Methods and systems are disclosed for determining a material property transition within a wellbore. In some embodiments, a method includes determining a material transition profile for each of a plurality of test points within a linear measurement path including, for each test point, determining an acoustic response for a first location within the linear measurement path, and determining an acoustic response for a second location within the linear measurement path. The test point is between the first and second locations. The method further includes generating a material transition profile for the test point based, at least in part, on a difference between the acoustic response at the first location and the acoustic response at the second location.

A seismic source is positioned at the surface of a geologic formation and a plurality of seismic receivers is positioned in a wellbore of the geologic formation. Seismic wavefield data is obtained based on the seismic source outputting seismic energy into the wellbore and the plurality of seismic receivers receiving the seismic energy. A velocity profile is determined along the wellbore based on the seismic wavefield data. P and S wave data in a downgoing direction is separated from the seismic wavefield data based on an inversion and the velocity profile. The P and S wave data in the downgoing direction is adaptively subtracted from the seismic wavefield data to form residual wavefield data. The P and S wave data in a upgoing direction is separated from the residual wavefield data based on the inversion and an updated velocity profile. The P and S wave data in the upgoing and downgoing direction is output.

A seismic source is positioned at the surface of a geologic formation and a plurality of seismic receivers is positioned in a wellbore of the geologic formation. Seismic wavefield data is obtained based on the seismic source outputting seismic energy into the wellbore and the plurality of seismic receivers receiving the seismic energy. A velocity profile is determined along the wellbore based on the seismic wavefield data. P and S wave data in a downgoing direction is separated from the seismic wavefield data based on an inversion and the velocity profile. The P and S wave data in the downgoing direction is adaptively subtracted from the seismic wavefield data to form residual wavefield data. The P and S wave data in a upgoing direction is separated from the residual wavefield data based on the inversion and an updated velocity profile. The P and S wave data in the upgoing and downgoing direction is output.

A system and method for acoustically profiling a wellbore while drilling, and which identifies depths in the wellbore where the wellbore diameter is enlarged or has highly fractured sidewalls. These depths are identified based on monitoring either travel time or signal strength of acoustic signals that propagate axially in the wellbore. Correlating wellbore depth to travel time of a signal traveling downhole inside of a drill string and uphole outside of the drill string yields an average signal velocity in the wellbore. Depths having a lower average signal velocity indicate where the wellbore diameter is enlarged or has highly fractured sidewalls. These depths are also identified by generating separate acoustic signals inside and outside of the drill string, comparing signal strengths of signals reflected from the wellbore bottom, and identifying the depths based on where there is an offset in the strengths of the reflected signals.

A system and method for acoustically profiling a wellbore while drilling, and which identifies depths in the wellbore where the wellbore diameter is enlarged or has highly fractured sidewalls. These depths are identified based on monitoring either travel time or signal strength of acoustic signals that propagate axially in the wellbore. Correlating wellbore depth to travel time of a signal traveling downhole inside of a drill string and uphole outside of the drill string yields an average signal velocity in the wellbore. Depths having a lower average signal velocity indicate where the wellbore diameter is enlarged or has highly fractured sidewalls. These depths are also identified by generating separate acoustic signals inside and outside of the drill string, comparing signal strengths of signals reflected from the wellbore bottom, and identifying the depths based on where there is an offset in the strengths of the reflected signals.

Method for characterizing subterranean formation is described. One method involves simulating a poroelastic pressure response of known fracture geometry utilizing a geomechanical model to generate a simulated poroelastic pressure response. Compiling a database of simulated poroelastic pressure responses. Measuring a poroelastic pressure response of the subterranean formation during a hydraulic fracturing operation to generate a measured poroelastic pressure response. Identifying a closest simulated poroelastic pressure response in the library of simulated poroelastic pressure response. Estimating a geometrical parameter of a fracture or fractures in the subterranean formation based on the closest simulated poroelastic pressure response.

Method for characterizing subterranean formation is described. One method involves simulating a poroelastic pressure response of known fracture geometry utilizing a geomechanical model to generate a simulated poroelastic pressure response. Compiling a database of simulated poroelastic pressure responses. Measuring a poroelastic pressure response of the subterranean formation during a hydraulic fracturing operation to generate a measured poroelastic pressure response. Identifying a closest simulated poroelastic pressure response in the library of simulated poroelastic pressure response. Estimating a geometrical parameter of a fracture or fractures in the subterranean formation based on the closest simulated poroelastic pressure response.

This disclosure presents a system, method, and apparatus for preventing fracture communication between wells, the system comprising: a sensor coupled to a fracking wellhead, circulating fluid line, or standpipe of a well and configured to convert acoustic vibrations in fracking fluid in the well into an electrical signal; a memory configured to store the electrical signal; a machine-learning system configured to analyze current frequency components of the electrical signal in a window of time and to identify impending fracture communication between the well and an offset well, the machine-learning system having been trained on previous frequency components of electrical signals measured during previous instances of fracture communication between wells; and a user interface configured to return a notification of the impending fracture communication to an operator of the well.

A method for determining a thermal maturity image of a subterranean region and a non-transitory computer readable medium, storing instructions for executing the method, are disclosed. The method includes, obtaining a seismic dataset for the subterranean region of interest, obtaining a thermal maturity value for a plurality of core samples taken from different positions within the subterranean region, and obtaining a plurality of well log types from the core sampling location. The method further includes determining a calibrated rock physics model based on the plurality of well log types, determining a pore fluid type based on the calibrated rock physics model, and determining a thermal maturity model based on the plurality of core samples, on the pore fluid type, and on the plurality of well logs. The method still further includes determining the thermal maturity image of the subterranean region based on the seismic dataset and thermal maturity model.

A method for determining a thermal maturity image of a subterranean region and a non-transitory computer readable medium, storing instructions for executing the method, are disclosed. The method includes, obtaining a seismic dataset for the subterranean region of interest, obtaining a thermal maturity value for a plurality of core samples taken from different positions within the subterranean region, and obtaining a plurality of well log types from the core sampling location. The method further includes determining a calibrated rock physics model based on the plurality of well log types, determining a pore fluid type based on the calibrated rock physics model, and determining a thermal maturity model based on the plurality of core samples, on the pore fluid type, and on the plurality of well logs. The method still further includes determining the thermal maturity image of the subterranean region based on the seismic dataset and thermal maturity model.