On the rock-physics basis for seismic hydrocarbon detection

Abstract

One of the primary fluid indicators for direct hydrocarbon detection in sandstones using seismic reflectivity is the difference between the saturated-rock P-wave impedance and the rock-frame impedance. This can be expressed in terms of the difference between the observed P-wave impedance squared and a multiplier times the square of the observed S-wave impedance. This multiplier is a fluid discrimination parameter that laboratory and log measurements suggest varies over a wide range. Theoretically, this parameter is related to the ratio of the frame bulk and shear moduli and the ratio of the frame and fluid-saturated rock densities. In practice, empirical determination of the fluid discrimination parameter may be required for a given locality. Given sufficient data for calibration, the parameter can be adjusted so as to best distinguish hydrocarbon-saturated targets from brine-saturated rocks. Using an empirically optimized fluid discrimination parameter has a greater impact on hydrocarbon detection success rate in the oil cases studied than for gas reservoirs, for which there is more latitude. Application to a wide variety of well-log and laboratory measurements suggests that the empirically optimized parameter may differ from direct theoretical calculations made using Gassmann’s equations. Combining laboratory and log measurements for sandstones having a broad range of frame moduli, varying from poorly consolidated to highly lithified, reveals a simple linear empirical relationship between the optimized fluid discrimination parameter and the squared velocity ratio of brine-saturated sandstones.