Abstract: This application relates to methods and apparatus for monitoring hydraulic fracturing in well formation and fracture characterization using distributed acoustic sensing (DAS). The method involves interrogating an optic fiber arranged down the path of a borehole to provide a distributed acoustic sensor and also monitoring flow properties of fracturing liquid pumped into the well where the acoustic data from the distributed acoustic sensor is processed together with the flow properties data to provide an indication of at least one fracture characteristic.

Abstract: The present invention is a method to determine where fractures are created within a wellbore during a formation fracturing operation, the method comprising the steps of: providing at least one sensor within a carrier capable of measuring and recording a pressure difference across the carrier as a function of time; releasing the sensor into fracturing fluids; injecting fracturing fluids into a wellbore during a fracturing operation; after at least one fracture has formed, permitting fluids to flow back from the fractured formation into the wellbore and to a surface facility; capturing at least one sensor from the fluids which flowed back from the fractured formation; reading recorded data from the captured sensor; and determining the relative size of at least two different fractures based on the recorded data.

Abstract: This application relates to methods and apparatus for monitoring hydraulic fracturing in well formation and fracture characterization using distributed acoustic sensing (DAS). The method involves interrogating an optic fiber arranged down the path of a borehole to provide a distributed acoustic sensor and also monitoring flow properties of fracturing liquid pumped into the well where the acoustic data from the distributed acoustic sensor is processed together with the flow properties data to provide an indication of at least one fracture characteristic.

Abstract: The present invention is a method to determine where fractures are created within a wellbore during a formation fracturing operation, the method comprising the steps of: providing at least one sensor within a carrier capable of measuring and recording a pressure difference across the carrier as a function of time; releasing the sensor into fracturing fluids; injecting fracturing fluids into a wellbore during a fracturing operation; after at least one fracture has formed, permitting fluids to flow back from the fractured formation into the wellbore and to a surface facility; capturing at least one sensor from the fluids which flowed back from the fractured formation; reading recorded data from the captured sensor; and determining the relative size of at least two different fractures based on the recorded data.

Abstract: This application relates to methods and apparatus for monitoring hydraulic fracturing in well formation and fracture characterization using distributed acoustic sensing (DAS). The method involves interrogating a optic fiber (102) arranged down the path of a bore hole (106) to provide a distributed acoustic sensor and also monitoring flow properties of fracturing fluid pumped (114) into the well. The acoustic data from the distributed acoustic sensor is processed together with the flow properties data to provide an indication of at least one fracture characteristic.

Abstract: A method for determining the physical location of a fiber optic channel in a fiber optic cable comprises the steps of a) providing at least one location key having a known physical location, b) establishing the location of the location key with respect to the fiber optic channel, and c) using the location information established in step b) to determine the physical location of the channel. The location key may comprises an acoustic source, a section of fiber optic cable that is acoustically masked, or at least one magnetic field source and step b) comprises using a Lorentz force to establish the location of the magnetic field source with respect to the fiber optic channel.

Abstract: A method for determining information about points in a wellbore that includes a region of interest comprises a) providing a first set of measured temperature data corresponding to a comparison portion of the wellbore that is not in the region of interest and a second portion of the wellbore that is in the region of interest, b) providing a second set of measured temperature data also corresponding to the comparison and second portions of the wellbore, c) on a microprocessor, using the comparison portions of the first and second data sets to align the first and second data sets, d) subtracting the second portion of the first data set from the portion of the second data set with which it is aligned, and e) outputting the result of step d) as human-readable information about points in the region of interest.

Abstract: A method for determining the physical location of a fiber optic channel in a fiber optic cable comprises the steps of a) providing at least one location key having a known physical location, b) establishing the location of the location key with respect to the fiber optic channel, and c) using the location information established in step b) to determine the physical location of the channel. The location key may comprises an acoustic source, a section of fiber optic cable that is acoustically masked, or at least one magnetic field source and step b) comprises using a Lorentz force to establish the location of the magnetic field source with respect to the fiber optic channel.

Abstract: A method of measuring fluid in-flow in a region of interest in a wellbore comprises deploying a fiber optic cable concurrently with placement of a downhole tubular, transmitting a light signal along the cable and receiving a reflected signal from the region of interest, and interpreting the received signal to obtain information about fluid flowing in the region of interest. The wellbore may include a horizontal portion. The received signal may also be interpreted by assessing amplitude and frequency spectra across array of channels, conditioning the received signal by removing at least a portion of the signal that is not related to flow, assessing flow regimes across depths and times, calculating axial flow/s within the wellbore using relationships for axial flow, and calculating flow into or out of the wellbore at one or more points using relationships for flow through an orifice.

Abstract: A method of measuring fluid in-flow in a region of interest in a wellbore comprises deploying a fiber optic cable concurrently with placement of a downhole tubular, transmitting a light signal along the cable and receiving a reflected signal from the region of interest, and interpreting the received signal to obtain information about fluid flowing in the region of interest. The wellbore may include a horizontal portion. The received signal may also be interpreted by assessing amplitude and frequency spectra across array of channels, conditioning the received signal by removing at least a portion of the signal that is not related to flow, assessing flow regimes across depths and times, calculating axial flow/s within the wellbore using relationships for axial flow, and calculating flow into or out of the wellbore at one or more points using relationships for flow through an orifice.

Abstract: A method of determining in-situ a relation between the seismic velocity and the state of stress in an underground formation located under a surface subjected to time-changing surface loading conditions. A relation is selected between the seismic velocity and the state of stress containing at least one unknown parameter. A seismic source is arranged at surface or in a borehole penetrating the underground formation, and a seismic receiver is arranged at a distance from the seismic source at surface or in a second borehole. At two different times the seismic velocity of the formation along a path from the seismic source to the seismic receiver is determined. The difference in surface loading conditions at the two times is converted in a difference in states of stress in the underground formation. The unknown parameter(s) are calculated to obtain the relation between the seismic velocity and the state of stress in the underground formation.

Abstract: A method of determining in-situ a relation between the seismic velocity and the state of stress in an underground formation located under a surface subjected to time-changing surface loading conditions. A relation is selected between the seismic velocity and the state of stress containing at least one unknown parameter. A seismic source is arranged at surface or in a borehole penetrating the underground formation, and a seismic receiver is arranged at a distance from the seismic source at surface or in a second borehole. At two different times the seismic velocity of the formation along a path from the seismic source to the seismic receiver is determined. The difference in surface loading conditions at the two times is converted in a difference in states of stress in the underground formation. The unknown parameter(s) are calculated to obtain the relation between the seismic velocity and the state of stress in the underground formation.

Abstract: A method of investigating a reservoir region in a subsurface formation by a time-lapse seismic survey. The subsurface formation comprises a further formation region adjacent to the reservoir region. Data are obtained from a time-lapse seismic survey and includes seismic data of the subsurface formation at a first point in time and a later point in time. The seismic data is processed to obtain a seismic representation of change in a predetermined seismic parameter in the further formation region, whereby the seismic parameter is dependent on stress. The seismic representation of change in the seismic parameter in the further formation region is interpreted for an indication of changes of stress distribution in the further formation region, and a property of the reservoir region is derived using the indication of change of stress distribution in the further formation region.