149 results about "Distributed acoustic sensing" patented technology

A method for obtaining information about a subsurface formation from acoustic signals that contain information about to the subsurface formation, comprises: providing a fiber optic having a proximal end and a remote end, with the proximal end being coupled to a light source and a proximal photodetector, wherein said fiber optic cable includes randomly spaced impurities and selectively placed Bragg gratings and wherein the fiber optic cable is acoustically coupled to the subsurface formation so as to allow the acoustic signals to affect the physical status of at least one grating: transmitting at least one light pulse into the cable; receiving at the photodetector a first light signal indicative of the physical status of at least one first section of the cable, and outputting at least one item of information to a display.

Methods and apparatus for performing sonic well logging within a wellbore based on optical Distributed Acoustic Sensing (DAS) are provided. A sonic well logging system based on DAS may be capable of producing the functional equivalent of tens, hundreds, or even thousands of acoustic sensors. In this manner, the emplacement of the sonic well logging system based on DAS may not be nearly as complex or expensive as emplacing a sonic well logging system based on traditional methods. Furthermore, multiplexing may be simpler, downhole electronics need not be used, and the sonic well logging system may be used in extreme, high temperature environments.

This application relates to methods and apparatus for monitoring hydraulic fracturing during oil/gas well formation. A fiber optic cable (102) deployed down a well bore (106), which may be the well bore in which fracturing is performed, is interrogated to provide a distributed acoustic sensor. Data is sampled from at least one longitudinal sensing portion of the fiber and processed to provide at least fracturing characteristic. The fracturing characteristic may comprise the characteristics of high frequency transients indicative of fracturing events (606). The intensity, frequency, duration and signal evolution of the transients may be monitored to provide the fracturing characteristic. Additionally or alternatively the fracturing characteristic may comprise the longer term acoustic noise generated by fracture fluid flow to the fracture sites. The intensity and frequency of the noise may be analyzed to determine the fracturing characteristic. The method allows real-time control of the fracturing process.

A method and system for transmitting signals from a distributed acoustic sensor, DAS, into a well through at least one pin penetrator running from a downhole side to a top side of a subsea wellhead, and without degrading quality of the signals. The method includes: connecting a first assistant recording package, ARP, between the DAS and the at least one pin penetrator on a downhole side of the wellhead; connecting a second ARP between a data acquisition system and the at least one pin penetrator on the topside of the well head; converting DAS signals to electrical signals by the first ARP and performing signal conditioning; transmitting signals received from the DAS sensors, from the first ARP and through the wellhead to the second ARP. The system implements the method.

A workflow using techniques for improving signal-to-noise ratio and decreasing interferences for Low-Frequency Distributed Acoustic Sensing is described.

A downhole device is provided that is intended to be co-located with an optical fiber cable to be found, for example by being fixed together in the same clamp. The device has an accelerometer or other suitable orientation determining means that is able to determine its positional orientation, with respect to gravity. A vibrator or other sounder is provided, that outputs the positional orientation information as a suitable encoded and modulated acoustic signal. A fiber optic distributed acoustic sensor deployed in the vicinity of the downhole device detects the acoustic signal and transmits it back to the surface, where it is demodulated and decoded to obtain the positional orientation information. Given that the device is co-located with the optical fiber the position of the fiber can then be inferred. As explained above, detecting the fiber position is important during perforation operations, so that the fiber is not inadvertently damaged.

Embodiments of the present invention help in the processing and interpretation of seismic survey data, by correlating or otherwise comparing or associating seismic data obtained from a seismic survey with flow information obtained from a well or borehole in the surveyed area. In particular, embodiments of the present invention allow for flow data representing a flow profile along a well that is being monitored by a distributed acoustic sensor to be determined, such that regions of higher flow in the well can be determined. For example, in the production zone the well will be perforated to allow oil to enter the well, but it has not previously been possible to determine accurately where in the production zone the oil is entering the well. However, by determining a flow rate profile along the well using the i)AS then this provides information as to where in the perforated production zone oil is entering the well, and hence the location of oil bearing sands. This location can then be combined or otherwise correlated, used, or associated with petroleum reservoir location information obtained from the seismic survey, to improve the confidence and/or accuracy in the determined petroleum reservoir location.

A Distributed Acoustic Sensing (DAS) fiber optical assembly comprises adjacent lengths of optical fiber A, B with different directional acoustic sensitivities, for example by providing the first length of optical fiber A with a first coating 35, such as acrylate, and the second length of optical fiber B with a second coating 36, such as copper, wherein the first and second coatings 35 and 36 may be selected such that the Poisson's ratio of the first length of coated fiber A is different from the Poisson's ratio of the second length of coated fiber B. The different Poisson's ratios and/or other properties of the adjacent lengths of optical fiber A and B improve their directional acoustic sensitivity and their ability to detect broadside (radial) acoustic waves.

Described herein is a method and system of distributed acoustic sensing, such as in an urban or metropolitan area involving a dedicated and established fibre optic communications network including a data centre. In general, the disclosed method and system includes the steps of (a) selecting an optical fibre cable installation having a path extending across a selected geographical area, the optical fibre cable installation including a bundle of optical fibres and forming part of a fibre-optic communications network, (b) determining characteristics associated with the optical fibre and/or the selected optical fibre installation, (c) transmitting outgoing light in the optical fibre, (d) receiving reflected light back scattered along the optical fibre, and (e) based on the reflected light and the determined characteristics, generating an alert signal representative of an acoustic event. The disclosed method and system may be useful in the detection of acoustic events near or within the selected geographical area.

