Abstract

The need to analyze subtle differences in seismic amplitude variation is gaining tremendous ground and so is the need to accurately model the medium that generates these subtle seismic signatures. The detection of the seismic response becomes more challenging when the medium is fractured. These fractures could be natural or artificial. Porous medium with embedded fractures in multiple orientation is quite common phenomena with natural reservoir, particularly in shales and carbonates. Gassmann isotropic relation is applicable only for homogeneously distributed equivalent porosity mediums. In natural reservoirs, particularly the fractured ones (orthorhombic medium), concept of equivalent porosity medium do not hold any more even though fractures occupy very little porosity volume in the background porous media, their compliance in a stress system with a saturant type could no longer be a straight forward problem to predict the seismic response of such fluid filled systems. In this work, we explore the possibility of detecting the nature of anisotropy in the given rock by comparing the equivalent porosity distribution through Gassmann isotropic and Gassmann anisotropic prediction. We found that consideration of a VTI medium does not make any difference in the predicted values of seismic velocity and modulus