Saudi Arabian Oil Company

Oilsco Technologies Limited

Paradigm Oilfield Services Limited

Nxg Technologies Limited

Krzysztof Karol Machocki

Michael Anthony Affleck

Chinthaka Pasan Gooneratne

Sakethraman Mahalingam

Arturo Magana-Mora

Timothy Eric Moellendick

Arturo Magana Mora

Ismail Adebiyi

Christopher Thomas Wrighton

William Contreras Otalvora

Alan MacKenzie

Ayodeji Abegunde

Ahmed Jaafari

Darren Ritchie

Alan Mackenzie

Darren John Ritchie

A system and method include a dart deployment sub coupled to a drill string including a data receiver, a transmission device, and a data transmission cable, a downhole data collection sub coupled downhole from the dart deployment sub including an instrumentation package capable of acquiring parameter data regarding a location in the wellbore, and a dart disposed inside the dart deployment sub coupled to the data transmission cable configured to receive acquired parameter data from the downhole data collection sub. The dart is configured to depart from the dart deployment sub and land in the downhole data collection sub, wherein the data receiver is configured to receive parameter data from the dart via the data transmission cable. The system further includes a surface collection device coupled to the transmission device configured to transmit parameter data from the dart deployment sub to the surface collection device.

System and method for streaming high frequency data to surface while drilling

A system for monitoring fluid flow conditions on a return flow line including a return flow line in fluid communication with a wellbore, a shaker, and a header box. The system includes a contactless flow sensor facing an interior of the header box or an outlet of the return flow line, a data gathering and analyzing unit coupled to the contactless flow sensor, and a control panel to display data and notify when hazardous conditions occur. A method for monitoring fluid flow conditions on a return flow line including flowing a drilling mud into the header box through the return flow line and monitoring the height of the drilling mud in the header box and/or return flow line to determine the fluid level using the contactless flow sensor. The fluid level is used to determine a fluid flow rate and indicate a current operational or a hazardous operational status.

System and method to detect and measure fluid flow in the return line during drilling activities

A monitoring system for a drill string controlled by a drilling program may include a contactless sensor arranged to capture data at a second time. The data may be associated with a parameter at a position along a drill line associated with the drill string. The system may include a processor operatively connected to the contactless sensor. The processor may be configured to access a machine learning (ML) model that is trained using the data captured at a first time, prior to the second time, and an image analysis algorithm. The processor may be configured to identify, using the trained ML model, a condition pertaining to the drill string based on interpreting the data captured at the second time. The processor may be configured to cause an adjustment to the drilling program based on the identified condition.

Contactless sensor monitoring of a drill string controlled by a drilling program

Testing a fluid in a wellbore with a well testing tool carried on a well testing string includes activating a first selectively controllable longitudinal valve and a second selectively controllable longitudinal valve with a communication module. A first and second packer of the well testing tool engages an inner wall of the wellbore to define a zone of interest between the first packer and the second packer. The communication module further activates a selectively controllable radial valve positioned between the first packer and the second packer to flow fluid between the central bore and the annulus formed between the first packer and the second packer, a fluid sample flows from the annulus between the first packer and the second packer through the testing string to a tophole facility.

Straddle packer testing system

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 tool is used to inject a rapidly solidifying sealant into and across highly fractured oil and gas wellbore formations when a significant loss circulation zone or event is encountered. A system including the tool allows for application of the sealant to the formation without requiring removal of the drill string from the hole. The tool may have operatively associate with containers storing sealant and or sealant components that are provided downhole from the surface via wireline or the like.

Device, system, and method for applying a rapidly solidifying sealant across highly fractured formations during drilling of oil and gas wells

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

A method includes installing an influx device into a bell nipple. The influx device has an opening, a pumping port entrance, a pumping port exit, a measuring port entrance, and a measuring port exit. The pumping port exit is disposed in the annulus and the measuring port entrance is disposed adjacent the opening. The method further includes pumping a control gas, at a flow rate, from the pumping port entrance to the annulus using the pumping port exit, receiving the control gas at the measuring port exit using the measuring port entrance, detecting the control gas, using a gas measuring device connected to the measuring port exit, to determine a displacement time, and measuring the size of the void in the annulus using the flow rate and the displacement time.

System and method to measure changes in the mud level and gas properties when drilling through a total loss zone with no returns to surface

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

A method includes attaching a sensor calibration tool to a drill string. The sensor calibration tool includes a first tool sensor configured to measure a first operational parameter. A first tool sensor measurement of the first operational parameter is received from the first tool sensor, where the drill string is disposed at least partially within a wellbore and supported by a surface rig system and the sensor calibration tool is positioned on the drill string at a surface location proximate to the surface rig system. A first rig sensor measurement of the first operational parameter is received from a first rig sensor positioned on a first surface component of the surface rig system. The first rig sensor is calibrated based on a comparison of the first tool sensor measurement with the first rig sensor measurement.

Rig sensor testing and calibration

Systems and methods for producing fluids from a subterranean well include an electrical submersible pump assembly with a motor-pump unit. The motor-pump unit has a motor housing and a stator is located within the motor housing. The stator has a stator body with an interior cavity. A rotor assembly is located within the interior cavity of the stator. The rotor assembly includes a rotor shaft extending along the central axis of the stator, a rotor member, and an intermediate rotor bearing assembly. The rotor member and the intermediate rotor bearing assembly circumscribe the rotor shaft. An impeller is mounted on the rotor shaft and located within the interior cavity of the stator. A liner with a polygonal cross section is located along an interior surface of the interior cavity. The liner is secured to the motor housing and seals the stator body from a wellbore fluid.

Submersible canned motor pump

A method for optimizing a drilling roadmap may include identifying an optimal bottom hole assembly (BHA) setup and drilling parameters for a well located in a field. The BHA setup may be based on historical simulation data of the field and drilling roadmap information. The drilling roadmap information may include initial drilling instructions for implementing the drilling roadmap. The method may include implementing and tracking the drilling roadmap at the well. The drilling roadmap may be based on a location of the well on the field and a type of other applications being performed on the field. The method may include obtaining sensor collected data to determine an accuracy of implementation of the drilling roadmap. The accuracy may be determined based on a comparison between tracked drilling parameters and simulated drilling parameters.

Method and system for optimizing field development

Disclosed are methods, systems, and computer-readable medium to perform operations including: capturing, using an image sensor directed at a drilling system, an image feed of movement of a component of the drilling system with respect to a vertical reference line; converting the image feed into a digital representation of the movement of the component, the digital representation including a number of offset pixels from the component to the vertical reference line in the image feed; converting the digital representation into a machine learning (ML), the ML representation including a plurality of vectors each including the number of offset pixels from the component to the vertical reference line at a respective time; training a ML model using the ML representation to characterize the movement of the component as normal or abnormal; and using the trained ML model to characterize the movement of the component in real-time as normal or abnormal.

Automatic analysis of drill string dynamics

An assembly and a method for sealing a tubular in a wellbore, where the wellbore sealing assembly includes a hollow housing body and a seal. The hollow housing body is configured to receive a tubular. The seal is positioned within the hollow housing body and has a first movable end and a second movable end. A first seal surface and a first hollow housing inner surface define a first hollow housing cavity. A second seal surface and a second hollow housing surface define a second hollow housing cavity. The seal is configured to seal fluid in the first hollow housing cavity from fluid in the second hollow housing cavity when the tubular is disposed in the hollow housing body. The first movable end and the second movable end are moveable to change a length of a third seal surface shared between the seal and the tubular.

Growing community of inventors

Aberdeen, United Kingdom

Krzysztof Karol Machocki