitoring deviations in the variables mentioned above, the PMA 212 software can detect choke blockage or other choke failures. Upon detecting such failures, the PMA 212 software can automatically send commands to the control unit 170 to mitigate these failures or can alert the operator to user input. For example, the PMA 212 software can send a command, either obtained manually or self-generated, to the control unit 170 to take the failed choke offline and bring the other choke online so that the fluid can be redirected to the other choke.For example, if choke 130a is online and choke 130b is offline but PMA software 212 detects a fault in choke 130a, then the PMA software sends a command to control unit 170 to cause motor drive module 176 to drive choke valve motor 144a to take choke 130a offline (i.e., blocking fluid flow to it) and drive choke valve motor 144b to take choke 130b online so that fluid entering PMA 122 is redirected to choke 130b. In some embodiments, by monitoring the signals from the choke position sensors 132a and 132b and the choke valve position sensors 134a and 134b, the PMA software 212 can determine which chokes are online and how open they are. When the PMA software 212 (or the on-site operator of device 202) determines that a choke setting change is necessary, the PMA can send a command to the control unit 170 to cause the motor drive module 176 to actuate one or more of the choke motors 142a and 142b and the choke valve motors 144a and 144b. In one example, to further open choke 130a, PMA software 212 sends a command to control unit 170 to cause motor drive module 176 to drive choke motor 142a.In another example, to redirect fluid from one choke 130a to another choke 130b, PMA software 212 sends a command to control unit 170 to cause motor drive module 176 to drive both choke valve motors 144a, 144b, with motor 144a taking choke 130a offline while motor 144b brings choke 130b online. Before drilling begins, the bearing assembly is first secured to the bowl of the RCD module 160. In some embodiments, the PMA software 212 can facilitate the procedure of securing the bearing assembly to the bowl by monitoring the signal from the position sensor 162 and, optionally, images or footage captured by the camera 180 to determine whether the bearing assembly is secured to the bowl. For example, after determining that the bearing assembly is not yet secured to the bowl, the PMA software 212 can send a command to the control unit 170 to cause the motor drive module 176 to drive the engagement motor 164 to move the bearing assembly relative to the bowl. Figure 4 shows a sample control panel 400 provided by the PMA software 212, which can be accessed by an operator via the device user interface screen 202 on-site. The control panel 400 can be configured to display monitored variables in real time and to allow the operator to control the PMA settings in real time. In the illustrated embodiment, the control panel 400 comprises a pressure section 402, a choke section 420, a peak / piston section 430, a status section 440, a current operation section 460, and a control section 480. In some embodiments, the pressure section 402 has a gain / loss gauge 404 that displays any gain or loss of drilling fluid in the drilling system, a surface backpressure (SBP) gauge 406 that displays the surface backpressure in real time, a casing midpoint pressure (ICP) gauge 408, an equivalent circulating density (ECD) gauge 410 of ICP that displays the ICP pressure as a density value, a standpipe pressure (SPP) gauge 412, a bottom hole pressure (BHP) gauge 414 that displays the real-time bottom hole pressure in the well, and a bottom hole equivalent circulating density (ECD of BH) gauge 416 that displays the bottom hole pressure as a density value.Real-time surface backpressure can be the pressure as measured by the pressure sensor 124 (Figure 2) of the PMA 122, which is communicated to the PMA software via the control unit 170. Real-time downhole pressure can be calculated by the PMA software based on one or more variables such as well profile, drill string profile, surface backpressure, mud density, mud properties, drilling fluid pump rate, drill string rpm, downhole temperature, surface temperature of drilling mud, peak and piston effect based on drill string movement, drilling mud column (drilling mud profile) in the circular crown, etc., using procedures known to those skilled in the art.In the illustrated embodiment, indicator 404 is shown as a vertical bar chart display, and each of the gauges 406 through 416 is shown as a dial indicator display. In some embodiments, each dial indicator display may have color-coded portions to indicate a safe / optimal range and an unsafe / undesirable range. In other embodiments, not shown here, the pressure section 402 is configured to display alternative or additional gauges to display other well data such as, for example, annular friction losses, custom depth ECD, custom depth pressure, etc. iviA / a / zuzo / uii ouu In some embodiments, the choke section 420 displays the current operating status of each choke in the drilling system. For example, in the illustrated embodiment, the drilling system has two chokes: choke A and choke B. The choke section 420 can display the status of each choke—that is, whether each choke is online or offline—via choke status indicators 422a and 422b. For example, in Figure 4, choke status indicator 422a shows that choke A is online, while choke status indicator 422b shows that choke B is offline. In some embodiments, each of the indicators 422a and 422b has interactive buttons that allow the operator to adjust the corresponding choke as online or offline.Depending on the setting selected by the operator, the PMA software can generate and send the necessary commands to the control unit 170 to cause one or both choke valve motors (e.g., choke valve motors 144a, 144b in Figure 2) to adjust one or both choke valves A and B to match the setting selected by the operator. The choke section 420 can also show how open each choke is by means of choke position indicators 424a and 424b. For example, in Figure 4, choke position indicator 424a shows that choke A is 50% open, while choke position indicator 424b also shows that choke B is 50% open. In the choke section 420, each choke can have a respective choke position adjuster 426a and 426b, and each choke position adjuster can have a respective mode indicator 428a and 428b that shows whether the corresponding adjuster 426a and 426b is in manual or automatic mode. When a choke is in line (e.g., choke A in Figure 4), a target choke opening can be set using the corresponding choke position adjuster (e.g., choke position adjuster 426a).If the choke position adjuster 426a is in manual mode, the target opening of the corresponding choke (choke A) can be adjusted by the operator. If adjuster 426a is in automatic mode, the PMA software can adjust the target opening based on data received from the PMA 122 control unit 170 and, optionally, the EDR system 206. In some embodiments, each of the mode indicators 428a and 428b has interactive buttons that allow the operator to select either manual or automatic mode for adjusters 426a and 426b. In some embodiments, when automatic mode is selected, the PMA software reacts by locking the corresponding adjuster 426a and 426b so that the operator cannot modify the target opening of that adjuster.In the sample embodiment shown in Figure 4, choke A is open to 89%, and the target opening is set to 80% on adjuster 426a by the operator (since adjuster 426a is in manual mode, as shown by indicator 428a). If the target opening differs from the actual opening indicated by indicator 424a, the PMA software can generate and send the necessary commands to control unit 170 to cause the choke motor (e.g., choke motor 142a in Figure 2) of choke A to open or close the choke until the actual choke opening reaches the target opening. In some embodiments, the 430 peak / piston section has an ejection velocity gauge 434 that displays the ejection velocity of the drill string 14. The 430 peak / piston section may also have a 432 peak / piston gauge that displays the peak or piston pressure, which is calculated based on the ejection velocity and other variables such as drill string direction of movement, wellbore profile, drill string profile, drilling mud profile, drilling mud properties, and final drill string conditions, using procedures known to those skilled in the art. In embodiments where chokes A and B are cartridge-style chokes, status section 440 has choke cartridge status indicators 442a and 442b that show whether the respective choke cartridges for chokes A and B are inserted (“inserted”) into their corresponding choke housings or removed (“removed”) from their respective choke housings. In some embodiments, each indicator 442a and 442b has interactive buttons that allow the operator to adjust the choke cartridge status (i.e., inserted or