Saudi Arabian Oil Company

Electro-flow Controls Ltd

E-flow Control Ltd

Fraser, Scott

Michael Anthony Affleck

Chinthaka Pasan Gooneratne

Krzysztof Karol Machocki

Timothy Eric Moellendick

Graham Hitchcock

William Contreras Otalvora

Arturo Magana Mora

Pratyush Singh

Sakethraman Mahalingam

Aslan Bulekbay

Arturo Magana-Mora

Christopher Thomas Wrighton

Mahmoud Abughaban

Scott David Fraser

Monty B Gilleland

Tom Dixon

Ian Allan

Graham Richard Hitchcock

A well system includes a local controller communicably coupled to a hydraulic diverter configured to control a well shut-in assembly at a well site operable to shut in a wellbore based on a command from the local controller or to shut in or open the wellbore based on a command from a control panel at or in a vicinity of the well site. The well system includes a remote controller located at a location remote from the local controller and the well site and configured to communicate a wireless signal to the local controller to initiate the command from the local controller. The well system includes the hydraulic diverter fluidly coupled to the well shut-in assembly. The hydraulic diverter is configured to, based on the command from the local controller, control the well shut-in assembly to shut in the wellbore and render the command from the control panel irrelevant.

Wirelessly activated well system

A mud flow measurement system includes a flow pipe, a Coriolis meter, a differential pressure sensor, and a mud flow measurement module. The mud flow measurement module is configured to select a calibration curve corresponding to a drilling mud injected into the well, determine a measured density based on the signal from each of the vibration sensors and the selected calibration curve, determine a differential pressure across the Coriolis meter from the differential pressure sensor, and compute a calculated mass flow rate, Q, of the multiphase mud flow using equation where Cis a calibration constant, Ais a cross-sectional area of the measurement tube, β is a ratio of the internal diameters of the flow pipe the measuring tube, ρ is the density of the multiphase mud, and ΔP is the differential pressure across the Coriolis meter, where ρ is the measured density determined from the Coriolis meter.

Drilling mud flow metering system and method

A method, and related apparatus, involves providing one or more drill pipe segments and disposing a quantity of lost circulation material objects within the one or more drill pipe segments. A retention element is provided to retain the lost circulation material objects within the one or more drill pipe segments. The one or more drill pipe segments are connected to a drill string at a wellbore, and drilling fluid is flowed through the drill string. The flowing of drilling fluid through the drill string causes the retention element to release the lost circulation material objects to propagate further.

Methods and apparatus for deployment of large lost circulation material objects

A system for monitoring an annular fluid level may include a floating element disposed on a surface of a drilling fluid within an annulus of the well, during mud cap drilling operations. The system may also include an antenna disposed above the floating element. The antenna may be configured to transmit a first signal to the floating element, and to receive a second signal from the floating element in response to the first signal. The system may also include a processor configured to determine a time value that measures a time between a transmittal, by the antenna, of the first signal and a receipt, by the antenna, of the second signal. The processor may also determine a state of a drilling fluid level within the annulus based on the time value, and update a drilling program for the well based on the state of the drilling fluid level.

Systems and methods for monitoring annular fluid level

A downhole tool includes a choke, a controller, a communication and power element, instrumentation, and a stabilizer. The choke is configured to vary an annular well pressure. The choke includes an expandable element having an expanded position, an expanding position, and an unexpanded position. The controller is connected to the choke and is configured to place the choke in the expanded position, the expanding position, and the unexpanded position. The communication and power element is electronically connected to the controller. Power and instructions are sent to the controller from the communication and power element. The instrumentation is electronically connected to the communication and power element. The instrumentation comprises sensors configured to obtain downhole data and the downhole data is sent to the communication and power element. The stabilizer is configured to centralize the choke within the casing string.

Subsurface annular pressure management system—a method and apparatus for dynamically varying the annular well pressure

An apparatus includes a first body, a second body, a shear pin, and a divider. The first body includes a coupling. The second body includes a cutter blade. The shear pin is configured to hold the position of the second body relative to the first body in an open position. The coupling is configured to couple the first body to the second body in a closed position. In the open position, the apparatus defines first and second flow paths for fluids and solids to pass through the apparatus. The first flow path is defined through the first body and through an inner bore of the divider. The second flow path is defined through the first body and through an annulus surrounding the divider. In the closed position, the second flow path is closed, such that solids remain in the annulus surrounding the divider.

