Effect of capillarity and relative permeability on Q anisotropy of hydrocarbon source rocks. Issue 2 (11th May 2019)

• Record Type: Journal Article
• Authors: Santos, J E; Savioli, G B; Carcione, José M; Ba, Jing
• Is Part Of: Geophysical journal international. Volume 218:Issue 2(2019)
• Page Start: 1199
• Page End: 1209
• Publication Date: 2019-05-11
• Subjects: Numerical approximations and analysis -- Numerical modelling -- Numerical solutions -- Computational seismology -- Seismic anisotropy -- Seismic attenuation; Geophysics -- Periodicals; 550
• DOI: 10.1093/gji/ggz217
• Languages: English
• ISSNs: 0956-540X

Abstract

SUMMARY: Shale reservoir formations are porous rocks of low permeability composed of fluid-saturated illite–smectite and kerogen layers, which behave as viscoelastic transversely isotropic (VTI) media at long wavelengths, that is, much larger than the average layer thickness. Seismic waves travelling across these heterogeneous materials induce wave-induced fluid flow (WIFF) and Biot slow waves generating energy loss (mesoscopic loss) and velocity dispersion. When these formations are saturated by two-phase fluids, the presence of capillary forces—interfacial tension—and interaction between the two fluids as they move within the pore space need to be taken into account. This can be achieved using a Biot model of a poroelastic solid saturated by a two-phase fluid that includes capillary pressure and relative permeability functions and supports the existence of two slow waves. An upscaling finite-element method is used to analyse the WIFF, which determines an effective VTI medium predicting higher attenuation and ( Q ) anisotropy than the classical single-phase (single fluid) models.