An apparatus, system and method for regulating fluid flow are disclosed. The apparatus includes a flow rate sensor and a valve. The flow rate sensor uses images to estimate flow through a drip chamber and then controls the valve based on the estimated flow rate. The valve comprises a rigid housing disposed around the tube in which fluid flow is being controlled. Increasing the pressure in the housing controls the size of the lumen within the tube by deforming the tube, therefore controlling flow through the tube.

This fluid measuring device is provided with: an irradiation unit that irradiates a fluid with light; a light receiving unit that receives light scattered by the fluid; a detecting unit that detects a backflow of the fluid on the basis of a light reception signal from the light receiving unit; and a calculating unit that calculates, on the basis of the detection result by the detection unit and the light reception signal from the light receiving unit, estimated fluid information indicating the flow rate or flow speed of the fluid. Accordingly, even when a backflow of the fluid temporarily occurs, the flow speed of the fluid can be precisely measured.

A powder flow monitoring system may include a computing device configured to receive image data representing illuminated powder of a powder stream between a powder delivery device and a build surface of a component, generate a representation of the powder stream based on the image data, and output the representation of the powder stream for display at a display device.

A wellbore system includes a wellbore tubular with local inner diameter variation. The system includes a wellbore tubular that is positionable in a wellbore for producing hydrocarbon fluid. The wellbore tubular includes at least one portion of an inner wall with a greater inner diameter than other portions of the inner wall of the wellbore tubular. The system includes a fiber optic cable of a fiber optic sensing system that is positionable in the wellbore for measuring flow disturbance of production fluid at the at least one portion of the inner wall to monitor hydrocarbon production flow.

A method of assessing fluid flow in a conduit, the fluid comprising hydrocarbons, the method comprising the steps of: (a) measuring optical variances resulting from at least one circumferential mode of vibration of the conduit by directing a monochromatic light source, such as from a vibrometer, onto an external surface of the conduit thereby providing a measured vibration of the conduit as a result of fluid flow in the conduit. The data normally accurately measures velocity of the conduit usually considered to be wideband noise. Accordingly, sample rates are high, such as at least 5,000 times per second. The data is then assessed, for example by using a Fourier Transform, and a pre-trained algorithm to predict fluid flow at that point in the conduit, or upstream or downstream thereof. An associated apparatus is also disclosed. Embodiments of the invention can thus provide a non-invasive method and apparatus for providing information on the nature of flow regimes in pipelines, such as subsea pipelines which can be useful to optimise production and reduce well testing and/or downtime.

A method of assessing fluid flow in a conduit, the fluid comprising hydrocarbons, the method comprising the steps of: (a) measuring optical variances resulting from at least one circumferential mode of vibration of the conduit by directing a monochromatic light source, such as from a vibrometer, onto an external surface of the conduit thereby providing a measured vibration of the conduit as a result of fluid flow in the conduit. The data normally accurately measures velocity of the conduit usually considered to be wideband noise. Accordingly, sample rates are high, such as at least 5,000 times per second. The data is then assessed, for example by using a Fourier Transform, and a pre-trained algorithm to predict fluid flow at that point in the conduit, or upstream or downstream thereof. An associated apparatus is also disclosed. Embodiments of the invention can thus provide a non-invasive method and apparatus for providing information on the nature of flow regimes in pipelines, such as subsea pipelines which can be useful to optimise production and reduce well testing and/or downtime.

A method of fluid flow measurement includes a emitting a light beam into a pipe through which a fluid flows, the light beam illuminating the fluid flowing in the pipe, using a light detector array to detect light caused by scattering of the beam with particles found in the fluid, the light beam being outside a field of view of the light detector array, dividing the field of view of the light detector array into layers, and determining an instantaneous flow velocity in each of the layers as a function of signals transmitted from the light detector array in each of the layers.

A method of fluid flow measurement includes a emitting a light beam into a pipe through which a fluid flows, the light beam illuminating the fluid flowing in the pipe, using a light detector array to detect light caused by scattering of the beam with particles found in the fluid, the light beam being outside a field of view of the light detector array, dividing the field of view of the light detector array into layers, and determining an instantaneous flow velocity in each of the layers as a function of signals transmitted from the light detector array in each of the layers.

A method for predicting fluid fractions is provided. The method includes building, from pressure, temperature, a fluid speed parameter, speed of sound, and fluid fractions of a first fluid flow, a machine learning model programmed to estimate fluid fractions of a fluid flow as a function of at least one Distributed Acoustic Sensing (“DAS”) fluid flow parameter and at least one physical characteristic of the fluid flow; receiving at least one DAS fluid flow parameter and the at least one physical characteristic of a second fluid flow; and determining, using the machine learning model, fluid fractions of the second fluid flow from at least the at least one DAS fluid flow parameter for the second fluid flow and the at least one physical characteristic of the second fluid flow.

A method for predicting fluid fractions is provided. The method includes building, from pressure, temperature, a fluid speed parameter, speed of sound, and fluid fractions of a first fluid flow, a machine learning model programmed to estimate fluid fractions of a fluid flow as a function of at least one Distributed Acoustic Sensing (“DAS”) fluid flow parameter and at least one physical characteristic of the fluid flow; receiving at least one DAS fluid flow parameter and the at least one physical characteristic of a second fluid flow; and determining, using the machine learning model, fluid fractions of the second fluid flow from at least the at least one DAS fluid flow parameter for the second fluid flow and the at least one physical characteristic of the second fluid flow.