Abstract

Recent work by Murphy et. al. (1993) shows that compressional and shear sonic slowness measurements together with bulk density can be used to invert for the modulus of the pore fluid in clean, porous sandstones. The modulus of the pore fluid can then be compared against values for water, oil and gas at downhole conditions to identify the fluid type. There is also laboratory evidence (Murphy et. al. (1993)) and field evidence (Brie et. al. (1995)) that an approximate fluid saturation can be estimated from slownesses at sonic frequencies.

In this paper Murphy's fluid modulus inversion is combined with Brie's empirical saturation estimate to analyze sonic data from a well in Total's Tunu field for gas saturation. Biot-Gassmann is then used to replace the pore space with 100% water and 100% gas to assess the impact of different pore fluids on the AVO response. The modeling indicates that AVO attributes may be able to differentiate between water and gas for sands of comparable thickness to those at the well location studied.