Abstract: Examples described herein provide for evaluating greenhouse gas emissions for a fluid for a hydrocarbon exploration and recovery operation. The method includes performing an emissions lifecycle analysis for the drilling and completion fluid. The method further includes determining a greenhouse gas emissions value for the drilling and completion fluid based at least in part on a result of the emissions lifecycle analysis. The method further includes modifying a portion of the hydrocarbon exploration and recovery operation based at least in part on the greenhouse gas emissions value.

Abstract: An example system for non-invasive determination of target properties of a pressure vessel includes: a signal generator acoustically coupled to a fluid contained in the pressure vessel and disposed externally to the pressure vessel, the signal generator to emit acoustic signals into the fluid; a plurality of sensors acoustically coupled to the fluid and disposed externally to the pressure vessel to detect the acoustic signals; a control device interconnected with the signal generator and the plurality of sensors, the control device configured to: control the signal generator to emit acoustic signals into the pressure vessel; obtain sensor data from the plurality of sensors, the sensor data representing the acoustic signals as received by the plurality of sensors; compute, based on the detected signal data, the target properties of the pressure vessel; and output an indication of the target properties.

Abstract: Systems and a tool are disclosed herein for improved debris collection within a wellbore. An example debris collection tool can include a motor rotationally coupled to a pump by a first flexible shaft, the pump rotationally coupled to a gearbox by a second flexible shaft, and the gear box rotationally coupled to a milling bit by an additional shaft. The flexible shafts can be made of a flexible, but durable material that can absorb strain created by a pump whose rotor rotates eccentrically with the axis of rotation offset from the axis of symmetry. The flexible shafts can be made of a durable and flexible material that can withstand the strain created by the eccentric rotation.

Abstract: A method of analyzing flowback of a downhole system includes generating active flowback data by monitoring an active flowback from a wellbore. Historic flowback data for historic flowback from the wellbore is used to determine a flowback cluster. The flowback cluster is selected based on comparing the active flowback data to the historic flowback data and determining one or more data instances of the historic flowback data that have features that are similar to that of the active flowback data. Based on the flowback cluster, one or more thresholds may be determined in order to generate an alert when the active flowback data exceeds the thresholds.

Abstract: An embodiment of a method includes receiving measurements from a drilling system during a transient period of a drilling operation for a wellbore. The measurements include measurements of annulus pressure and drilling fluid flow rate, and the transient period is a period of time when the drilling fluid flow rate is ramped up or down. In addition, the method includes training an annulus pressure model that relates an annulus frictional pressure drop over a range of drilling fluid flow rates based at least in part on the measurements. Further, the method includes controlling an annulus backpressure of the wellbore by use of the annulus pressure model after the transient period.

Abstract: A method includes initiating a managed pressure drilling (MPD) operation in an MPD system including a rotating control device (RCD) including at least one sealing element and a plurality of pressures sensors placed relative to the at least one scaling element. The RCD is positioned in the MPD system so as to receive fluid exiting an annulus of a wellbore. Further, the method includes creating a pressure spike in the annulus of the wellbore during the MPD operation, and monitoring a pressure differential between the plurality of pressure sensors to determine whether there is a leakage within the RCD.

Abstract: A method may include receiving data acquired during one or more well construction operations; detecting one or more fluid states using a number of predefined fluid states and the data, where the predefined fluid states include operational fluid states and associated fluid sub-states; generating, using the one or more fluid states, an assessment of a fluid treatment; and outputting the assessment of the fluid treatment.

Abstract: Some implementations include a system comprising a first tubular fluidically connected with one or more frac pumps and one or more first flow control devices that are fluidically connected to a second tubular that is fluidically connected to a wellhead. The system also may include a third tubular fluidically connected with the first tubular and one or more second flow control devices that are connected with a fourth tubular that is fluidically independent of the wellhead.

Abstract: The disclosure provides an automated method and autonomous steering system that automates and integrates a collision avoidance process and subsequent corrective action. The autonomous steering system implements an anti-collision (AC) method that provides collision avoidance by identifying collision risks with one or more hazards. In one example, the automated method includes: (1) detecting a collision risk of a path of a wellbore in a subterranean formation with at least one hazard, wherein the wellbore is being drilled by steering a downhole drilling tool according to the path and the path is based on a well plan for the wellbore, (2) identifying a corridor for the wellbore to avoid the at least one hazard, (3) modifying the path by incorporating the corridor, and (4) steering the downhole drilling tool according to the modified path, wherein the detecting, the identifying, the modifying, and the steering are automatically performed in real-time.

