A method for distributed acoustic sensing includes sending a first optical pulse down an optical fiber, wherein light from the first optical pulse is backscattered from positions along a length of the optical fiber according to coherent Rayleigh scattering; splitting backscattered light from the first optical pulse into a first portion for a first interferometer and a second portion for a second interferometer, the first interferometer having a first gauge length and the second interferometer having a second gauge length, wherein the first gauge length is different from the second gauge length; detecting a first interferometric signal from the first interferometer responsive to the first portion of backscattered light; detecting a second interferometric signal from the first interferometer responsive to the second portion of backscattered light; and processing the first and second interferometric signals for two different sensing applications adapted for the first and second gauge lengths, respectively.

Various aspects described herein relate to a machine learning based detecting of fracture hits in offset monitoring wells when designing hydraulic fracturing processes for a particular well. In one example, a computer-implemented method includes receiving a set of features for a first well proximate to a second well, the second well undergoing a hydraulic fracturing process for extraction of natural resources from underground formations; inputting the set of features into a trained neural network; and providing, as output of the trained neural network, a probability of a fracture hit at a location associated with the set of features in the first well during a given completion stage of the hydraulic fracturing process in the second well.

The present disclosure relates to systems and methods for treating subterranean formations through adjacent well communications. A method to determine well communication, comprises generating one or more pressure excitation signals via an electrical pump in a first well, wherein the one or more pressure excitation signals produce one or more response signals based on the one or more pressure excitations signals interacting with a subterranean formation; measuring the one or more response signals through transmission of the one or more response signals to a second well with a fiber optic cable, wherein the one or more response signals are measured as time-series data; determining a formation response by processing the one or more response signals with an information handling system; determining a well parameter via one or more sensors; and performing a treatment operation to mitigate well interference between the first well and the second well.

A hybrid cable for collecting data inside a well includes an electrical cable extending along a longitudinal axis of the hybrid cable, an optical fiber extending along the longitudinal axis, an armor that extends along the longitudinal axis, and encircles the electrical cable and the optical fiber, and a connecting device extending along the longitudinal axis, to enclose the electrical cable and the optical fiber, and to be enclosed by the armor. The connecting device has an unsmooth external surface.

Various embodiments include apparatus and methods implemented to take into consideration gauge length in optical measurements. In an embodiment, systems and methods are implemented to interrogate an optical fiber disposed in a wellbore, where the optical fiber is subjected to seismic waves, and to generate a seismic wavefield free of gauge length effect and/or to generate a prediction of a seismic wavefield of arbitrary gauge length, based on attenuation factors of a plurality of wavefields acquired from interrogating the optical fiber. In an embodiment, systems and methods are implemented to interrogate an optical fiber disposed in a wellbore, where the optical fiber is subjected to seismic waves, and to convert a seismic wavefield associated with a first gauge length to a seismic wavefield associated with a different gauge length that is a multiple of the first gauge length. Additional apparatus, systems, and methods are disclosed.

A fracture mapping system for use in hydraulic fracturing operations utilizing non-directionally sensitive fiber optic cable, based on distributed acoustic sensing, deployed in an observation well to detect microseismic events and to determine microseismic event locations in 3D space during the hydraulic fracturing operation. The system may include a weighted probability density function to improve the resolution of the microseismic event on the fiber optic cable.

A well system includes a fiber optic cable positionable downhole along a length of a wellbore. The well system also includes a reflectometer communicatively coupleable to the fiber optic cable. The reflectometer injects optical signals into the fiber optic cable and receives reflected optical signals from the fiber optic cable. Further, the reflectometer identifies strain detected in the reflected optical signals generated from seismic waves of a microseismic event. Additionally, the reflectometer identifies a focal mechanism of the microseismic event and velocities of the seismic waves. The reflectometer also determines a position of the microseismic event using the strain detected in the reflected optical signals, the focal mechanism of the microseismic event, and the velocities of the seismic waves.

Various embodiments include apparatus and methods implemented to take into consideration gauge length in optical measurements. In an embodiment, systems and methods are implemented to interrogate an optical fiber disposed in a wellbore, where the optical fiber is subjected to seismic waves, and to generate a seismic wavefield free of gauge length effect and/or to generate a prediction of a seismic wavefield of arbitrary gauge length, based on attenuation factors of a plurality of wavefields acquired from interrogating the optical fiber. In an embodiment, systems and methods are implemented to interrogate an optical fiber disposed in a wellbore, where the optical fiber is subjected to seismic waves, and to convert a seismic wavefield associated with a first gauge length to a seismic wavefield associated with a different gauge length that is a multiple of the first gauge length. Additional apparatus, systems, and methods are disclosed.

Methods and systems for assessing cross-well interference and/or optimizing hydrocarbon production from a reservoir by obtaining low frequency DAS and DTS data and pressure data from a monitor well, when both the monitor and production well are shut-in, and then variably opening the production well for production, and detecting the temperature and pressure fluctuations that indication cross-well interference, and localizing the interference along the well length based on the low frequency DAS data. This information can be used to optimize well placement, completion plans, fracturing plans, and ultimately optimize production from a given reservoir.

Various embodiments include apparatus and methods implemented to simulate geophone data from distributed acoustic sensing data, such as simulating vertical component geo phone waveform data from distributed acoustic sensing data. Embodiments include measuring vertical component of strain at a plurality of vertical positions along an optical fiber disposed along a wellbore at a well site. The measured vertical component of strain can be processed to generate a vertical component of displacement. The vertical component of displacement can be used to generate a vertical component of velocity from which a waveform simulating a waveform of geophone data can be output. Additional apparatus, systems, and methods are disclosed.