Estimates of the effective fluid modulus from seismic cannot be directly converted to the true pore-volume weighted mean saturation S¯w determined from fluid flow principles by using the saturation laws currently in use. One of the reasons is that seismic waves sample the reservoir geology and production induced saturation heterogeneity in a different way from the fluids. This mismatch prevents accurate quantitative evaluation of saturation changes from 4D seismic analysis. To tackle this problem, a reservoir-related saturation law is developed for a turbidite reservoir - this geology being chosen because the architecture for a single sand package can be modelled as a stack of horizontal beds. An effective medium and perturbation theory are applied to the determination of the seismic properties of this model. This calculation provides a relationship that connects the true saturation S¯w to the effective fluid modulus from seismic via statistical measures of the vertical spread of the porosity and saturation variations in the reservoir. These statistics can be extracted from the simulation model and if known, enable the new saturation law to deliver a significant improvement in accuracy when estimating S¯w compared to other well-known laws. The relationship that has been developed also captures the effect of inter-bedded shales and can therefore be used to estimate true saturation in regions of the reservoir with moderate to low net-to-gross, provided the fraction of the shale component is known. In practice, the final choice of saturation law depends upon the reservoir information available, the assumptions that can be tolerated and the accuracy required in any particular reservoir characterization study. © 2008 European Association of Geoscientists & Engineers.