Abstract: A method for controlling drilling fluid properties includes receiving one or more measurements representing a drilling efficiency of a drilling rig including a drill bit deployed into a well. A drilling rig circulates a drilling fluid in the well. The method includes determining that the one or more measurements are lower than expected, determining that a property of a subterranean formation in which drill bit is positioned has changed based on one or more measurements, and in response to determining that the subterranean formation has changed, automatically generating a drilling fluid adjustment plan based at least in part on one or more of a drilling fluid inhibition factor or a drilling fluid stability factor.

Abstract: A system includes a sensor carrier and an integrated data recorder. The sensor carrier includes an outer sub body and an inner sub body. The inner sub body is coupled to the outer sub body by a support leg. The inner sub body includes a recess formed therein. The sensor carrier includes a flow path defined as the space between the outer sub body, the inner sub body, and the support leg. The integrated data recorder is positioned within the recess of the inner sub body such that the integrated data recorder is substantially at the centerline of the sensor carrier. The integrated data recorder includes a sensor package including one or more drilling dynamics sensors, a processor, a memory module, and an electrical energy source.

Abstract: Aspects provide a method of automated lithology at a wellbore. The method includes imaging cuttings collected while drilling the wellbore. The method includes one or more processors: obtaining, from an instance segmentation machine learning model, one or more lithology predictions associated with the wellbore based on the images; determining one or more performance metric scores for the instance segmentation machine learning model based on the one or more lithology predictions and reference data; and comparing the one or more performance metrics scores to one or more performance metric score thresholds and/or one or more performance metrics scores of a second model. The method includes based on the comparison: labeling the images; and (i) retraining the model using the labeled images; or (ii) replacing the model with the second model. The method includes obtaining, from the retrained or second instance segmentation machine learning model, one or more second lithology predictions.

Abstract: Determining the efficiency of solids removal from a wellbore during a wellbore displacement operation may prevent the unnecessary consumption of resources at a well site and enhance the performance of subsequent wellbore operations. The efficiency of solids removal may be based, at least in part, on one or more expected masses of one or more return fluids returned to the surface from a wellbore displacement operation, wherein the determining the expected masses comprises using one or more properties of one or more wellbore servicing fluids before the wellbore servicing fluids are used in the wellbore displacement operation. The expected masses may be compared to actual masses of wellbore fluids returned to the surface, wherein the actual masses are determined from samples of the wellbore fluids obtained from a return line of the wellbore.

Abstract: A downhole tool, including first and second sections, the second section being rotatable relative to the first section, a lock sleeve attached to the first and second sections, the lock sleeve being unlockable by application of a threshold torque acting between the first section and the second section. A positive displacement motor assembly, including a housing, a power section, and a stator, a drive sub connected to the rotor, and a lock sleeve nonrotatably attached to the housing and to the drive sub, the lock sleeve being releasable at a selected threshold torque between the housing and the drive sub. A method for forming a casing exit, including running a tool to a target location in a borehole, causing the first section and the second section to experience different rotational strain, releasing the lock sleeve at a torque threshold between the first and second sections.

Abstract: In various wellbore test systems, a probe mechanism that is extended to contact the formation within a wellbore, and retracted to allow movement of the test system, both rotationally and longitudinally, within the wellbore. A combination including monitoring an actuation fluid pressure used to actuate the probe mechanism to extend and to retract, and the use of one or more timers, provide information used to determine the position of the probe mechanism during the extension and retraction movements.

Abstract: The present disclosure discloses a mud pressure wave signal modulation apparatus and method, which relate to the technical field of petroleum drilling engineering. The apparatus includes: a motor (5), a valve plate (3), a main control circuit (23), a motor drive control circuit, and a downhole communication circuit; the valve plate (3) is driven by the motor (5) to be rotated around an axial direction perpendicular to a flow direction of drilling fluid; the motor (5) and the valve plate (3) are disposed in a drilling fluid channel (2), and the drilling fluid channel (2), the motor (5), the valve plate (3), the main control circuit (23), the motor drive control circuit and the downhole communication circuit are disposed in a drill collar.

