Baker Hughes Corporation

Baker Hughes, a Ge Compnay, LLC

Baker Hughes Oilfield Operations LLC

Bryan Dugas

Michell Schimanski

Moray L Laing

John D MacPherson

Markus Hempel

Sven M Haberer

Tarab H Ali

Ian P Says

John P Lottinville

A downhole system and method of performing an operational action with the downhole system. The downhole system includes a downhole string having a flow channel therethrough, a first turbine generator for generating electrical energy when a flow rate of a fluid through the flow channel is within a first flow rate range, and a second turbine generator for generating electrical energy when a flow rate of the fluid through the flow channel is within a second flow rate range. A first pulser at a downhole location in the downhole string transmits a pressure pulse communicative of data generated downhole using electrical energy generated by one of the first turbine generator and the second turbine generator. A sensor at a surface location receives the pressure pulse, and a control unit performs the operational action based on the data communicated by the pressure pulse.

Dual turbine power and wellbore communications apparatus

A method and apparatus for determining a gas influx into a wellbore. A work string defining an inner bore area and an annulus area, with a pair of inner bore sensors in the inner bore and a pair of annulus sensors in the annulus. A processor sets a gas influx alarm limit based on a steady-state value of an acoustic parameter measured by the pair of inner bore sensors in an absence of a gas influx and a steady-state value of the acoustic parameter measured by the annulus sensors in the absence of the gas influx. The processor determines a gas influx in the wellbore when a subsequent value of the acoustic parameter is outside of the alarm limit and performs an action at the work string to counteract the gas influx in the wellbore.

Method and apparatus to detect gas influx using mud pulse acoustic signals in a wellbore

Downhole assemblies comprise at least one sensor configured to sense at least one parameter relating to a downhole condition. The downhole assembly further includes a communications assembly having at least one device for controlling a characteristic of fluid flow through the downhole assembly and a processor in communication with the at least one sensor. The processor is configured to selectively alter the characteristic of fluid flow through the downhole assembly with the at least one device in response to data received from the at least one sensor.

Assemblies for communicating a status of a portion of a downhole assembly and related systems and methods

A method for verifying that a kick or loss detected by surface monitoring equipment has occurred includes: receiving an input signal having notification that a kick or a loss has been detected in an earthen borehole during a time interval when drilling fluid is not being pumped into a drill string disposed in the borehole; sensing a pressure in the borehole to provide sensed pressure readings; comparing the sensed pressure readings to an upper threshold and a lower threshold; verifying that a kick has occurred if the notification comprises a kick detection and the sensed pressure reading are above the upper threshold; verifying that a loss has occurred if the notification comprises a loss detection and the sensed pressure readings are below the lower threshold; and transmitting a kick or loss verification signal to a signal receiving device upon verification that the kick or loss has occurred.

Combined surface and downhole kick/loss detection

A method for transmitting data from a downhole location to a location at the surface of the earth includes determining a minimum value and a maximum value of M-samples of data values, determining a keycode for the M-samples of data values that provides an indication of the maximum and minimum values of the M-samples, and encoding the keycode and the data values into one or more encoded words. The one or more encoded words are then transmitted as an acoustic signal in drilling fluid by modulating a mud-pulser. The acoustic signal is received by a transducer uphole from the mud-pulser and converted into an electrical signal. The electrical signal is demodulated into a received encoded word, which is decompressed into the M-samples in accordance with the keycode. The M-samples are then received by a computer processing system disposed as the surface of the earth.

Compressed telemetry for time series downhole data using variable scaling and grouped words

A method, apparatus and computer-readable medium for determining an influx at a wellbore is provided. A flowback parameter is obtained for a plurality of flowback events at the wellbore prior to a current flowback event. An average of the flowback parameter (&#x3bc;) and a standard deviation (&#x3c3;) of the flowback parameter is determined from the plurality of prior flowback parameters. An alarm threshold is set based on the determined average and the standard deviation. A current flowback parameter is measured and the influx is determined when the current flowback parameter meets the alarm threshold.

Smart flowback alarm to detect kicks and losses

A method enables communication with downhole tools during a 'flow off' condition by energizing at least one sensor and a controller using a local power source only after flow of drilling fluid has been reduced below the threshold flow rate value. Thereafter, the method involves generating the at least one predetermined pattern into the wellbore, detecting the at least one predetermined pattern using the at least one sensor and the controller, and transmitting a signal using the controller in response to the detected at least one predetermined pattern.

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Breaux Bridge, LA, United States of America

Bryan Dugas