Gauge cutter and sampler apparatus

The present disclosure describes methods and systems, including computer-implemented methods, computer program products, and computer systems, for monitoring the flow of drilling mud from a wellbore by image processing. One method includes: capturing, using a digital imaging device, images of drilling mud at a surface of the wellbore as the drilling mud flows through one or more image capture zones of a circulation system that circulates drilling mud through the wellbore and a wellbore drilling assembly; receiving, by one or more processors of a computer system operatively coupled to the digital imaging device, the images captured by the digital imaging device; and processing, by the one or more processors, the images captured by the digital imaging device to determine a rate of flow of the drilling mud through the one or more image capture zones.

System and methods for the measurement of drilling mud flow in real-time

Systems include a floating device disposed on a top of a column of drilling fluid in an annulus of a wellbore. The floating device includes a capsule. A transmitter or a reflector may be coupled to the capsule. The floating device may transmit signals to a surface region from the annulus or receive signals from the surface region and reflect at least a portion of the received signals. A receiver in the surface region receives transmitted signals or reflected signals from the floating device and determines a distance between the floating device and a reference point in the surface region. The distance indicates a level of the drilling fluid in the annulus.

System and method to measure mud level in a wellbore annulus

System and methods for delivering objects formed of a solid material into a circulation fluid of a subterranean well include a volume transfer container. The volume transfer container has an inlet port, an outlet port, and a charge access opening sized to provide for the filling of the volume transfer container with the objects. A discharge line extends from a pump assembly to the volume transfer container. A transfer line extends from the volume transfer container to the drilling assembly, providing a fluid flow path from the volume transfer container to the drilling assembly that is free of any pump.

Drill string solids deployment

A method includes receiving, by a computer system, a video of a visible state of a component of a generator, the generator powering at least a portion of a rig equipment system at a wellsite. The computer system can determine an operational parameter based on the visible state of the component of the generator imaged in the video, and can transmit the operational parameter to an output device.

Rig power system efficiency optimization through image processing

Analysis of drilling slurry solids by image processing includes receiving images of a solid slurry including a mixture of wellbore drilling mud and solid objects found in the wellbore while drilling the wellbore through a subterranean zone. The solid objects include drill cuttings and non-drilled solids. By implementing image processing techniques on the images, the solids in the solid slurry are classified a drill cutting or as a non-drilled solid.

Analysis of drilling slurry solids by image processing

A testing apparatus for testing a fluid and a loss control material (LCM) is provided. The testing apparatus includes a testing chamber having an upstream end, a downstream end, a device central axis, and a general flow direction. The testing chamber includes a chamber body having an upstream cap, a downstream cap, a first chamber wall, and a second chamber wall. The first chamber wall has a first diameter and in part defines a first chamber interior, the second chamber wall has a second diameter, the first diameter is less than the second diameter, and both the first chamber wall and the second chamber wall are positioned relative to one another such that an annulus is defined in part in between. The traversal of the fluid and the LCM along the fluid flow path is restricted by a flow restriction.

Lost circulation materials (LCM) and lost circulation shapes (LCS) test fixture

One or more images of a tubular being run into a well are captured. The one or more images can be captured by an image sensor. The tubular includes a first tubular section and a second tubular section connected together by a connection. An onsite edge gateway local to the image sensor is configured to perform various operations. Based on the captured one or more images, an elevation of the connection relative to a reference elevation of the well is determined. Based on the determined elevation, an operating condition is determined. It is determined whether the operating condition is included in an automation rule. In response to determining that the automation rule includes the operating condition, a signal is transmitted to drive a controllable device.

Image based inspection of well equipment

A method for determining a slips status during a drilling operation of a subterranean formation. The method includes capturing, using one or multiple camera devices mounted on a drilling rig of the drilling operation, a plurality of images, each of the plurality of images comprising a portion that corresponds to a slips device of the drilling rig, generating, using a sensor device of the drilling rig, a plurality of parameters of the drilling rig, wherein the plurality of parameters are synchronized with the plurality of images, providing, by a computer processor, the plurality of parameters as input to a machine learning model of the drilling rig, and analyzing, by the computer processor and based on the machine learning model, the plurality of images to generate the slips status.

Growing community of inventors

Aberdeen, United Kingdom

Michael Anthony Affleck