Abstract: The trip system closely monitors and ensures that the hydrostatic pressure of the wellbore stays consistent throughout the tripping process, stripping process, and axial pipe operations. The core components of the system include, but are not limited to, an advanced automation system that controls a back-pressure device, including but not limited to a choke, a rotary ball valve, or other flow control devices. The automation system also monitors upstream and downstream flow measurement components. The trip system also provides a pump system to circulate drilling fluid from the trip tank across the top of the wellhead and/or at a lower portion below the RCD.

Abstract: A system for determining a direction for drilling a well is disclosed. The system has a device in a portion of a conveyance mechanism comprising a cylindrical housing with at least one sensor that tracks a position of the portion during a drilling operation, the device being configured to obtain a plurality of drilling parameters, and a control system coupled to the device and configured to perform at least one reservoir simulation, and prepare a plurality of required parameters while drilling. The device uses an optimization box to simulate increasing an angle between a drilling direction and a maximum horizontal stress by calculating a minimum mud pressure required to prevent borehole collapse. The control system generates an engineering curve representative of each angle simulated and a corresponding mud weight or pressure, and the device and the control system identify an optimal direction corresponding to a minimum drilling mud pressure parameter.

Abstract: An intelligent completion module includes a flowmeter that uses one or more electromagnetic acoustic transducer (EMAT) sensors and a flow control valve. The flow rate and the speed of sound in the production fluid from a production zone is measured and used to make reservoir management decisions. The flowmeter includes at least two EMAT rings, including one or more EMAT sensors in a circular distribution which can be used in propagation or pulse-echo modes. In a segregated flow regime, a single EMAT sensor in pulse-echo mode is used to measure holdups of fluid components.

Abstract: A method for identifying guided waves in a measurement set. The method may comprise disposing an acoustic logging tool into a wellbore, performing a measurement operation with the acoustic logging too in the wellbore to form a data set which comprises one or more guided waves, measuring a speed of the one or more guided waves, and identifying a fluid phase interface using the speed of the one or more guided waves. The method may further comprise estimating an acoustic velocity of a wellbore fluid using a database and interpreting the fluid phase based at least in part on the acoustic velocity of the wellbore fluid.

Abstract: The precision aerial firefighting and deluge system for helicopters and unmanned aerial systems is a device to attack fires inaccessible to firefighters due to altitude or other obstructions by streaming water or other fire retardant into or onto a specific location on the ground, on the water, or at altitude. The system employs a medium or heavy lift helicopter or unmanned aerial systems one or more tanks or bladders for water and/or fire retardant chemicals, a compressed air foam system, a pump, rigid plumbing lines for outflow of water/fire retardant; a rigid, telescopic boom that extends beyond rotor tip path plane, flexible lines/hoses inside boom; a crew switched electronic boom controller, a boom management system, a flange adapter, an electric, variable direction, crew-controlled fire monitor, a drop-hose, and a dart with inertial feathers.

Abstract: A method for monitoring overburden during excavation in soil, in which the soil pressure exerted by the soil (10) on an excavation device driven through the soil (10) is monitored by means of a pressure control element (5) extended from the circumference (3) of the driving device. An excavation device for carrying out the method has a pressure control element (5) which is arranged on the circumference (3) of the excavation device and can be extended beyond the circumference (3) of the excavation device.

Abstract: A system for relieving pressure in a wellbore annulus of a hydrocarbon recovery well includes a wellhead, a production line extending from the wellhead, and an annulus relief line extending between the wellhead and the production line. A first pressure gauge measures fluid pressure in the wellbore annulus, a second pressure gauge measures fluid pressure in the production line. A well control system is in communication with the first pressure gauge, second pressure gauge and a check valve disposed in the annulus relief line. The well control system opens and closes the check valve in response to a determined difference between fluid pressure measured by the first pressure gauge and fluid pressure measured by the second pressure gauge. A related method includes measuring the fluid pressure in the wellbore annulus and in the production line, and opening and closing the check valve in response to the determined pressure difference.

Abstract: The disclosed embodiments include well operation evaluation systems and methods to analyze a broomstick chart of a well operation. The method includes receiving data indicative of a broomstick chart of a well operation. The method also includes diagnosing an issue during the well operation based on the broomstick chart. The method further includes predicting an impact on the well operation as a result of the issue. The method further includes determining a likelihood of occurrence of the impact. The method further includes determining a solution to overcome the issue.