removed) of the corresponding choke. Based on the operator's selection, the PMA software can generate and send the necessary commands to control unit 170 to change the PMA settings to match the operator's selection. For example, with further reference to Figures 2 and 3, if the operator selects to withdraw for choke A (e.g., choke 130a in Figure 2), the PMA software 212 can send a command to control unit 170 to make unit ΐνίΛ / α / ^υZ J / UI IOUU Control unit 170 checks if choke 130a is offline based on the signal from choke valve position sensor 134a. If choke 130a is not offline, control unit 170 can send a signal to motor drive module 176 to cause choke valve motor 144a to take choke 130a offline. If control unit 170 confirms that choke 130a is offline, it can signal motor drive module 176 to drive choke cartridge motor 146a to withdraw the choke cartridge from the choke housing of choke 130a. Based on the signals from the choke cartridge position sensor 136a, the control unit 170 can confirm that the choke cartridge 130a has been removed and can in turn communicate a confirmation to the PMA software 212.After receiving confirmation, PMA's 212 software can update the choke status 130a on indicator 442a of control panel 400. The status section 440 may also have a PMA status indicator 444 to show whether the fluid is flowing through one or both of the PMA's chokes A and B (i.e., the PMA choke narrowing line 122 is closed) or bypassing both of the PMA's chokes A and B (i.e., the choke narrowing line is open). In the illustrated embodiment, if the fluid is flowing through one or both of the chokes A and B, the PMA is in the "to PMD" mode shown on the PMA status indicator 444. If the fluid is bypassing both chokes A and B, the PMA is in the "to agitator" mode shown on the PMA status indicator. With further reference to Figure 1, the agitator (not shown) is part of the mud handling equipment 50. A agitator indicates that the fluid entering the PMA is flowing towards mud handling equipment 50 without first flowing through either choke A or choke B.In some embodiments, indicator 444 has interactive buttons that allow the operator to select either PMD or agitator mode. Based on which button on indicator 444 the operator selects, the PMA software generates and sends the necessary commands to the control unit 170 to change the PMA settings to match the operator's selection. For example, with further reference to Figures 2 and 3, if the operator selects the shaker mode, the PMA software 212 can send a command to the control unit 170 to check whether the PMA 122 choke narrowing line is open and whether chokes A and B (e.g., chokes 130a, iviA / a / zuzo / uii ouu) are functioning correctly. 130b, respectively) are offline based on signals from flow line valve position sensor 152 and choke valve position sensors 134a, 134b, respectively. If the choke line is open and chokes 130a, 130b are offline, control unit 170 can communicate this to the PMA software, and the PMA software can confirm this to the operator via control panel 400.If the choke narrowing line is closed and one or both chokes 130a and 130b are online, the control unit 170 can then send a signal to the motor drive module 176 to actuate the flow line valve motor 154, changing the position of the flow line valve 150 and thereby opening the choke narrowing line. This also actuates one or both choke valve motors 144a and 144b to take chokes 130a and 130b offline. Based on signals from the flow line valve position sensor 152 and the choke valve position sensors 134a and 134b, the control unit 170 can confirm that the PMA is in agitation mode and communicate this confirmation to the PMA software 212. After receiving confirmation, the PMA 212 software can update the PMA status on indicator 444 of control panel 400. If the operator selects PMD mode, the PMA software 212 can send a command to the control unit 170 to check whether the PMA 122 choke narrowing line is closed and whether one or both chokes 130a and 130b are online, based on signals from the flow line valve position sensor 152 and the choke valve position sensors 134a and 134b, respectively. If the choke narrowing line is closed and one or both chokes 130a and 130b are online, the control unit 170 can communicate this to the PMA software, and the PMA software can confirm this to the operator via the control panel 400.If the choke narrowing line is open and both chokes 130a and 130b are offline, the control unit 170 can then send a signal to the motor drive module 176 to actuate the flow line valve motor 154, changing the position of the flow line valve 150 and thereby closing the choke narrowing line. This actuates one or both choke valve motors 144a and 144b to bring one or both chokes 130a and 130b online. Whether the control unit 170 brings one or both chokes online depends on the user settings in PMA software 212. Based on signals from flow line valve position sensor 152 and choke valve position sensors 134a, 134b, control unit 170 confirms that the PMA is in PMD mode and communicates a confirmation to PMA software 212.After receiving confirmation, the PMA 212 software can update the PMA status on indicator 444 of control panel 400. In some embodiments, the current operation section 460 has an operation indicator 462 that shows whether the current drilling system operation is drilling a well or connecting new drill string segments. In some embodiments, indicator 462 has interactive buttons that allow the operator to select the current drilling system operation. Depending on which button is selected on indicator 462, the PMA software can generate and send commands to the control unit 170 to change the PMA settings to match the operator's selection. For example, if the operator selects connection, the PMA software can send a command to the control unit 170, and then the control unit 170 can send a signal to the motor drive module 176 to drive the choke motor 142a, 142b of the in-line chokes to adjust the choke opening to compensate for changes in annular friction losses in the wellbore during the connection of a new drill string segment.If the operator selects drilling, the PMA software can send a command to control unit 170, which then sends a signal to motor drive module 176 to actuate choke motors 142a and 142b. These inline chokes adjust the choke opening to compensate for changes in annular friction losses in the wellbore after new drill string segments are connected and drilling fluid pumping resumes. In either situation, the amount of adjustment required for the inline choke opening can be automatically determined by the PMA software. In some embodiments, the current operating section 460 also has a standpipe / PMA gauge 464 and a pump rate gauge 466. In Figure 4, the standpipe / PMA gauge 464 displays an ideal pump rate for diverting flow without exceeding the surface limitations of a pump diverter device (not shown) in the drilling system, from the bottom hole (standpipe) through the PMA, to provide continuous circulation during the connection of new drill string segments, so that chokes 130a, 130b can achieve a desired bottom hole pressure under no-flow conditions in the bottom hole. The pump rate gauge 466 can display the pump rate of the mud pump 60 as measured by the sensors in the EDR system. In some embodiments, the control section 480 has a control display indicator 482 that provides four different pressure control modes for the drilling system. The control section 480 may also have a set depth indicator 484 that displays the depth value for a particular set depth. The set depth indicator 484 has a drop-down menu that allows the operator to select the type of set depth to display (e.g., ICP depth). The control section 480 may have a pressure value input 486 with an input box that allows the operator to enter a pressure value. In the illustrated embodiment, the four pressure control modes include: an SBP mode; a BHP mode; a BH ECD mode; and a “none” mode. The control section 480 may have an interactive button 488 to allow the user to confirm selections made in the control section 480.Based on the selections made by the operator in control section 480, the PMA can generate software commands and send them to control unit 170 accordingly. For example, in SBP mode, the operator can set a pressure value (“static SBP”) in the pressure value input box 486, and the PMA software 212 communicates with the control unit 170 to cause the PMA 122 to apply the static SBP (for example, 200 psi) in the well regardless of the mud pump rate 60 or the pressure conditions in the bottom hole of well 16. In BHP mode, the operator can select a set depth type from the set depth indicator 484 drop-down menu and a pressure value (“desired BHP”) in the pressure value input 486. The PMA software then communicates with the control unit 170 to cause the PMA 122 to manipulate the desired BHP at the selected set depth (e.g., 2750.0 psi at an ICP depth of 4150.0 ft) by applying