Poisson's ratio at high pore pressure

Laboratory investigations suggest that a precise relationship exists between Poisson's ratio, pore pressure and fluid type. Values of Poisson's ratio for dry samples are significantly smaller than those for fluid-saturated samples. The values are anomalously high for high pore pressure, with the possibility of differentiating between gas-saturated, brine-saturated and oil-saturated porous rocks. The present study considers two overpressure models, based on oil/gas conversion and disequilibrium compaction, to obtain Poisson's ratio versus differential pressure (confining pressure minus pore pressure). The model results are in good agreement with experiments. Poisson's ratio is approximately constant at high differential pressures and increases (decreases) for saturated (dry) rocks at low differential pressures. Fluid type can be determined at all differential pressures from Poisson's ratio. The analysis is extended to the anisotropic case by computing the three Poisson's ratios of a transversely isotropic rock versus differential pressure. While one of them is practically independent of effective pressure, the others increase with increasing pore pressure. Experiments performed on cores under different pressure conditions, and calibration of the models with these data, provide a tool for inverting pore pressure from seismic data.