Various embodiments include a method for determining the mixing ratio R of a fluid comprising a mixture of at least two different fluids for a technical process in a device comprising: irradiating an ultrasonic signal with a transmission level along a measuring distance running inside a measuring section; measuring a receiving level of the ultrasonic signal at one end of the measuring distance; determining an ultrasonic attenuation of the ultrasonic signal attenuated by the fluid based at least on the transmission and receiving levels of the ultrasonic signal; measuring a temperature of the fluid flowing through the measuring section; and determining a mixing ratio of the at least two different fluids from the determined ultrasonic attenuation and from the measured fluid temperature.

A system for measuring fluid flow in a wellbore is provided. A probe includes at least a heater. A fiber optic cable is connected to the probe. The system is programmed to perform operations including: changing an output of the heater to thereby change a temperature of drilling fluid moving over a fiber optic cable; measuring a strain on the fiber optic cable caused by changing the temperature of the drilling fluid; preliminarily determining a velocity of the drilling fluid from the measured strain; measuring at least a second parameter of the drilling fluid; adjusting the preliminary determined velocity based on the measured at least a second parameter to yield an adjusted velocity; and determining a flow rate of the drilling fluid based on the adjusted velocity.

A fluid analysis system for characterizing a multiphase fluid includes a first set of acoustic probes disposed at a first angular position about a central axis of the fluid analysis system and oriented to direct first sound waves along a first direction that is parallel to the central axis, a second set of acoustic probes disposed at a second angular position about the central axis that is opposite to the first angular position and oriented to direct second sound waves along the first direction, a third set of acoustic probes spanning the central axis and oriented to direct third sound waves along a second direction that is perpendicular to the central axis, and an analysis unit. The analysis unit is configured to determine a location of a fluid interface within the multiphase fluid based on first, second, and third parameters respectively associated with the first, second, and third sounds waves.

A fluid analysis system for characterizing a multiphase fluid includes a first set of acoustic probes disposed at a first angular position about a central axis of the fluid analysis system and oriented to direct first sound waves along a first direction that is parallel to the central axis, a second set of acoustic probes disposed at a second angular position about the central axis that is opposite to the first angular position and oriented to direct second sound waves along the first direction, a third set of acoustic probes spanning the central axis and oriented to direct third sound waves along a second direction that is perpendicular to the central axis, and an analysis unit. The analysis unit is configured to determine a location of a fluid interface within the multiphase fluid based on first, second, and third parameters respectively associated with the first, second, and third sounds waves.

Embodiments of the invention provide a tool-kit of processing techniques which can be employed in different combinations depending on the circumstances. For example, flow speed can be found using eddy tracking techniques, or by using speed of sound measurements. Moreover, composition can be found by using speed of sound measurements and also by looking for turning points in the k-w curves, particularly in stratified multi-phase flows. Different combinations of the embodiments can therefore be put together to provide further embodiments, to meet particular flow sensing requirements, both on the surface and downhole. Once the flow speed is known, then at least in the case of a single phase flow, the flow speed can be multiplied by the interior cross-sectional area of the pipe to obtain the flow rate. The mass flow rate can then be obtained if the density of the fluid is known, once the composition has been determined.

A fluid density measuring device uses a pipe with a pipe wall that has an inner wall surface with a non-circular cross-section at least in an axial segment of the pipe. Preferably, the inner wall surface comprises one or more protrusions extending inwardly into the pipe and along the axial direction of the pipe. An ultrasound transducer located on the pipe wall is used to generate local motion of the pipe wall with a circumferential direction of motion. Preferably, the ultrasound transducer is located between successive protrusions. An ultrasound receiver located on the pipe wall receives an ultrasound torsion wave generated by the local motion after the torsion wave has traveled through the axial section wherein the inner wall surface has a non-circular cross-section. The fluid density is determined from the propagation speed of the torsion wave.

Apparatus and methods for the measurement of gas volume fraction of produced oil are described. A first method measures the response of a pipe containing the produced oil excited by a source of vibration in the form of an acoustic frequency chirp containing a linearly varying range of frequencies in the tens of kilohertz range encompassing at least one resonant mode of the pipe. As the gas volume fraction increases, the location of the peak maximum of the measured frequency spectrum responsive to the excitation increases in frequency, and the height of the peak maximum increases, thereby permitting a linear calibration curve to be obtained. A second method measures the response of a pipe containing the produced oil to excitation by a continuous source of vibration having a chosen frequency above those which excite flexural vibrations in the pipe and simultaneously excite acoustic waves in the fluid contained in the pipe, known as the coincidence frequency. Gas present in the fluid will interrupt sound propagation or reverberation, thereby generating fluctuations in the amplitude of the measured vibrations of the pipe. The amplitude fluctuation level provides a measure of the gas volume present inside the pipe. A third method measures the response of a pipe containing the produced oil to excitation by a high-bandwidth, short pulse having a chosen center frequency above the coincidence frequency. Gas present in the fluid will interrupt pulse propagation, thereby generating fluctuations in the amplitude of the measured vibrations of the pipe.

A method of determining a mixing state of a medium in a container includes: transmitting a plurality of acoustic signals at least partly through the medium and receiving the plurality of acoustic signals after at least partly traversing the medium; determining at least one propagation value of at least one propagation quantity for each of the plurality of received acoustic signals to provide determined propagation values, each at least one propagation quantity being indicative of an interaction of the acoustic signals with the medium; determining at least one fluctuation value of at least one fluctuation quantity based on the determined propagation values to provide a determined at least one fluctuation value, each at least one fluctuation quantity being indicative of and/or correlating with a variance of the determined propagation values and/or with a state of a mixture; and determining the mixing state of the medium.

Embodiments of the invention provide a tool-kit of processing techniques which can be employed in different combinations depending on the circumstances. For example, flow speed can be found using eddy tracking techniques, or by using speed of sound measurements. Moreover, composition can be found by using speed of sound measurements and also by looking for turning points in the k- curves, particularly in stratified multi-phase flows. Different combinations of the embodiments can therefore be put together to provide further embodiments, to meet particular flow sensing requirements, both on the surface and downhole. Once the flow speed is known, then at least in the case of a single phase flow, the flow speed can be multiplied by the interior cross-sectional area of the pipe to obtain the flow rate. The mass flow rate can then be obtained if the density of the fluid is known, once the composition has been determined.

Embodiments herein generally relate to systems and methods to determine the composition, properties, and morphology of a liquid in a liquid handling structure. Aspects disclosed include exploiting spatiotemporal constraints of zero-group-velocity modes for non-contact, non-invasive, liquid sensing applications.