Carbon dioxide capture and storage (CCS) has been actively researched as a strategy to mitigate CO2 emissions into the atmosphere. The three components in CCS are monitoring, verification, and accounting (MVA). Seismic monitoring technologies can meet the requirements of MVA, but they require a quantitative relationships between multiphase saturation distributions and wave propagation elastic properties. One of the main obstacles for quantitative MVA activities arises from the nature of the saturation distribution, typically classified anywhere from homogeneous to patchy. The emerging saturation distribution, in turn, regulates the relationship between compres-sional velocity and saturation. In this work, we carry out multiphase flow simulations in a 2-D aquifer model with a log-normal absolute permeability distribution and a capillary pressure function parametrized by permeability. The heterogeneity level is tuned by assigning the value of the Dykstra-Parson (DP) coefficient, which sets the variance of the log-normal horizontal permeability distribution in the entire domain. Vertical permeability is a 10th of the horizontal value in each gridcell. We show that despite apparent differences in saturation distribution among differentrealizations, CO2 trapping and the V_p-S_w Rock Physics relationship are mostly functions of the DP coefficient. When the results are compared with the well accepted limits, Gassmann-Wood (homogeneous) (A Text Book of Sound; G. Bell and Suns LTD: London, 1941) and Gassmann-Hill (patchy) models, the V_p-S_w relationship never reaches the upper bound, that is, patchy model curve, even at the highest heterogeneity level in the model.
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