A method includes deploying an optical fiber attached to a distributed acoustic sensing (DAS) interrogator in a wellbore, pre-setting gauge length of the DAS interrogator based on an expected measurement signal, interrogating the optical fiber using the DAS interrogator, receiving reflected DAS signals along a length of the optical fiber using the pre-set gauge length, performing an analysis to estimate a location and a magnitude of a strain source associated with the reflected DAS signals, and dynamically adjusting the gauge length for at least a portion of the optical fiber within a pre-defined limit of the DAS interrogator as a function of the estimated location and magnitude of the strain source to enhance sensitivity and to optimize signal-to-noise ratio.

A device and method for imaging, measuring and identifying multiphase fluid flow in wellbores using phased array Doppler ultrasound. The device includes a radially-configured or ring-shaped ultrasound transducer that when deployed in a well in Doppler mode can measure the velocity of radially flowing fluids in the wellbore and generate a 3D image of radial flow in the wellbore, including flowback into the wellbore after fracturing operations, or flow leaving the wellbore during water injection operations. The ring-shaped ultrasound transducer can also simultaneously operate in a B-mode to generate a B-mode image of the wellbore liner upon which the Doppler image can be overlaid. The device may also include a forward facing ultrasound transducer either instead of or in place of the ring-shaped transducer for obtaining information and images on axial flow in the wellbore in Doppler mode, and the location of phase boundaries and phase locations in B-mode.

A device and method for imaging, measuring and identifying multiphase fluid flow in wellbores using phased array Doppler ultrasound. The device includes a radially-configured or ring-shaped ultrasound transducer that when deployed in a well in Doppler mode can measure the velocity of radially flowing fluids in the wellbore and generate a 3D image of radial flow in the wellbore, including flowback into the wellbore after fracturing operations, or flow leaving the wellbore during water injection operations. The ring-shaped ultrasound transducer can also simultaneously operate in a B-mode to generate a B-mode image of the wellbore liner upon which the Doppler image can be overlaid. The device may also include a forward facing ultrasound transducer either instead of or in place of the ring-shaped transducer for obtaining information and images on axial flow in the wellbore in Doppler mode, and the location of phase boundaries and phase locations in B-mode.

System and methods of controlling fluid flow during reservoir stimulation treatments are provided. A flow distribution of treatment fluid injected into formation entry points along a wellbore path is monitored during a current stage of a multistage stimulation treatment. Upon determining that the monitored flow distribution meets a threshold, a remainder of the current stage is partitioned into a plurality of treatment cycles and at least one diversion phase for diverting the fluid to be injected away from one or more formation entry points between consecutive treatment cycles. A portion of the fluid to be injected into the formation entry points is allocated to each of the treatment cycles of the partitioned stage. The treatment cycles are performed for the remainder of the current stage using the treatment fluid allocated to each treatment cycle, wherein the flow distribution is adjusted so as not to meet the threshold.

System and methods of controlling fluid flow during reservoir stimulation treatments are provided. A flow distribution of treatment fluid injected into formation entry points along a wellbore path is monitored during a current stage of a multistage stimulation treatment. Upon determining that the monitored flow distribution meets a threshold, a remainder of the current stage is partitioned into a plurality of treatment cycles and at least one diversion phase for diverting the fluid to be injected away from one or more formation entry points between consecutive treatment cycles. A portion of the fluid to be injected into the formation entry points is allocated to each of the treatment cycles of the partitioned stage. The treatment cycles are performed for the remainder of the current stage using the treatment fluid allocated to each treatment cycle, wherein the flow distribution is adjusted so as not to meet the threshold.

A method of optimizing production of a hydrocarbon-containing reservoir by measuring low-frequency Distributed Acoustic Sensing (LFDAS) data in the well during a time period of constant flow and during a time period of no flow and during a time period of perturbation of flow and simultaneously measuring Distributed Temperature Sensing (DTS) data from the well during a time period of constant flow and during a time period of no flow and during a time period of perturbation of flow. An initial model of reservoir flow is provided using the LFDAS and DTS data; the LFDAS and DTS data inverted using Markov chain Monte Carlo method to provide an optimized reservoir model, and that optimized profile utilized to manage hydrocarbon production from the well and other asset wells.

A method of optimizing production of a hydrocarbon-containing reservoir by measuring low-frequency Distributed Acoustic Sensing (LFDAS) data in the well during a time period of constant flow and during a time period of no flow and during a time period of perturbation of flow and simultaneously measuring Distributed Temperature Sensing (DTS) data from the well during a time period of constant flow and during a time period of no flow and during a time period of perturbation of flow. An initial model of reservoir flow is provided using the LFDAS and DTS data; the LFDAS and DTS data inverted using Markov chain Monte Carlo method to provide an optimized reservoir model, and that optimized profile utilized to manage hydrocarbon production from the well and other asset wells.

A method comprises positioning a receiver in a borehole and determining an offset acoustic waveform at a target point. The method includes generating a reverse time sequence waveform of the determined offset acoustic waveform and generating, by a transmitter, an acoustic pulse based on the reverse time sequence waveform. The method includes detecting, by the receiver, an acoustic response to the acoustic pulse.

Methods and systems for measuring cluster efficiency for stages of wellbores are provided herein. One method includes selecting a frequency band for generating broadband tube waves within the fluid column of the wellbore and generating the broadband tube waves within the fluid column of the wellbore using a pressure pulse generator that is hydraulically coupled to the wellbore. The method also includes recording data corresponding to the broadband tube waves and reflected broadband tube waves using pressure receivers that are hydraulically coupled to the wellbore. The pressure receivers are arranged into arrays with two or more pressure receivers in each array. The data recorded by the pressure receivers relate to characteristics of reflectors (including perforation cluster/fracture interfaces) within the wellbore. The method further includes processing the recorded data using interferometry and performing full waveform inversion(s) on the processed data to determine frequency-dependent, complex-valued reflection coefficients at each perforation cluster/fracture interface.

A method can be used to determine multi-phase measurements of fluid flowing with respect to a wellbore. Signals can be received, and the signals can be emitted by each variable frequency acoustic emitter of a set of variable frequency acoustic emitters positioned spaced apart in a sensing transducer that is in an interior of a wellbore. The received signals can be converted into a flow rate of each of a set of different fluid phases of a fluid in the wellbore. The multi-phase measurements of the fluid can be determined using the converted flow rate.