a backpressure at the surface.In BHP mode, the required surface backpressure applied by the PMA 122 can be calculated based on variables such as mud pump rate, drilling mud profile, drilling mud properties, etc. The required surface backpressure can be constantly adjusted to maintain the desired BHP at the set depth. In BHP ECD mode, the operator can select a particular set depth from the drop-down menu of the set depth indicator 484 and, instead of a pressure value, the operator can enter an ECD (Desired ECD) value in the input box of the pressure value input 486. The PMA software can then communicate with the control unit 170 to have the PMA 122 manipulate the desired ECD at the set depth by applying surface backpressure.In none mode, the PMA software can automatically open chokes 130a, 130b fully to release any surface backpressure applied in the previous mode (i.e., SBP, BHP or BH ECD). With reference back to Figure 3A, the at least one off-site communication device 204 of the control system 100 is located at a remote location some distance from the drilling site. Although the illustrated embodiment shows two off-site devices, the control system 100 may have fewer or more off-site devices in other embodiments. In some embodiments, the off-site device 204 comprises one or more processors and storage media. In some embodiments, the off-site device 204 has a user interface and hosts one or more applications. In some embodiments, the off-site device 204 may receive user input through an input device such as a touchscreen, mouse, keyboard, etc.In some embodiments, the off-site device 204 is a portable device with wireless communication capabilities, such as a smartphone, laptop, tablet, or other portable devices capable of communicating over the 222 network and displaying information. In embodiments where the control system 100 has two or more off-site devices, the two or more off-site devices 204 may be identical or may include different types of devices. In further embodiments, the two or more off-site devices 204 may be in different geographical locations but all can communicate with the on-site device 202 at the same drilling site via the 222 network. In some embodiments, the off-site device 204 has a PMA application 214, i.e., a software / firmware program that runs on it, to enable a user interface and features, which will be described in more detail below. The off-site device 204 can load or install the PMA application 214 based on data received over network 222. In some embodiments, the application iviA / a / zuzo / uii ouu PMA Application 214 can be configured to run on mobile device platforms such as iPhone, iPod touch, Blackberry, Google Android, Windows Mobile, etc. In some embodiments, PMA Application 214 can send and receive communications from PMA Software 212 over Network 222. In some embodiments, PMA Application 214 can receive data collected by PMA Software 212 from Device 202 on-site in a real-time transmission over one or more data channels on Network 222. In some embodiments, PMA Application 214 allows the off-site operator of Device 204 to download the data received from PMA Software 212 for subsequent viewing and / or analysis.In some embodiments, PMA application 214 can receive user input from the off-site operator of device 204 via the user interface and, based on that input, send communications to PMA software 212. In some embodiments, PMA software 212 can send communications (e.g., alerts) to PMA application 214 based on data provided by control unit 170 and / or data analysis performed by PMA software 212. In some embodiments, when the off-site device 204 is connected to the on-site device 202, the PMA application 214 can provide the same functionalities as the PMA software 212 but from a location remote from PMA 122. In some embodiments, the PMA application 214 has real-time access to the same data received by the PMA software, and the PMA application 214 can self-generate or manually obtain (i.e., via the user interface) a command and then send the command to the PMA software over the 222 network. Once received, the PMA software can forward the command to the PMA 122 control unit 170 to change one or more PMA settings, as described above.The command sent by PMA application 214 and forwarded to control unit 170 by PMA software can have the same effect on PMA 122 as a command that is self-generated or manually obtained by PMA software 212 itself. PMA application 214 can be configured to allow an off-site device 204 operator to access the on-site device 202 PMA software 212 and the data collected by the on-site device 212, so that the operator can remotely monitor and control the drilling site PMA 122, or aspects thereof, from any location where the off-site device 204 can access the network 222. In some embodiments, PMA application 214 allows the device iviA / a / zuzo / uii ouu 204 off-site connects to PMA 122 remotely, via network 222 and device 202 on-site, and provides the operator of device 204 off-site with real-time remote control of PMA 122. In some embodiments, the PMA application 214 on device 204 off-site operates as a long-range remote control that can operate from anywhere in the world for long-range wireless protocols (e.g., GSM, CDMA, WiMax, etc.) via remote servers, such as servers 224. In some embodiments, based on user settings in PMA Application 214, PMA Application 214 can automatically change one or more settings of PMA 122 on behalf of the operator in response to changes in data received and / or alerts from PMA Software 212. In some embodiments, PMA Application 214 can define preset rules to control PMA 122. The preset rules can be based on user input by the off-site operator of Device 204 or generated by PMA Application 214. In some embodiments, the preset rules dictate an acceptable range for each monitored variable. For example, one of the preset rules might dictate a maximum and a minimum bottomhole pressure set by the operator.When the real-time downhole pressure is not between the minimum and maximum downhole pressure values ​​of the preset rule, the PMA application 214 can automatically communicate with the PMA software 212 of the device 202 on site to cause the control unit 170 to adjust one or both chokes 130a, 130b accordingly. Figure 5A shows a sample control panel 500 provided by PMA application 214, which can be accessed by an operator through the user interface of off-site device 204. In some embodiments, the off-site device 204's PMA application 214 exchanges communications with the on-site device 202's PMA software 212 over network 222. Based on the communications from the PMA software 212, the PMA application 204 generates and updates the control panel 500. In some embodiments, the control panel 500 is configured to display one or more monitored variables in real time, as provided by the PMA software 212, and to allow the off-site device 204 operator to control the PMA settings 122 in real time over network 222. In the illustrated embodiment, the control panel 500 has a date and time indicator 502, a hole depth indicator 504 that shows the real-time depth of the well being monitored, and a drill bit depth indicator 506 that shows the real-time depth of the drill bit in the well. In some embodiments, the control panel 500 also has a block height indicator 508 that shows the remaining length to the next drill string segment connection, an inflow indicator 510 that shows the pump rate of the drilling fluid, an outflow indicator 512 that shows the flow rate of drilling mud entering the PMA, an inflow mud weight (MW) indicator 514 that shows the mud weight of the drilling fluid entering the well, and an outflow MW indicator 516 that shows the mud weight of the drilling mud leaving the well.In some embodiments, the control panel also has a 518 surface backpressure (SBP) indicator that displays the real-time surface backpressure and a 520 target SBP indicator that displays a target SBP value. In some embodiments, the control panel has a 522 ICP pressure indicator and a 524 ICP ECD indicator. In some embodiments, the 500 control panel has a graphical section 530 to provide a graphical representation of one or more of the variables mentioned above. In further embodiments, the graphical section 530 allows the operator to select specific block heights and displays the graphical representation of one or more variables for the selected block heights. In some embodiments, the graphical section 530 may display other variables such as downhole pressure, downhole ECD, choke A and choke B opening and status, surface backpressure, surface backpressure limit, peak pressure, ejection velocity, etc. With reference to Figure 5B, in some embodiments, the control panel 500 comprises a control section 540 with one or more input boxes for receiving user input to allow the operator to adjust the PMA settings. In the illustrated embodiment, the control section 540 has a formation integrity test (FIT) / maximum allowable casing