Systems and methods for exchanging fracturing components of a hydraulic fracturing unit and may include an exchangeable fracturing component section to facilitate quickly exchanging a fracturing component of a hydraulic fracturing unit. The fracturing component section may include a section frame including a base, and a fracturing component connected to the base. The fracturing component section also may include a component electrical assembly and a component fluid assembly connected to the section frame. The fracturing component section further may include a coupling plate connected to the section frame. The fracturing component section also may include one or more of a plurality of quick-connect electrical couplers or a plurality of quick-connect fluid couplers connected to a coupling plate. The quick-connect electrical and fluid couplers may be positioned to receive respective electrical and fluid connections of the component electrical and fluid assemblies and connect to other portions of the hydraulic fracturing unit.

Embodiments of the disclosure are associated with an autonomous wellbore tool that includes a plug assembly and a positioning system. The positioning system may be provided on the plug assembly. According to an aspect, the positioning system includes a distance measurement system.

Embodiments of the disclosure are associated with an autonomous wellbore tool that includes a plug assembly and a positioning system. The positioning system may be provided on the plug assembly. According to an aspect, the positioning system includes a distance measurement system.

Deployable smart acoustic resonance particles have dense cores, compliant matrixes surrounding the cores and stiff outer shells surrounding the matrixes. The particles have mechanical stress sensitivities that provide unique band gap shifts when compressed. Groups of similar particles with similar stress sensitivities and similar band gap shifts are added at different times to hydraulic fluids, as circulated through wells with the fluid and pushed into fractures. A plural, sonic monopole well logging tool is lowered into the well to determine locations and depth of fractures and local pressures by distinct resonance of individual groups.

Deployable smart acoustic resonance particles have dense cores, compliant matrixes surrounding the cores and stiff outer shells surrounding the matrixes. The particles have mechanical stress sensitivities that provide unique band gap shifts when compressed. Groups of similar particles with similar stress sensitivities and similar band gap shifts are added at different times to hydraulic fluids, as circulated through wells with the fluid and pushed into fractures. A plural, sonic monopole well logging tool is lowered into the well to determine locations and depth of fractures and local pressures by distinct resonance of individual groups.

An imaging agent, a method of production of the imaging agent, and the use of the imaging agent for microseismic monitoring of subterranean formations such as those generated during hydraulic fracturing. The acoustic emitting agent is tailorable for emission delay to ensure placement and frequency emission profiles for well region differentiation. This monitoring tool is highly useful in gas, oil, and geothermal well defining and stimulation monitoring.

An imaging agent, a method of production of the imaging agent, and the use of the imaging agent for microseismic monitoring of subterranean formations such as those generated during hydraulic fracturing. The acoustic emitting agent is tailorable for emission delay to ensure placement and frequency emission profiles for well region differentiation. This monitoring tool is highly useful in gas, oil, and geothermal well defining and stimulation monitoring.

The present disclosure relates to systems, non-transitory computer-readable media, and methods for detecting a washout or other anomaly event in a wellbore. In particular, in one or more embodiments, the disclosed systems receive a plurality of measurements including a measured flow rate into the wellbore, a measured weight on a drill bit in the wellbore, a measured depth of the drill bit in the wellbore, and a measured pressure at a standpipe of the wellbore. In one or more embodiments, the disclosed systems estimate one or more parameters of a physical model for determining a theoretical estimate of the standpipe pressure. In one or more embodiments, the disclosed systems determine a probability that the washout or other anomaly event is occurring in the wellbore based at least partially upon the measurements and the theoretical estimate of the standpipe pressure.

The present disclosure relates to systems, non-transitory computer-readable media, and methods for detecting a washout or other anomaly event in a wellbore. In particular, in one or more embodiments, the disclosed systems receive a plurality of measurements including a measured flow rate into the wellbore, a measured weight on a drill bit in the wellbore, a measured depth of the drill bit in the wellbore, and a measured pressure at a standpipe of the wellbore. In one or more embodiments, the disclosed systems estimate one or more parameters of a physical model for determining a theoretical estimate of the standpipe pressure. In one or more embodiments, the disclosed systems determine a probability that the washout or other anomaly event is occurring in the wellbore based at least partially upon the measurements and the theoretical estimate of the standpipe pressure.

An apparatus for detecting a location of an optical fiber having an acoustic sensor disposed subsurface to the earth includes an acoustic emitter configured to emit a first signal having a first frequency and a second signal having a second frequency that is higher than the first frequency, the first and second emitted acoustic signals being azimuthally rotated around the borehole and an optical interrogator configured to interrogate the optical fiber to receive an acoustic measurement that provides a corresponding first received signal and a corresponding second received signal. The apparatus also includes a processor configured to (i) frequency-multiply the first received signal to provide a third signal having a third frequency within a selected range of the second frequency, (ii) estimate a phase difference between the second received signal and the third signal, and (iii) correlate the phase difference to the location of the optical fiber.