During 4D seismic reservoir characterization, it is important to have reliable rock physics models for both static (e.g., mineralogy, porosity, cement volume) and dynamic (e.g., saturation, pressure, temperature) reservoir parameters. Without a good understanding of reservoir geology and associated static rock physics properties, it is impossible to interpret time-variant changes in pore pressure and saturation (Andersen et al., 2009). The dry rock properties of the reservoir can be obtained from well-log data combined with geological information about mineral composition and rock texture, and Gassmann theory to estimate the effect of pore fluid changes. Normally, core measurements are undertaken to quantify stress sensitivity, but these are often affected by induced fractures caused by the coring acquisition that will enhance the stress sensitivity of the rock (Holt et al., 2005). Duffaut and Landrø (2007) showed how calibrated Hertz-Mindlin contact theory could be applied to estimate stress sensitivity on VP/VS ratios in two North Sea oil fields (Statfjord and Gullfaks), in order to explain observed AVO signatures during water injection and associated pore-pressure increase. It was found that loose Gullfaks sands yielded high VP/VS ratios (up to about 7) during water injection, whereas slightly quartz-cemented Statfjord sands yielded more moderate changes in VP/VS ratios (approximately 2). The differences were modeled by varying the number of grain-to-grain contacts. In this paper we further investigate the pressure sensitivity of seismic parameters in these two oil fields, applying the rock physics modeling approach presented by Avseth and Skjei (TLE, this issue), and we demonstrate a good match between rock physics modelling results and seismic observations in terms of VP/VS. The stress sensitivity of VP/VS decreases drastically when sands become cemented, as crack-like porosity at grain contacts are eliminated.

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