pressure (MACP) section 550, in which the operator can enter one or more of the depth in input box 552, the bottom hole ECD in input box 554, and the pressure gradient in input box 556. Section 550 may include a refresh button 558 for the operator to click after modifying one of the input boxes 552, 554, or 556, so that the real-time values ​​are displayed in this section. ΐνίΛ / α / ^υZ J / UI IOUU In the illustrated embodiment, control section 540 has a pressure control section 560, in which the operator can select the desired pressure control mode for the drilling system in area 562. Pressure control section 560 may also have a drop-down menu 564 that allows the operator to select a depth level, and the corresponding depth value for the selected depth level is displayed in box 566. Box 568 may display the current pressure or ECD value, and the operator can adjust the desired pressure or ECD value in input box 572. In the illustrated embodiment, pressure control section 560 has a choke control section 574 through which the operator can select which choke to put online or offline, under which mode (i.e., manual or automatic) each choke operates, the opening of each choke, etc.After changing the value in one or more input boxes in section 560, the operator can click on a refresh button 576 in section 560 to display the real-time values ​​in this section. In the illustrated embodiment, control section 540 has a choke operator safety settings section 580 that allows the operator to preset a safe high SBP limit in input box 582, an emergency choke opening for choke A in input box 584, and an emergency choke opening for choke B in input box 586. These values ​​can be considered as preset rules. Other configurations of the PMA Application 214 control panel 500 are possible. In some embodiments, one or more calibrators, indicators, buttons, etc., from the PMA software control panel 400 and their corresponding functions may also be included in the control panel 500. In one embodiment, the control panel 500 may appear identical to or similar to the control panel 400. When the operator modifies any of the input boxes, including the drop-down menu, in control section 540, the off-site PMA application 214 on device 204 can send a command to the on-site PMA software 212 on device 202 via the internet. In some embodiments, the PMA application 214 can also automatically generate a command, for example, when a preset rule is violated, and send the command to the PMA software 212. When the PMA software 212 receives the command from the PMA application 214, the PMA software can treat the received command as if it originated from the on-site PMA software. PMA on device 202 at the site, such that a command from PMA application 214 has the same effect on PMA 122 as a command from the PMA software itself. Sample commands from the PMA software and their effects on the PMA are described above and are therefore not repeated here. In some embodiments, the on-site operator of device 202 or the off-site operator of device 204 can determine how much control of PMA 122 to give to control system 100. In some embodiments, the types of operations that control system 100 is permitted to perform automatically are predetermined based on user settings in PMA software 212 and / or PMA application 214. While the embodiment illustrated in Figure 3A shows an on-site device 202 communicating with a PMA 122 and one or more off-site devices 204 communicating with the on-site device 202 via network 222, other configurations are possible. For example, as shown in Figure 3B, the on-site device 202 can be communicating with multiple PMAs 122a, 122b, and 122c at the same drilling site, and the on-site device 202's PMA software 212 is configured to allow the user to monitor and control one or more of the multiple PMAs simultaneously. The off-site device 204 PMA application 214 is configured to communicate with the on-site device 202 via the 222 network as described above, thereby enabling the off-site device user to also monitor and control all PMAs 122a, 122b, 122c.Each of the PMAs 122a, 122b, and 122c may be the same as or similar to the PMA 122 described above; therefore, PMAs 122a, 122b, and 122c will not be described in detail in this document. For simplicity, the components of PMAs 122a, 122b, and 122c are omitted from Figure 3B. In this embodiment, the off-site device 204 control panel 500 can be configured to display data from all PMAs 122a, 122b, and 122c simultaneously or allow the user to select which PMA data to display. The user can thus remotely monitor and control one or more of the PMAs 122a, 122b, and 122c via the off-site device 204 control panel 500. In another example, as shown in Figure 3C, there are multiple devices 202,1202,2202 on site, each located at a respective drilling site and having a respective PMA software 212,1212,2212 installed. The PMA software 1212,2212 may be the same as or similar to the PMA software 212 described above, so the PMA software 1212,2212 will not be described in detail in this document. Each device 202,1202,2202 on site is in communication with a respective PMA 122,1122,2122 at the respective drilling sites. Each of the PMAs 1122, 2122 may be the same as or similar to the PMA 122 described above; therefore, PMAs 1122, 2122 will not be described in detail in this document. For simplicity, the components of PMAs 122, 1122, 2122 are omitted from Figure 3C.In some embodiments, each on-site device 202, 1202, 2202 communicates with a respective EDR system 206, 1206, 2206 at each drilling site. The off-site device's PMA application 214 is configured to communicate with each of the on-site devices 202, 1202, 2202 via network 222, thereby enabling the off-site device 204 user to monitor and control all PMAs 122, 1122, 2122 across multiple drilling sites simultaneously. In this embodiment, the off-site device 204's control panel 500 can be configured to display data from all PMAs 122, 1122, 2122 simultaneously or allow the user to select which drilling site data to display. The user can thus remotely monitor and control one or more of the PMAs 122,1122,2122 at different drilling sites via the off-site device control panel 500 204. Figure 6 shows a sample configuration of the 222 network. In some embodiments, the 222 network comprises one or more of the following components: a 602 proxy service; a 604 managed pooled flow generation service; a 606 data punch consumer; a 608 client flow generation service; a 610 managed large non-relational database service; a 612 software security service; a 614 CREATE READ UPDATE DELETE (CRUD) service; and a 616 user authentication proxy. The proxy service 602 acts as a proxy between the on-site device 202 and the other components on the 222 network. The proxy service 602 can provide an entry point for the PMA software 212 on the on-site device 202 to access data (e.g., drilling parameters) available on the 222 network. An example of a proxy service 602 is Lambda-Proxy®.The Managed Aggregate Stream Generation Service (604) provides temporary storage for high-volume traffic, enabling real-time stream generation of large volumes of data. An example of a Managed Aggregate Stream Generation Service (604) is the Managed Kafka® service. In some implementations, communications from the on-site Device (202) to the proxy Service (602) are forwarded to the Managed Aggregate Stream Generation Service (604) for temporary storage. An example of PMA Software (212) is PMDSmart™, developed by Opla Energy. The managed large non-relational database service (610) is a database that can provide permanent storage for large volumes of data. An example of a database service (610) is the Managed Cassandra® service. The drilling data consumer (606) can contain a number of mainframe application stacks that ingest data from the stream generation service (604) and put the data into storage, which in this example is the database service (610). The stream generation client service (608) can serve the off-site device (204) by reading data from the stream generation service (604) and then sending the data to the off-site device's PMA application (214). In some implementations, the stream generation service (608) forwards data in a neutral format that can be read by different types of devices.An example of a flow generation service for 608 customers is a managed cloud service such as the Beanstalk® managed instance. An example of a 214 PMA application is PMDSmart™ developed by Opla Energy. The Security service (612) manages the security of the PMA application and PMA software, for example, to ensure that only authorized users can access data and software on the 222 network. The CRUD service (614) handles all tables from various applications and requests for historical data. The CRUD service (614) can also provide authentication functions. The User Authentication proxy (616) is a forwarding mechanism between the components of the 222 network and an external authentication