Rock physics modeling to assess the impact of spatial distribution pattern of pore fluid and clay contents on acoustic signatures of partially-saturated reservoirs

Abstract

The identification of pore fluid type, saturation and distribution pattern within the pore space is of great significance as several seismic and petrophysical properties of porous rocks vary largely by fluid type, saturation and fluid distribution pattern. With the help of rock physics modeling, the impact of fluid saturation as well as fluid distribution pattern on seismic velocities, acoustic impedances and seismic amplitudes is estimated on porous rock of early Cretaceous Mississauga sands. For this purpose two saturation patterns: uniform and patchy saturations are considered within the pore spaces. The primary goal of this study is to understand the vertical and horizontal trends of numerous seismic parameters such as P-wave velocity (V P ), S-wave velocity (V S ), their impedances, V P /V S ratio, bulk density (ρ b ), seismic reflectivity etc. as a function of fluid saturation, saturation pattern (patchy or homogeneous), porosity (ϕ) and clay content. The results reveal that the seismic parameters and offset dependent amplitudes are very sensitive to pore fluid saturation and distribution patterns and physical properties. As the hydrocarbons (oil/gas) saturation increases, the compressional wave velocity decreases. P-wave velocity is 20–40 % higher in case of patchy saturation than of homogeneous saturation. Similarly, reservoir porosity and clay matrix control the elastic response of porous rock due to which seismic velocities decrease with increase in porosity and clay content.