Effects of fluid changes on seismic reflections: Predicting amplitudes at gas reservoir directly from amplitudes at wet reservoir

Abstract

The equations for fluid substitution in a sample with known porosity and the mineral’s and pore-fluid’s elastic moduli are well-documented. Discussions continue on how to conduct fluid substitution in practical situations where more than one fluid phase is present and the porosity and mineralogy are not precisely defined. We pose a different question: If we agree on a fluid substitution method, and also agree that at partial saturation the bulk modulus of the “effective” pore fluid is the harmonic average of those of the components, can we conduct fluid substitution directly on the seismic reflection amplitude? To address this question, we conducted forward modeling synthetic exercises: We systematically varied the porosity, clay content, and thickness of the reservoir and assumed that the properties of the bounding shale are fixed. Next, we used a velocity-porosity model to compute the elastic properties of the dry-rock frame and applied Gassmann’s equation to compute these properties in wet rock as well as at partial gas saturation. After that, we generated prestack synthetic seismic reflections at the top of the reservoir at full saturation and at partial saturation, and related one to the other. We found that within our assumption framework, there is an almost linear relation between the intercepts of the P-to-P reflectivity for the wet and gas reservoir. The same is true for the gradients. We have provided best-linear-fit equations that summarize these results. We applied this technique to field data and found that we can approximately predict the seismic amplitude at a gas reservoir from that measured at a wet reservoir, given that all other properties of the rock remain fixed. The solution given here should be treated as a method, meaning it should be tested and modified for various rock types and textures.