service (not shown). An example of a user authentication proxy is Okta®. Other 222 network configurations are possible. Figures 7 and 8 illustrate sample procedures 700 and 800 that can be performed using the off-site device PMA application and the on-site device PMA software, respectively, of the control system 100. Although the operations in the sample procedures are generally described as being performed by the PMA application and / or the PMA software, it can be seen that the operations in the sample procedures can be performed by the PMA application and / or the PMA software in combination with one or more additional components in the control system 100. With reference to Figure 7, procedure 700 begins with the off-site device's PMA application connecting to the internet (step 702) and then connecting iviA / a / zuzo / uii ouu to the PMA software via an internet service (step 704). Once connected, the PMA application begins receiving data from the PMA software (step 706) and displays the data in real time on the off-site device's control panel (step 708). As the PMA application continues to receive and display data, it checks whether: (i) any of the preset rules in the PMA application are violated (step 710) based on the received data; (ii) it received an alert from the PMA software (step 712); and (iii) it received user input (step 714). Based on data received from the PMA software, the PMA application can determine that a predefined rule has been violated (step 710) and then automatically generate a command in response to the violated rule (step 716). If the PMA application receives an alert from the PMA software (step 712), it can either automatically generate a command (step 716) or request user input from the off-site device operator (step 718). If the PMA application receives user input (step 714), whether in response to a request made in step 718 or entered by the operator without prior notification, the PMA application can generate a (manually obtained) command based on the user input (step 720). Not all user input received by the PMA application requires a command to be generated by the application.Some user inputs, such as a request to modify the control panel view on the off-site device, do not require any action by the PMA software or modification of PMA settings, so the PMA application does not generate a command in these cases. After the PMA application generates a command, it sends the command to the PMA software over the internet (step 722) and waits for confirmation from the PMA software that the command has been received and / or processed (step 724). If the PMA application has not received confirmation from the PMA software (step 726), it continues waiting (step 724). When the PMA application receives confirmation from the PMA software (step 726), it updates the control panel on the off-site device, if necessary (step 728), and returns to step 706. With reference to Figure 8, procedure 800 begins with the on-site device's PMA software connecting to the internet (step 802) and collecting and monitoring data received from the PMA controller, i.e., controller 172 in Figure 2 (step 804). In some embodiments, the on-site device has a control panel, and the PMA software also displays the received data in real time on the control panel in step 804. As the PMA software continues to receive and monitor data, it checks whether any of the preset rules in the PMA software are violated (step 806) based on the received data and whether it received a command from the PMA application (step 808).If the on-site device has a user interface, the PMA software can also check if it received user input on the on-site device; however, this scenario is not shown in Figure 8 for the sake of simplicity. After determining that a pre-established rule has been violated (step 806) based on the received data, the PMA software can: (i) self-generate a command in response to the violated rule (step 810); request user input from the device operator on-site (step 812); or send an alert to the device's off-site PMA application via the internet (step 814). If the PMA software receives user input in response to its request in step 812, the PMA software generates a command (obtained manually) based on the received user input (step 816). If the PMA software sent an alert to the PMA application in step 814, the PMA software checks whether it received the command from the PMA application (step 808). The PMA software can receive a command from the PMA application (step 808), whether the command is in response to an alert sent in step 814 or is sent by the PMA application without being notified. After the PMA software generates or receives a command, the PMA application sends the command to the PMA controller 172 (step 818) and waits for confirmation from the controller that the command has been received and / or processed (step 820). If the command is sent by the PMA application, the PMA software may modify the command before sending it to the controller. If the PMA software has not received confirmation from the controller (step 822), it continues waiting (step 820). When the PMA software receives confirmation from the controller (step 822), it may update the control panel on the device on-site if necessary (step 824) and send a confirmation to the PMA application if necessary (step 826), i.e., to the location where the command was sent by the PMA application. The PMA software then returns to step 804. ΐνίΛ / α / ^υZ J / UI IOUU Therefore, the control system 100 can help transfer some of the monitoring and control responsibilities at a drilling site to off-site devices in remote locations, thereby reducing the number of human operators required on the rig. The control system 100 can also help the off-site device 204 operator feel more like an integral part of the drilling operations by providing monitoring and control mechanisms that are the same as, or similar to, those of the on-site device 202. Although discussed in the context of MPD, a person skilled in the art may appreciate that the systems and procedures in this disclosure can be applied to other types of pressure-controlled drilling techniques, such as pressurised mud cap drilling, backflow control drilling, dual-gradient drilling, and underbalanced drilling. Interpretation of terms Unless the context clearly requires otherwise, throughout the description, “comprises,” “comprising,” and the like should be interpreted in an inclusive, rather than exclusive or exhaustive, sense; that is, in the sense of “including, but not limited to”; “connected,” “coupled,” or any variant thereof, means any connection or coupling, whether direct or indirect, between two or more elements; the coupling or connection between the elements may be physical, logical, or a combination thereof; in this document, “above,” “below,” and words of similar significance, when used to describe this specification, shall refer to this specification as a whole, and not to any particular portion of this specification;or, with reference to a list of two or more items, covers all of the following interpretations of the word: any of the items in the list, all of the items in the list, and any combination of the items in the list; the singular forms “a”, “one”, and “the” also include the meaning of any appropriate plural form. When a component is referenced above, unless otherwise stated, the reference to that component should be interpreted as including as equivalents of that component any component that performs the function of the described component (i.e., that is functionally equivalent), including components that are not structurally equivalent to the disclosed structure that performs the function in the illustrated example embodiments. iviA / a / zuzo / uii ouu Various modifications to these embodiments will be readily apparent to those skilled in the art, and the generic principles defined herein may be applied to other embodiments without departing from the spirit or scope of the disclosure. Thus, this disclosure is not intended to be limited to the five embodiments shown herein but should be given the full scope consistent with the claims. All structural and functional equivalents to the elements of the various embodiments described throughout this disclosure that are known or may later become known to those skilled in the art are intended to be covered by the elements of the claims. Furthermore, nothing disclosed herein is intended to be dedicated to the public, regardless of whether such disclosure is explicitly cited in the claims.Therefore, it is intended that the following appended claims and claims introduced hereafter be interpreted to include all such modifications, permutations, additions, omissions, and subcombinations that may reasonably be inferred. The scope of the 15 claims shall not be limited by the preferred embodiments set forth in the examples but shall be given the broadest interpretation consistent with the overall description.

