Estimation of modified fluid factor and dry fracture weaknesses using azimuthal elastic impedance

Abstract

We consider the problem of fluid identification and fracture detection in unconventional reservoir (tight gas sand and shale gas) characterization. We begin with a simplification of the stiffness parameters and the derivation of a linearized reflection coefficient and azimuthal elastic impedance (EI). The accuracy of the simplification is confirmed in application to gas-bearing fractured rocks with low porosity and small fracture density. We have developed a modified fluid factor that is more sensitive to fluid type and less influenced by porosity. A two-step inversion workflow is evaluated based on the derived linearized reflection coefficient and azimuthal EI, including (1) a damped least-squares inversion for azimuthal EI, constrained by an initial model, and (2) a Bayesian Markov chain Monte Carlo inversion for the modified fluid factor and dry fracture weaknesses. Stability and accuracy are examined with synthetic data, from which we conclude that the modified fluid factor and dry fracture weaknesses can be stably determined in the presence of moderate data error/noise. The stability of our approach is further confirmed on a fractured tight gas sand field data set, within which we observe that geologically reasonable parameters (Lamé constants, the modified fluid factor, and dry fracture weaknesses) are determined. We conclude that our inversion workflow and its underlying assumptions form realistic predictions/discriminations of reservoir fracture and fluid parameters.