Using time-lapse seismic amplitude data to detect variations of pore pressure and fluid saturation due to oil displacement by water: a numerical study based on one-dimensional prestack inversion

Abstract

We describe a numerical study performed to appraise the ability of seismic amplitude data to infer the time evolution of pore pressure and fluid saturation due to hydrocarbon production. To this end, we construct a synthetic, spatially heterogeneous hydrocarbon reservoir model that is subject to numerical simulation of multiphase fluid flow. Hydrocarbon production is assumed in the form of one water-injection well and four oil-producing wells. The synthetic reservoir model exhibits average porosities of 20% and poses significant vertical resolution constraints to the usage of seismic amplitude data to ascertain variations of pore pressure and fluid saturation. We assume the availability of migrated prestack seismic amplitude and use one-dimensional models to simulate trace by trace the seismic amplitude data before and after the onset of production. One-dimensional seismic amplitude data are simulated in time-lapse mode making use of a rock physics model that includes the effect of differential compaction between sands and shales as a function of depth of burial. The sensitivity study presented in this paper is based on one-dimensional inversion and hence sheds light on the vertical resolution properties of noisy seismic amplitude data. Multiphase fluid-flow parameters have a measurable impact on fluid saturation and pore pressure and hence on the spatial distribution and time evolution of elastic parameters. However, the inverted spatial distributions of elastic parameters at best correlate with smooth spatial averages of the actual distributions of pore pressure and fluid saturation. Because for the case under consideration time-lapse seismic amplitude variations are of the order of 5%, such a correlation would be difficult, if not impossible, to ascertain without the use of one-dimensional inversion. We show that the elastic parameters inverted from prestack seismic amplitude data provide more degrees of freedom to discriminate between time variations of pore pressure and fluid saturation in the reservoir compared to distributions of acoustic impedance inverted from poststack seismic amplitude data.