Abstract: A distributed control system can be used to implement failover capabilities for control units that control well equipment during a well operation. For example, a system can include first well equipment that performs a first physical task and second well equipment that performs a second physical task different from the first physical task. Additionally, the system can include a distributed control system with a first control unit coupled to the first well equipment and a second control unit coupled to the second well equipment. Both control units may include a first control module and a second control module for automatically controlling the first physical task and the second physical task, respectively. The distributed control system can detect a failure of the second control unit and initiate a failover process in which the first control unit takes over control of the second physical task by enabling the second control module.

Abstract: Distributed artificial intelligence (AI) can be used to monitor a wellbore operation in some examples described herein. In one such example, physical equipment can be positioned at a surface of a wellsite to support a drilling operation at the wellsite. Each piece of physical equipment may include a sensor module, a processor communicatively coupled to the sensor module, and a memory. The memory can include an AI module configured to determine a condition associated with the equipment by analyzing sensor data from the sensor module using one or more machine-learning models. The memory additionally can include a warning module for causing the processor to output a warning notification based on the condition. The memory further can include a communications module for causing the processor to transmit a communication indicating the condition to a destination via a network. The communication may be different from the warning notification.

Abstract: Aspects of the subject technology relate to systems and methods for optimizing multi-unit pumping operations at a well site. Systems and methods are provided for receiving sensor data from a hydraulic fracturing fleet equipment at an equipment system, designating an event as being flagged based on the sensor data from the hydraulic fracturing fleet equipment, determining a physical action based on the flagged event and a priority list of actions, and providing instructions to a first pump of the hydraulic fracturing fleet equipment to perform the physical action based on the flagged event and the priority list of actions.

Abstract: Provided is a flowback system and method. The flowback system, in one aspect, include a tank, a transfer pump, a low-pressure vent line coupled between a vent of the tank and a first flare tip, and a high-pressure gaseous hydrocarbon line coupled to a second flare tip. In accordance with yet one other aspect, the flowback system includes a control system including a sensor, a valve and a valve controller coupled to the valve, the valve of the control system coupled between the low-pressure vent line and the high-pressure gaseous hydrocarbon line, the control system configured to sense an unsafe system event and actuate the valve to supply high-pressure gaseous hydrocarbons from the high-pressure gaseous hydrocarbon line to the low-pressure vent line.

Abstract: A mobile robot is disclosed herein. The mobile robot may include a frame, a propulsion module, a navigation module designed to navigate the mobile robot along a target pathway, and a computational module. The mobile robot may obtain a composition reading of the drilling fluid and a pressure reading of the drilling fluid. The robot may determine, using the computational module, an additive to add to a drilling fluid reservoir based on the composition reading and the pressure reading. The mobile robot may then retrieve the additive from an inventory and deposit the additive into the drilling fluid reservoir.

Abstract: The disclosure presents processes to improve the calibration of adjustable choke valves corresponding to a specific size of positive choke bean. Typically, manufacturers specify a position of the adjustable choke valve that corresponds to a specific choke bean size. Hydrocarbon fluid conditions and composition vary and subterranean formation characteristics vary which can lead to errors in the calibration. By comparing flow rate parameters of the hydrocarbon fluid flowing through the adjustable choke manifold and the positive choke manifold, errors in calibration can be detected and corrected. The factors involved with the hydrocarbon fluid and the error correction can be used to update a choke model. The choke model can then be used for future calibrations of the adjustable choke valve.

Abstract: A system is provided including at least one pump for pumping a fluid into a wellbore, a pressure sensor provided at a wellhead of the wellbore for measuring a backpressure of the fluid being pumped into the wellbore, and a diagnostic manager. The diagnostic manager obtains pressure data associated with a pressure signal from the pressure sensor, wherein the pressure data includes pressure measurements of the fluid over a selected time period. The diagnostic manager converts, based on the pressure data, at least a portion of the pressure signal into frequency domain. The diagnostic manager detects a change in frequency of the pressure signal in the Fourier spectrum and determines that a fault associated with the wellbore has occurred based on the changed frequency of the pressure signal.

Abstract: A machine learning model trained to predict offset pressure (“predictor”) is used to generate a pumping schedule that mitigates well interference during a hydraulic fracturing treatment operation. Diverse candidate pumping schedules are generated according to pumping schedule constraints. Feature inputs are populated with the candidate pumping schedules and with static and dynamic features related to the operation. The feature inputs are fed into one or more instances of the predictor to obtain offset pressure predictions at a prediction horizon for which the predictor was configured. The offset pressure predictions are evaluated to identify the one that best satisfies a well interference mitigation objective and the corresponding candidate pumping schedule is identified for well interference mitigation.

Abstract: A system is provided including a coiled tubing reel apparatus including a reel drum for storing a coiled tubing string spooled on the reel drum and a hydraulic reel drive motor that controls rotation of the reel drum. The system further includes a reel controller that determines an estimated reel back tension for a portion of the coiled tubing string between the reel apparatus and the injector based on a set of parameters related to a coiled tubing operation. The reel controller determines a target reel back tension to be applied to the portion of the coiled tubing string by adjusting the estimated reel back tension based on a historical job dataset. The reel controller then determines and sets a target hydraulic pressure of the reel drive motor to achieve the target reel back tension in the portion of the coiled tubing string.

Abstract: A bi-directional telemetry system for use in a wellbore environment is provided. The bi-directional telemetry system includes a first acoustic telemetry component and a second acoustic telemetry component that is separate from the first acoustic telemetry component. The first acoustic telemetry component comprises a downhole acoustic transmitter disposed in a wellbore and operable to transmit the first acoustic signal and an uphole acoustic receiver. The second acoustic telemetry component comprises an uphole acoustic transmitter operable to transmit the second acoustic signal and a downhole acoustic receiver.