Claims

1. A control system for controlling a pressure management apparatus in a drilling site drilling system, the pressure management apparatus comprising a controller and a plurality of components controllable by the controller, the control system comprising: a network accessible via the Internet; an on-site device in communication with the controller and connected to the network, the on-site device being configured to receive data from the controller, the on-site device being located at or near the drilling site;and an off-site device connected to the network and in communication with the on-site device via the network, the off-site device being configured to receive data from the on-site device via the network in real time and to receive user input, the off-site device being located at a remote location from the drilling site, wherein the off-site device is configured to generate a command based on the data or user input and send the command to the on-site device; and wherein the on-site device is configured to receive the command and send the command to the controller to cause the controller to modify at least one setting of the plurality of components of the pressure management apparatus.

2. The control system of claim 1 wherein the network is part of a virtual private cloud.

3. The control system of claim 1 or 2 wherein the network comprises one or more data channels.

4. The control system of claim 1 or 2 wherein the network comprises one or more of: a proxy service; a managed pooled stream generation service; a drill data consumer; a client stream generation service; a managed large non-relational database service; a software security service; a CRUD service; and a user authentication proxy.

5. The control system of any one of claims 1 to 4, wherein the pressure management apparatus comprises one or more data collection devices operatively coupled to the controller, and wherein the controller is configured to receive data from the one or more data collection devices. iviA / a / zuzo / uii ouu 6. The control system of any one of claims 1 to 5 wherein the drilling system comprises an electronic drilling recorder system and wherein the on-site device is in communication with the electronic drilling recorder system.

7. The control system of any one of claims 1 to 6 wherein the plurality of components comprises a choke having a choke motor and a choke valve motor, and wherein the controller is configured to actuate the choke motor to make the choke more open or closed, and to actuate the choke valve motor to place the choke online or offline.

8. The control system of claim 7 wherein the choke comprises a choke housing; a choke cartridge configured to be removable into the choke housing; and a choke cartridge motor, and wherein the controller is configured to drive the choke cartridge motor to cause the choke cartridge to move relative to the choke housing.

9. The control system of any one of claims 1 to 8 wherein the plurality of components comprises a choke narrowing line; a flow line valve configured to control fluid flow in the choke narrowing line; and a flow line valve motor operatively coupled to the flow line valve, and wherein the controller is configured to actuate the flow line valve motor to cause the flow line valve to open or close.

10. The control system of any one of claims 1 to 9 wherein the plurality of components comprises a bearing assembly; a bowl for receiving the bearing assembly; and a coupling motor operatively coupled to the bearing assembly or the bowl, and wherein the controller is configured to drive the coupling motor to cause the bearing assembly to move relative to the bowl.

11. The control system of any one of claims 1 to 10 wherein the pressure management apparatus comprises an optical detection device.

12. A method comprising: connecting, via an off-site device, to the Internet, the off-site device being located remotely from a well drilling site; connecting, via the off-site device, to an on-site device communicating with a pressure management apparatus (PMA) in a drilling system at the drilling site via an Internet service, the on-site device being at or near the drilling site; receiving, via the on-site device, PMA data from a real-time PMA controller; receiving, via the off-site device, real-time PMA data from the on-site device via the Internet; generating, via the off-site device, a command based, at least in part, on one or both of the PMA data and user input on the off-site device;send, via the off-site device, the command to the on-site device; receive, via the on-site device, the command; send, via the on-site device, the command to the controller; receive, via the controller, the command; and modify, via the controller, a PMA setting based on the command.

13. The method of claim 12 comprising receiving, by means of the on-site device, EDR data from a real-time drilling system platform; and receiving, by means of the off-site device, the real-time EDR data from the on-site device via the Internet.

14. The procedure of claim 13 wherein the command is generated based, at least in part, on EDR data.

15. The method of any one of claims 12 to 14 wherein modifying the PMA setting occurs before, during, or after one of: drilling the well, connecting a drill string at the drilling site, ejecting the drill string from the well, circulating fluid in the well, reaming the well, handling a kick or loss while drilling the well, and an offline operation.