Abstract: A system includes a drilling microchip, a mud return line, a microchip detector, and a computer system. The drilling microchip has an identifier and configured to be pumped into the drill string and up the annulus using the drilling fluid to obtain data about the well. The mud return line is hydraulically connected to the annulus of the well and a shale shaker. The microchip detector is connected to the shale shaker and has a detection range. The microchip detector is configured to interact with the identifier to indicate a presence of the drilling microchip in the detection range. The computer system is electronically connected to the microchip detector. The microchip detector is configured to send a signal to the computer system upon indication of the presence of the drilling microchip.

Abstract: A system includes production tubing, a Y-tool, and a downhole tool. The Y-tool is installed within the production tubing and splits the production tubing into a first section, a second section, and a third section. The downhole tool is configured to be run through a conduit of the first section of the production tubing and configured to be installed within the production tubing. The downhole tool includes a valve assembly, a seal stack, and a locking mechanism. The valve assembly is configured to hydraulically connect either the second section of the production tubing or the third section of production tubing to the first section of production tubing. The seal stack is configured to mate with a seal bore of the second section of the production tubing. The locking mechanism is configured to mate with a lock profile of the second section of the production tubing.

Abstract: A method and a system for using machine learning technologies to predict the value and timing of operational parameters. These predictions are then used to identify the risk of certain well incidents to occur, and if so notify responsible personnel thereof as to allow preventive actions to be taken.

Abstract: A method for evaluating a subterranean wellbore includes rotating a drill string in the subterranean wellbore. The drill string includes a rotary steerable tool, a steerable drill bit, or other rotary steering tool with at least one pad configured to extend radially outward from a tool body and engage a wall of the wellbore. Radial displacements of the pad are measured while rotating and processed to compute a curvature of the wellbore.

Abstract: A method for remotely signalling a downhole assembly comprising one or more downhole tools includes operating a choke arrangement configured to control production fluid flow from a wellbore to produce a first pressure signature in the fluid flow, the first pressure signature defining a trigger signal for the one or more downhole tools of the downhole assembly. The first pressure signature comprises at least a first pressure signal and a second pressure signal in the production fluid flow in the downhole assembly. Operating the choke arrangement to produce a second pressure signature in the production fluid flow in the downhole assembly at a predetermined time period following the first pressure signature, the second pressure signature defining a command signal for initiating operation of a predetermined one or more of the downhole tools of the downhole assembly.

Abstract: A method for estimating a rate of penetration while drilling a subterranean wellbore includes estimating a first rate of penetration while drilling using a first measurement method, estimating a second rate of penetration while drilling using a second measurement method, and combining the first and second rates of penetration to obtain a combined rate of penetration of drilling.

Abstract: Techniques for semantic segmentation of images are presented. The techniques include obtaining a semantic segmentation model, the semantic segmentation model having been trained using a first subset of sliding windows and corresponding first ground truth masks for the first subset of sliding windows; ranking a plurality of sliding windows from a corpus of training images according to an uncertainty metric; selecting a next subset of sliding windows from the corpus of training images based on the ranking and based on a similarity metric for one or more characteristics of a sliding window relative to other sliding windows; providing a collaborative user interface; receiving ground truth masks for the next subset of sliding windows using the collaborative user interface; and retraining the semantic segmentation model using the next subset of sliding windows and the ground truth masks for the next subset of sliding windows.

Abstract: A downhole blowout preventer has a blowout preventer tubing string containing a circulation unit, a packer unit and a pressure-building unit connected in sequence from top to bottom. The pressure-building unit is configured to be activated in response to a command, so as to build up pressure in a space inside the blowout preventer tubing string. The packer unit is configured to be activated when a pressure in said space reaches a first predetermined value, so as to seal an annulus between said blowout preventer tubing string and an external casing or borehole. The circulation unit is configured to be activated when the pressure in said space reaches a second predetermined value, thereby creating a circulation path between an interior and an exterior of the blowout preventer tubing string. The first predetermined value is less than the second predetermined value.

Abstract: A pressure relieve valve (PRV) secures to the rotating control device (RCD) in a drilling operation. The PRV located at rig flowline secures to a PRV line, such as PRV piping that bypasses the MPD choke, MPD system, UBD systems, and other flow control device(s). The outlet of the RCD is routed via the pressure relief valve to discharge to a safe contained area. Such discharge relieves overpressure of the wellbore to a contained environment via the rig flowline.