Abstract: Construction and use of an instrument test fixture for capturing performance data for stimulation or fracturing treatments. The test fixture includes a target material, such as concrete, which includes embedded sensors surrounding a casing. An energetic stimulation treatment, such as a dynamic pulse fracturing technique, is applied through the casing to the target material to simulate a treatment that would be performed in a wellbore. During application of the treatment, the sensors capture measurements which are recorded for analysis by a data collection system. The sensors allow for the measurement of key performance indicators including static and dynamic pressure, generated temperature, and resulting strain energy. The captured data can be analyzed and used to design and optimize stimulation treatments for field applications.

Abstract: A system is provided including at least one pump for pumping a fluid into a wellbore, a pressure sensor provided at a wellhead of the wellbore for measuring a backpressure of the fluid being pumped into the wellbore, and a diagnostic manager. The diagnostic manager obtains pressure data associated with a pressure signal from the pressure sensor, wherein the pressure data includes pressure measurements of the fluid over a selected time period. The diagnostic manager converts, based on the pressure data, at least a portion of the pressure signal into frequency domain. The diagnostic manager detects a change in frequency of the pressure signal in the Fourier spectrum and determines that a fault associated with the wellbore has occurred based on the changed frequency of the pressure signal.

Abstract: A downhole tool is positioned in a borehole of a geological formation at a given depth. A formation property is determined at the given depth. The positioning and determining is repeated to form data points of a data set indicative of formation properties at various depths in the borehole. One or more outlier data points is removed from the data set based on first gradients to form an updated data set. One or more properties associated with a reservoir compartment are determined based on second respective gradients associated with the updated data set.

Abstract: Aspects of the subject technology relate to systems and methods for optimizing multi-unit pumping operations at a well site. Systems and methods are provided for receiving sensor data from a hydraulic fracturing fleet equipment at an equipment system, designating an event as being flagged based on the sensor data from the hydraulic fracturing fleet equipment, determining a physical action based on the flagged event and a priority list of actions, and providing instructions to a first pump of the hydraulic fracturing fleet equipment to perform the physical action based on the flagged event and the priority list of actions.

Abstract: A method and system for in-sit calibration of a gravimeter. A method may comprise disposing a downhole tool in a borehole, wherein the downhole tool comprises the gravimeter attached to a linear actuator, recording a first set of measurements with the gravimeter while the linear actuator is stationary, activating the linear actuator, recording a second set of measurements with the gravimeter, and calibrating the gravimeter based on the first and second set of recorded measurements. A system may comprise a downhole tool, a conveyance, and an information handling system. The downhole tool may further comprise a hanger, a sonde, connected to the hanger, a linear actuator, connected to the hanger, and a shaft, connected to the linear actuator. The downhole tool may further comprise a linkage, connected to the shaft, a package, connected to the linkage, and a gravimeter, disposed in the package.

Abstract: A system is provided that includes a dart, a pressure sensor, and a controller communicatively coupled with the sensor. The dart is disposed in a fluidic channel. The dart has a main body and a flange extending from the main body and has a diameter greater than or equal to a diameter of the fluidic channel. When the dart translates within the fluidic channel and passes a location of a variation in the fluidic channel, the flange creates a pressure pulse. The pressure sensor measures the pressure pulse within the fluidic channel created by the dart. The controller determines the location of the variation based on the measured pressure pulse.

Abstract: A method and system for operating a frequency comb. The method may comprise operating an electro-optic (EO) frequency comb with two phase-locked microwave signals to produce an optical output, detecting the optical output with an optical receiver as one or more beat notes, and detecting the one or more beat notes with a radio-frequency spectrum analyzer. The system may comprise an EO frequency comb and an EO phase modulator disposed in the bulk nonlinear crystal resonator. The EO frequency comb may further comprise a continuous-wave laser and a bulk nonlinear crystal resonator connected to the continuous-wave laser.

Abstract: A distributed acoustic system may comprise an interrogator which includes a single photon detector, an umbilical line comprising a first fiber optic cable and a second fiber optic cable attached at one end to the interrogator, and a downhole fiber attached to the umbilical line at the end opposite the interrogator. A method for optimizing a sampling frequency may comprise identifying a length of a fiber optic cable connected to an interrogator, identifying one or more regions on the fiber optic cable in which a backscatter is received, and optimizing a sampling frequency of a distributed acoustic system by identifying a minimum time interval that is between an emission of a light pulse such that at no point in time the backscatter arrives back at the interrogator that corresponds to more than one spatial location along a sensing portion of the fiber optic cable.

Abstract: A system includes an optical fiber integrated into a conveyance subsystem that is positionable downhole in a wellbore. The system also includes a backscattering sensor system positionable to monitor temperature and optical fiber strain along the optical fiber using backscattered light signals received from the optical fiber. Further, the system includes a fiber optic rotary joint positionable to optically couple the optical fiber with the backscattering sensor system to provide an optical path for the backscattered light signals to reach the backscattering sensor system.

Abstract: Optical fiber having a graphene coating, a method to apply a graphene coating onto an optical fiber, and a fiber optic cable having a graphene coating are disclosed. A first carbon based coating is applied to an optical fiber along a longitudinal axis of the optical fiber. A laser beam is focused at the first carbon based coating. A first surface of the first carbon based coating is photothermally converted into a first layer of graphene.