Fluid substitution in laminated sands

Abstract

Petrophysicists and geophysicists do “fluid substitution” to estimate the density and sonic velocity of porous rocks at saturation conditions such as fully hydrocarbon-saturated or “fizz-bearing” with fluids such as gas, condensate, and oil. However, the Gassmann model implementation in many commercial packages sometimes yields implausible results for the compressional sonic velocity in laminated sand-shale sequences. In particular, the counterintuitive phenomenon of fluid effects increasing with computed shale fraction is often observed, as in the gas-bearing interval of a well drilled with oil-based mud shown in Figure 1. DTC FLUSUB (Gassmann fluid substitution) is the result of substituting DTC WET to the observed water saturation SW. As expected (Brie et al., 1995) the modeled fluid effect is larger than the difference between the wet and the observed log DTC OBS. The observed fluid effects reach a maximum in the cleanest sand with the highest porosity, but the model predicts a maximum in shaley sand with low porosity.