A comparison of the seismic velocities estimated from actual seismic data and well logs shows apparent discrepancies for the certain frequency ranges. The difference is related to the presence of the propagation velocity dispersion typically ignored in seismic signal processing as the second order effect. In addition, neglecting the effects of velocity dispersion in seismic imaging algorithms reduces the resolution in mapping the reservoir properties. Several theoretical models relating seismic data and their dispersive properties to important reservoir characteristics, such as porosity, permeability, fluid saturation, etc., are discussed. Velocity dispersion and signal attenuation in rocks with fluids are mostly affected by two mechanisms of the fluid-solid interactions, the Biot mechanism and the so-called "squirt flow" mechanism. The Biot mechanism is the more conventional one and it occurs at the macroscale level, whereas the "squirt flow" mechanism describes fluid flow at the pore scale level. It is considered how one can relate velocity dispersion and attenuation to measurable rock and fluid properties by coupling two mechanisms. New aspects of modeling attenuation and dispersion effects in partially saturated fluid based on statistical approach to scattering from aggregates of gaseous bubbles is also introduced.

The results indicate the first step in modeling complex reservoir properties from broadband interwell and surface seismic data. It can be particularly applied to the extraction of permeability anisotropy from attenuation and dispersion data to image the fluid flow in a reservoir. The separation of the elastic scattering component of the velocity dispersion could be useful for the prediction of depositional environments. The task to predict the dispersive properties of the reservoir away from the well control using interwell and surface seismic information can be also accomplished.

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