16. The method of any one of claims 12 to 15 wherein the command is generated by the off-site device based, at least in part, on PMA data and one or more pre-established rules.

17. The method of claim 16 wherein one or more pre-established rules are generated by the off-site device, generated by the on-site device, established by a user, or a combination thereof. iviA / a / zuzo / uii ouu 18. The method of any one of claims 12 to 15 wherein the command is generated based on PMA data, and the method comprises: generating, by means of the on-site device, an alert based on the PMA data; before generating the command, receiving, by means of the off-site device, the alert from the on-site device; and generating, by means of the off-site device, the command in response to the alert.

19. The method of any one of claims 12 to 15 wherein the command is generated based on user input, and the method comprises: generating, by means of the on-site device, an alert based on PMA data; before generating the command, receiving, by means of the off-site device, the alert from the on-site device; notifying, by means of the off-site device, a user of the off-site device input based on the alert; and receiving, by means of the off-site device, the user input from the user in response to the notification.

20. The method of any one of claims 12 to 19 wherein the PMA data comprises one or more of: a flow rate; a pressure; a temperature; a choke position; a choke valve position; a choke cartridge position; a flow line valve position; a bearing assembly position; an image; and a video.

21. The method of claim 14 wherein the EDR data comprises an injection pressure.

22. The method of any one of claims 12 to 21 comprising displaying, by means of the off-site device, a control panel to present at least some of the PMA data in real time and receive user input.

23. The method of claim 22 comprising, after modifying the PMA setting: receiving, via the on-site device, a confirmation from the PMA; receiving, via the off-site device, the confirmation from the on-site device; and updating, via the off-site device, the control panel. iviA / a / zuzo / uii ouu 24. The method of any one of claims 12 to 23 wherein the remote location is at a distance from a second drilling site of a second well, and the method comprises: connecting, by means of the off-site device, to a second on-site device communicating with a second PMA in a second drilling system at the second drilling site via the Internet service, the second on-site device being at or near the second drilling site; receiving, by means of the second on-site device, second PMA data from a controller of the second PMA in real time; receiving, by means of the off-site device, second PMA data in real time from the second on-site device via the Internet;generate, using the off-site device, a second command based, at least in part, on one or both of the second PMA data and a second user input on the off-site device; send, using the off-site device, the second command to the second on-site device; receive, using the second on-site device, the second command; send, using the second on-site device, the second command to the controller of the second PMA; receive, using the controller of the second PMA, the second command; and modify, using the controller of the second PMA, a setting of the second PMA based on the second command.

25. A control system for a pressure-managed drilling system having a drill string and drill bit extended in a well, an electric drilling recorder system, a mud pump, and a pressure management apparatus (PMA) in communication with a defined circular ring between the drill string and the well, the control system being in communication with the pressure management apparatus, the control system comprising: an on-site device in communication with a control unit of the pressure management apparatus and the electronic drilling recorder system to receive substantially real-time data, the data being collected by a plurality of sensors of the pressure management apparatus and the electronic drilling recorder; and an off-site device comprising: a user interface having a display; a control panel accessible via the display;and one or more processors in communication with the on-site device through a communication network, the one or more processors having access to a first set of instructions which, when executed by at least one of the one or more processors, cause the off-site device to: generate, on the control panel, one or more of: a hole depth indicator showing a depth of the well; a bit depth indicator showing a depth of the drill bit; a block height indicator showing a length remaining for a subsequent drill string segment connection; an inflow indicator showing a pump rate of a drilling fluid entering the well; an outflow indicator showing a flow rate of a drilling mud entering the pressure management apparatus;an inlet mud weight indicator that displays a mud weight of the drilling fluid entering the well; an outlet mud weight indicator that displays a mud weight of the drilling mud leaving the well; a surface backpressure indicator that displays a surface backpressure; a target surface backpressure indicator that displays a target surface backpressure; a casing midpoint pressure (ICP) indicator that displays an ICP pressure; and an equivalent circulating density (ECD) indicator of ICP that displays an ECD of ICP;iteratively update the control panel to display one or more of the following indicators: hole depth indicator, drill depth indicator, block height indicator, inflow flow indicator, outflow flow indicator, inflow mud weight indicator, outflow mud weight indicator, surface backpressure indicator, ICP pressure indicator, and ICP ECD indicator, substantially in real time; and control the pressure management apparatus, via the on-site device, based at least in part on the information displayed on the control panel.

26. The control system of claim 25 wherein the first set of instructions further causes the off-site device to: generate, on the control panel, one or more of: a bottomhole pressure indicator showing a bottomhole pressure; a bottomhole ECD indicator showing a bottomhole ECD; a surface backpressure limit indicator showing a surface backpressure limit; a peak pressure indicator showing a peak pressure; and an ejection speed indicator showing an ejection speed; and iteratively update the control panel to display one or more of the bottomhole pressure indicator, the bottomhole ECD indicator, the surface backpressure limit indicator, the peak pressure indicator, and the ejection speed indicator substantially in real time.

27. The control system of claim 26, wherein the pressure management apparatus has a first choke, wherein the first set of instructions further causes the off-site device to: generate, on the control panel: a first choke status indicator showing a first choke status; and a first choke position indicator showing a first choke opening; and iteratively update the control panel to show the first choke status indicator and the first choke position indicator substantially in real time.

28. The control system of claim 27 wherein the first set of instructions further causes the off-site device to generate, on the control panel, a graphical representation showing one or more of: the well depth; the drill bit depth; the remaining length; the drilling fluid pump rate; the drilling mud flow rate; the drilling fluid mud weight; the drilling mud weight; the surface backpressure; the target surface backpressure; the ICP pressure; the ICP ECD; the bottom hole pressure; the bottom hole ECD; the surface backpressure limit; the peak pressure; the ejection rate; the first choke status; and the first choke opening, for a range of well block heights;and iteratively update the control panel to display the graphical representation substantially in real time.

29. The control system of claim 28 wherein the control panel is configured to allow a user to select the range of block heights.

30. The control system of claim 29 wherein the pressure management apparatus has a second choke, wherein the first set of instructions further causes the off-site device to: generate, on the control panel, a second choke status indicator showing a state of the second choke; generate, on the control panel, a second choke position indicator showing an opening of the second choke; and iteratively update the control panel to display the second choke status indicator and the second choke position indicator substantially in real time.

31. The control system of claim 30 wherein the graphical representation shows the state of the second choke and the opening of the second choke.

32. The control system of any one of claims 25 to 31, wherein the first set of instructions further causes the off-site device to: generate, on the control panel, a Form Integrity Test (FIT) / Maximum Allowable Casing Pressure (MACP) section that allows the user to enter one or more of: a depth value, a bottom hole ECD value, and a pressure gradient value; and control the pressure management apparatus based at least in part on the depth value, the bottom hole ECD value, or the pressure gradient value.

