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 determining fluid inflow rates within a wellbore comprises determining a plurality of temperature features from a distributed temperature sensing signal originating in a wellbore, determining one or more frequency domain features from an acoustic signal originating the wellbore, and using at least one temperature feature of the plurality of temperature features and at least one frequency domain feature of the one or more frequency domain features to determine a fluid inflow rate at one or more locations along the wellbore.

Methods of characterizing acoustic output from a hydrocarbon well and hydrocarbon wells that include controllers that perform the methods are disclosed herein. The methods include receiving the acoustic output, determining a plurality of acoustic fingerprints, and electronically clustering the plurality of acoustic fingerprints. The acoustic output includes information regarding a plurality of sound events, and each sound event of the plurality of sound events includes at least one corresponding sound detected at the hydrocarbon well. The plurality of acoustic fingerprints includes a corresponding acoustic fingerprint for each sound event of the plurality of sound events. The electronically clustering includes utilizing a clustering algorithm to generate a plurality of acoustic event clusters. Each acoustic event cluster of the plurality of acoustic event clusters includes a corresponding fingerprint subset of the plurality of acoustic fingerprints, and each acoustic fingerprint in the corresponding fingerprint subset includes at least one similar acoustic property.

Systems and methods include a computer-implemented method for predicting fluid holdups along the borehole or the pipe on surface and to perform fluid typing and fluid properties characterization. Acoustic waves are transmitted by an array of acoustic wave transducers. Each transducer is configured to transmit acoustic waves at a different frequency. The acoustic waves are received by an array of acoustic wave receivers fixed on the bow centralizer on the tool used in the borehole. Each receiver is configured to receive only the given frequency of a given transducer, forming a receiver-transducer pair for the given frequency. Acoustic speeds measured at each given frequency and analyzed. A model is generated based on the analyzing. The model is configured to predict fluid holdups across the borehole and to perform fluid typing and fluid properties characterization in one phase, two phase, and three phase applications of gas, oil, and water.

This disclosure presents a method and an apparatus for improving production performance of a well using a drill stem test tool (DSTT). The method includes isolating a zone of interest in the wellbore, then reducing and recording pressure inside the drill string while recording acoustic emissions from the sensors on the DSTT, then correlating the recordings of the acoustic emissions with the pressure. The method includes using the processed acoustic emissions to determine a candidate sound of interest and a pressure at which the candidate sound of interest is recorded, then comparing the candidate sound of interest with a reference lookup table of known lithology classifications. The method includes determining a collapse pressure of the wellbore using the lithology of the wellbore and the pressure at which the candidate sound of interest is recorded.

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 downhole tool assembly for completing or cleaning a wellbore. The downhole tool assembly may include a perforation gun sub and a laser assembly sub. The perforation gun sub may be used to propagate a shockwave through one or more pre-existing perforations in a formation. The laser assembly sub may be used for treating perforations, e.g. treating the one or more pre-existing perforations. Depending on the parameters of the operation, the treating of the perforations may comprise changing the shape of the perforations and/or making the perforations wider, deeper, or otherwise adjusted.

A downhole tool assembly for completing or cleaning a wellbore. The downhole tool assembly may include a perforation gun sub and a laser assembly sub. The perforation gun sub may be used to propagate a shockwave through one or more pre-existing perforations in a formation. The laser assembly sub may be used for treating perforations, e.g. treating the one or more pre-existing perforations. Depending on the parameters of the operation, the treating of the perforations may comprise changing the shape of the perforations and/or making the perforations wider, deeper, or otherwise adjusted.

The subject technology relates to synthetic aperture to image leaks and sound sources. Other methods and systems are also disclosed. The subject technology includes drilling a wellbore penetrating a subterranean formation. The subject technology includes logging the wellbore using the stationary acoustic sensor and the moving acoustic sensor of the logging tool to obtain logged measurements, and obtaining an actual acoustic signal associated with a leak source in the wellbore using logged measurement data. The subject technology also includes determining a synthetic acoustic signal indicating an estimated leak source in the wellbore, and determining a correlation between the synthetic acoustic signal and the actual acoustic signal. The subject technology also includes generating a probability map from the determined correlation, in which the probability map indicates a likelihood of the leak source being located at a given location in the wellbore based on the probability map.

The subject technology relates to synthetic aperture to image leaks and sound sources. Other methods and systems are also disclosed. The subject technology includes drilling a wellbore penetrating a subterranean formation. The subject technology includes logging the wellbore using the stationary acoustic sensor and the moving acoustic sensor of the logging tool to obtain logged measurements, and obtaining an actual acoustic signal associated with a leak source in the wellbore using logged measurement data. The subject technology also includes determining a synthetic acoustic signal indicating an estimated leak source in the wellbore, and determining a correlation between the synthetic acoustic signal and the actual acoustic signal. The subject technology also includes generating a probability map from the determined correlation, in which the probability map indicates a likelihood of the leak source being located at a given location in the wellbore based on the probability map.