A method for monitoring fluid flow in a conduit comprises:

• • acoustically coupling an optical fiber to the conduit adjacent one or more flow restrictions (R₁-R₄) in the conduit;
  • inducing a Distributed Acoustic Sensing (DAS) assembly to measure an acoustic noise signature (SNR_1-4) generated in the fiber by the fluid flowing through each flow restriction (R₁-R₄);
  • deriving the fluid flow rate of the fluid (Q_I, Q_I+II) flowing through each flow restriction (R₁-R₄) from the measured acoustic noise signature (SNR_1-4); and
  • displaying the derived fluid flow rate (Q_I, Q_I+II) at a fluid flow rate monitoring display.

Using distributed acoustic sensing (DAS) fiber optic cable for borehole surveying and/or well ranging.

The invention relates to DAS observation has been proven to be useful for monitoring hydraulic fracturing operations. While published literature has shown focus on the high-frequency components (>1 Hz) of the data, this invention discloses that much of the usable information may reside in the very low frequency band (0-50 milliHz). Due to the large volume of a DAS dataset, an efficient workflow has been developed to process the data by utilizing the parallel computing and the data storage. The processing approach enhances the signal while decreases the data size by 10000 times, thereby enabling easier consumption by other multi-disciplinary groups for further analysis and interpretation. The polarity changes as seen from the high signal to noise ratio (SNR) low frequency DAS images are currently being utilized for interpretation of completions efficiency monitoring in hydraulically stimulated wells.

Methods and apparatus for tracking objects in conduits, especially for tracking the movement of a pig in a pipeline, are disclosed. Distributed acoustic sensing is used to obtain signal returns from a plurality of discrete longitudinal sensing portions of a fibre optic cable which is laid along the length of the conduit. The method involves detecting an acoustic signature corresponding to the object moving in the conduit. The acoustic signature may comprise a series of pressure pulses caused by the object traversing joints etc. in the conduit. Preferably the method involves detecting pressure waves caused by the object as it moves through the conduit. Detecting the characteristic pressure wave signal provides discrimination of the object from other acoustic disturbances. In pipeline applications a pig can be tracked in real time, if the pig stops moving an alert can be generated and the location of the pig will be known.

This disclosure describes a method of calculating fluid distribution from a hydraulically fractured well, especially during a plug-and-perf hydraulic fracturing operation. The Distributed Acoustic Sensing (DAS) data is used to quantify the fluid distribution in separate perf clusters during fracturing, and the result can be used for completion design and optimization, hydraulic fracturing, and ultimately for oil and gas production.

A distributed acoustic sensing cable package having a polymer composite extruded over an optical waveguide to encase the waveguide and to form a crystalline matrix layer acoustically coupled to the waveguide. The crystalline matrix includes reinforcement fibers to further enhance transmission of a cable strain to the optical waveguide. During manufacture of the cable, the polymer composite may be extruded over the optical waveguide and subsequently subjected to heat treatment to increase the crystallinity of the polymer composite and increase the elastic modulus. Both axial and radial strain fields are effectively interact with cased fiber waveguide for producing measurable phase shift signal for distributed acoustic noise detection.

A system and method for monitoring oil flow rates along a producing oil or gas well using a Distributed Acoustic Sensing fiber is described. This system uses the low-frequency component of the acoustic signal as a measurement of temperature variations within the well. The relative flow contributions can then be inferred from these temperature fluctuations.

In order to address the above noted problems, embodiments of the present invention use distributed acoustic sensing to monitor the fluid level in an ESP activated well so as to monitor the condition and performance of the ESP. Embodiments of the invention use the ESP as an acoustic source in order to monitor the annulus fluid level within the well and to monitor the frequency of the ESP. Additionally, embodiments of the present invention may use distributed acoustic sensing to monitor the flow rates of the production fluid above and below the ESP to determine the pump's efficiency. In particular, some embodiments utilise one or more optical fibers to measure the acoustic waves generated by the ESP, wherein the fiber cabling has already been deployed along the length of the well. As such, the present invention is a non-invasive, in-situ method for monitoring the condition and performance of an ESP.

A directionally sensitive Distributed Acoustic Sensing (DAS) fiber optical assembly comprises adjacent lengths of optical fiber (A,B) with different directional acoustic sensitivities, which are used to detect the direction (a) of acoustic signals relative to the lengths of optical fiber (A, B).

This application relates to methods and apparatus for monitoring of conduits, especially oil or gas pipelines, as an object such as pipeline pig moves within the conduit. The method comprises monitoring at least part of a conduit (206) using a fibre optic (202) distributed acoustic sensor (204) as the object (208) passes along the conduit. The acoustic signals detected from at least one sensing location (203) as the object moves along the conduit are analysed so as to discriminate acoustic signals received at said sensing location from different locations. The method allows the contributions to the acoustic signal at a given sensing portion from different locations to be separately identified, and can allow the detection of the location of acoustic sources along the conduit even if the source is outside the section of conduit which is monitored. The method provides a method of leak detection that can extend the monitoring of the pipeline beyond the location of the optical fibre.

Methods of performing a distributing sensing measurement included the steps of, modulating the frequency of one or more light signals output from one or more light sources, using one or more multi-level sequence of bits so that the one or more light signals are frequency modulated; using the one or more frequency modulated light signals to provide a pump signal and a probe signal; propagating the pump and probe signals along an optical fiber; using interactions between the pump and probe signal to perform a distributed sensing measurement. There is further provided corresponding sensing systems.