Abstract: Systems and methods for determining the cleaning effectiveness of a well borehole during drilling. A control system may monitor various parameters, including the volume of drilling mud and any materials entering a borehole, including by a flow rate, and the volume of fluids and materials (such as drilling mud and rock) exiting a borehole, including by a flow rate, and determining if there is a difference, the value of any such difference, whether the value is within one or more target ranges, falls below a threshold therefor, or exceeds a threshold therefor. If the control system determines that the value of the difference in volumes indicates that corrective action is appropriate, then taking such corrective action by modifying one or more drilling parameters.

Abstract: Embodiments herein relate to a technique that may include identifying historical data related to at least one remote well. The technique may further include identifying, based on the historical data, a correlation between gas flow capacity and estimated ultimate recovery (EUR) of the at least one other well. The technique may further include identifying gas flow capacity of a well. The technique may further include predicting, based on the gas flow capacity of the well and the identified correlation between gas flow capacity and EUR of the at least one other well, EUR of the well. The technique may further include operating the well based on the predicted EUR. Other embodiments may be described or claimed.

Abstract: A permanent magnet electric generator for use in downhole applications has a rotor element rotatable about an axis, extending in a radial direction generally perpendicular to the axis and one or more permanent magnets attached to the rotor for generating magnetic fields. A stator element also extends in a radial direction generally perpendicular to the axis. A shaft is connected to the rotor and rotatable about the axis, the shaft extends through the stator. The linear distance along the shaft between the rotor and stator defines a gap that is variable and resistant to debris buildup.

Abstract: Methods, apparatus, and systems are provided for detecting and removing microplastics from wastewater effluent. Both, automatic/remote and manual monitoring and sampling components are included to detect the presence of microplastics. The automatic monitoring and sampling component includes a TSS sensor and associated apparatus calibrated to account for non-plastic solids present in the wastewater and, thereby, more accurately determine the presence of microplastics. Efficient separation and removal of microplastics from wastewater effluent is performed by a specialized capture net apparatus having multiple sized mesh components and optional diffuser devices which perform size exclusion filtration of microplastics from the water.

Abstract: Computer vision drilling systems and methods may be used with a drilling rig. The computer vision systems and methods may be used during drilling of a well to monitor the drilling equipment and personnel on the drilling site to provide safer drilling operations. The results from the computer vision drilling system may be used to cause corrective actions to be performed if a safety condition arises. In addition, computer vision systems and methods are provided to automatically monitor the drilling site and drilling operations, such as by tallying pipe in the drill string and by monitoring equipment for anomalous drilling conditions, and automatically taking corrective action as may be needed.

Abstract: Provided is an inner string, an outer string, and a well system. The outer string, in one aspect, includes an outer tubular configured to extend at least partially around an inner tubular, the outer tubular including a seal surface. The outer string, according to one aspect, further includes two radial orientation slots located along an inside surface of the outer tubular, the two radial orientation slots offset from one another by a distance (d1), the two radial orientation slots configured to align with an orientation port in the inner tubular that it is configured to engage with to provide two pressure readings indicative of a relative location of the inner tubular to the outer tubular.

Abstract: An intelligent completion module includes a flowmeter that uses one or more electromagnetic acoustic transducer (EMAT) sensors and a flow control valve. The flow rate and the speed of sound in the production fluid from a production zone is measured and used to make reservoir management decisions. The flowmeter includes at least two EMAT rings, including one or more EMAT sensors in a circular distribution which can be used in propagation or pulse-echo modes. In a segregated flow regime, a single EMAT sensor in pulse-echo mode is used to measure holdups of fluid components.

Abstract: A measured electrical property may be used to control operation of a downhole device, which may be at least partially supported by additional downhole measurements consumed by the downhole device. For example, a downhole device may include an electrical sensor that measures an electrical property of electrical power provided to the downhole device. A processor of the downhole device may convert the measured electrical property to a quantized electrical property and determine a command or control action that corresponds to the quantized electrical property. The command or control action may be implemented to control operation of the downhole device.