33. The control system of claim 32 wherein the first set of instructions further causes the off-site device to update, upon user request, information in the FIT / MACP section substantially in real time.

34. The control system of any one of claims 25 to 31, wherein the first set of instructions further causes the off-site device to: generate, on the control panel, a pressure control section that enables the user to: select a pressure control mode for the pressure-managed drilling system; select a depth level; and to enter a pressure value or an ECD value, the pressure control section displaying a corresponding depth value for the depth level and a pressure or ECD for the depth level; update, upon user request, information in the pressure control section substantially in real time; and control the pressure management apparatus based at least in part on the pressure value or the ECD value.

35. The control system of claim 30, wherein the first set of instructions further causes the off-site device to: generate, on the control panel, a choke control section displaying a first mode indicator showing whether the first choke is in automatic or manual mode, the first mode indicator being configured to allow the user to select between automatic and manual modes, wherein when the first mode indicator is in automatic mode, the first choke is controlled by the on-site device based at least in part on the information displayed on the control panel; and when the first mode indicator is in manual mode, the status and opening of the first choke are adjustable by the user through user input in the choke control section;Update, upon user request, information in the choke control section substantially in real time; and when the first mode indicator is in manual mode, control the pressure management device based at least in part on user input in the choke control section. ΐνίΛ / α / ^υZ J / UI IOUU; 36. The control system of claim 30 wherein the first set of instructions further causes the off-site device to: generate, on the control panel, a choke operator safety settings section that allows the user to enter one or more of: a safe surface backpressure upper limit, an emergency choke opening for the first choke, and an emergency choke opening for the second choke; update, upon user request, information in the choke operator safety settings section substantially in real time; and control the pressure management apparatus based at least in part on the safe surface backpressure upper limit, the emergency choke opening for the first choke, and the emergency choke opening for the second choke.

37. The control system of claim 30 wherein the on-site device comprises a user interface having a display; an on-site control panel accessible through the display of the on-site device; and one or more processors having access to a second set of instructions which, when executed by at least one of the one or more processors of the on-site device, cause the on-site device to: generate, on the on-site control panel, one or more of: a gain / loss calibrator; a surface backpressure calibrator; an ICP pressure calibrator; a standpipe pressure calibrator; a downhole pressure calibrator; an ICP ECD calibrator; a downhole ECD calibrator; an annular friction loss calibrator; a custom depth ECD calibrator; and a custom depth pressure calibrator;and iteratively update the on-site control panel to display one or more of the gain / loss calibrator, surface backpressure calibrator, ICP pressure calibrator, standpipe pressure calibrator, downhole pressure calibrator, ICP ECD calibrator, and downhole ECD calibrator substantially in real time.

38. The control system of claim 37, wherein the gain / loss calibrator is displayed as a vertical bar chart visualization.

39. The control system of claim 37, wherein at least one of the surface backpressure calibrator, the ICP pressure calibrator, the standpipe pressure calibrator, the downhole pressure calibrator, the ICP ECD calibrator, and the downhole ECD calibrator is displayed as a dial indicator display.

40. The control system of claim 37 wherein the first choke comprises a choke cartridge, and wherein the second set of instructions further causes the on-site device to: generate, on the on-site control panel, a choke cartridge status indicator showing whether the choke cartridge is inserted or removed; and iteratively update the on-site control panel to display the choke cartridge status indicator substantially in real time.

41. The control system of claim 40 wherein the first choke cartridge indicator comprises interactive buttons to allow a choke cartridge position to be adjusted by the user, and wherein the second set of instructions further causes the on-site device to control the pressure management apparatus based at least in part on the interactive buttons of the first choke cartridge indicator.

42. The control system of claim 37 wherein the second set of instructions causes the on-site device to: generate, on the on-site control panel, a PMA status indicator showing whether the fluid is flowing through one or both of the first and second chokes or bypassing both the first and second chokes, the PMA status indicator comprising interactive buttons to allow the flow and bypass to be adjusted by the user; iteratively update the on-site control panel to display the PMA status indicator substantially in real time; and control the pressure management apparatus based at least in part on the interactive buttons of the PMA status indicator.

43. The control system of claim 37 wherein the second set of instructions further causes the on-site device to: generate, on the on-site control panel, an operation indicator showing the current operation of the managed pressure drilling system, the operation indicator comprising interactive buttons to allow the current operation to be adjusted by the user; iteratively update the on-site control panel to display the operation indicator substantially in real time; and control the pressure management apparatus based at least in part on the interactive buttons of the operation indicator.

44. The control system of any one of claims 25 to 43 wherein the pressure management apparatus comprises a pressure management device positioned at a wellhead of the well.

45. The control system of any one of claims 25 to 43 wherein the pressure management apparatus comprises an integrated pressure management device positioned at a wellhead of the well.

46. ​​A computer-implemented method for controlling a drilling operation of a pressure-managed drilling system for a well, the method comprising: (f) receiving a data stream from a pressure management apparatus and an electronic drilling recorder system, the data stream being generated in real time by a plurality of sensors of the pressure management apparatus and the electronic drilling recorder; (g) processing the data stream to generate operational information of the pressure-managed drilling system, the operational information comprising one or more of: a well depth; a depth of a drill bit in the well; a length remaining for a subsequent drill string segment connection; a pump rate of a drilling fluid entering the well; a flow rate of a drilling mud entering the pressure management apparatus;a mud weight of the drilling fluid entering the well; a mud weight of the drilling mud leaving the well; a surface backpressure; an intermediate casing point (ICP) pressure; an equivalent circulating density (ECD) of ICP; a bottom-hole pressure; a bottom-hole ECD; a surface backpressure limit; a pressure peak; an ejection velocity; a state of a first choke of the pressure management apparatus; a state of a second choke of the pressure management apparatus; a first choke opening; and a second choke opening; (h) providing a visual presentation of the operating information on a device outside the remote well site; (i) repeating (a) to (c) over time, to update the visual presentation throughout the drilling operation;and (j) controlling the pressure management apparatus based on a command, the command being determined at least in part on the visual presentation.; 47. The computer-implemented method of claim 22 comprising receiving user input through the visual display, and wherein the command is determined based at least in part on the user input.

48. Systems comprising any feature, combination of features, or subcombination of features shown or described herein or in the accompanying drawings.

49. Procedures comprising any feature, combination of features, or subcombination of features shown or described herein or in the accompanying drawings.

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