Abstract: A method comprises receiving a measurement of a pressure in a subsurface formation at a number of depths in a wellbore formed in the subsurface formation across a sampling depth range of the subsurface formation to generate a number of pressure-depth measurement pairs and partitioning the sampling depth range into a number of fluid depth ranges. The method comprises performing a fitting operation over each of the number of fluid depth ranges to determine a fluid gradient for the type of the reservoir fluid for each of the number of fluid depth ranges. The method comprises generating a solution set of one or more solutions based on the fluid gradient of the reservoir fluid for each of the number of fluid depth ranges determined from performing the fitting operation, wherein each solution defines a partitioning of the sampling depth range and the fluid gradient of each fluid depth range.

Abstract: Systems and methods for utilizing performance based condition monitoring to determine health condition of wellsite equipment. A method may include operating a piece of equipment at an oil and gas wellsite by performing a plurality actions by a component of the piece of equipment, and generating a plurality of sensor measurements, wherein each sensor measurement is indicative of a corresponding action. The method may further include receiving the plurality of sensor measurements by a processing system, calculating a condition indicator for each component based on a corresponding sensor measurement, recording each condition indicator over a period of time, and determining condition of the piece of equipment based on at least one of the condition indicators recorded over time.

Abstract: A method for determining a pressure profile in a subterranean formation is described. The method includes drilling a wellbore in the subterranean formation; lowering a logging tool into the wellbore to measure resistivity values as a function of depth along the wellbore; identifying a plurality of porous zones from the wellbore based on petrophysical logs; converting the measured resistivity values to an amount of total dissolved solids for each of the plurality of identified porous zones; converting the amount of total dissolved solids to a pore fluid density; calculating a pressure based on a sum of the pore fluid densities derived along a length of the well; and generating a depth-based pressure profile.

Abstract: A method includes creating a chamber within an annulus between a wellbore casing and a drillpipe. An upper boundary of the chamber includes a seal and a lower boundary of the chamber includes a liquid surface and determining a volume of the chamber at a first time. The method further includes determining the volume of the chamber includes measuring, using a pressure gauge, a first pressure within the chamber, changing an amount of a gas in the chamber, and measuring, using the pressure gauge, a second pressure within the chamber. The method further includes determining a first volume of gas within the chamber based on the first and second pressure measurements and the change in the amount of gas, and determining a first fluid level based on the first volume of the chamber.

Abstract: The invention relates to a system and method for estimating global rig state. The system comprises a model incorporating multiple variables related to rig state, at least one camera operably connected to at least one processor wherein said camera is capable of gathering visual data regarding at least one variable of rig state and said processor is capable of compiling rig state data, estimating global rig state, or both. The system further comprises multiple sensors for measuring variables related to global rig state wherein said sensors are operably connected to said processor. The method comprises sensing various aspects of the rig state, collecting visual data corresponding with said sensor data, compiling multiple sources of rig data, and estimating the overall rig state.

Abstract: A downhole wellbore planner builds a fracture model of a wellbore using fracture data identified from geological information. Using the fracture model and a target wellbore location at the formation, the wellbore planner may identify or select one or more lost circulation materials (LCMs). The drilling operator may then procure the LCMs before drilling the wellbore. In this manner, the impact of a lost circulation event may be reduced by having the LCMs on site or nearby.

Abstract: An example method for determining downhole conditions in a subterranean formation during a drilling operation may include introducing non-formation gas into a flow of drilling fluid through a fluid conduit in fluid communication with a drill string disposed within a borehole in the subterranean operation. The non-formation gas may be received from the flow of drilling fluid through a return line in fluid communication with the borehole. A downhole condition may be determined based, at least in part, on the received non-formation gas.

Abstract: The invention relates to the monitoring of pressure in production tubing (3) and/or annuli (7, 9) of an oil or gas well. Patterns of pressure in tubing and/or annuli may be indicative of a fault or a condition which requires attention. Patterns may also be recognized that, e.g. based in rates of change, may indicate that a fault may be going to occur in the future. Pressure differences between tubing and annuli or between different annuli may be monitored in the same way.

Abstract: An auxiliary system for intelligent well control includes augmented reality (AR) glasses, a server, and a first sensor group. The first sensor group is configured to collect real-time data of a wellbore and the surface and transmit the real-time data to the server. The server is configured to analyze a target pressure value of a choke valve of the surface according to the real-time data, obtain an actual pressure value of the choke valve of the surface from the real-time data, and transmit the actual pressure value and the target pressure value to the AR glasses. The AR glasses are configured to dynamically display the actual pressure value and the target pressure value in real time. Through the first sensor group and the server, the actual pressure value and the target pressure value can be accurately received by an operator in real time.