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Strong seismic flat spots are typically associated with the oil/water contact (OWC) in many amplitude-supported deepwater South Atlantic Basin (SAB) discoveries, particularly in relatively shallow (∼2000 mbml), high-porosity unconsolidated Eocene-age reservoirs. These reservoirs contain biodegraded oils that have low API gravity, low gas-oil ratios, high viscosities, and fluid acoustic velocities between 4500 and 5000 ft/s. Often, a mismatch in amplitude is noted when comparing an observed seismic-amplitude response with a synthetic forward model generated using sonic logging data. These observations can be attributed to the high viscosity (low API gravity) of biodegraded oil that can lead to wave-induced heterogeneous pore pressure at logging frequencies, thus deviating from a key assumption in Gassmann's fluid-substitution theory. These dispersion effects can lead to significantly slower acoustic velocities of these oil-bearing reservoirs at seismic frequencies than those measured at logging frequencies. Using a generalized fluid/solid-substitution theory, we model this change in acoustic velocity and find that the theory can explain the observed bright-spot response.

Pore fluid pressures encountered in the deep-water Gulf of Mexico typically exceed hydrostatic pressures shortly below the mudline. While pore pressures often become quite high at depth, the overall pressure trend usually falls within a fairly narrow window and—more importantly—the pressures display a rather consistent relationship with measurable rock properties such as velocity, resistivity, and density. The consistency of these trends follows directly from two conditions: the dominance of disequilibrium compaction as the primary source of geopressures in this basin (Osborne et al., 1997, Swarbrick et. al. 2002), and that most parts of the basin are currently at or near their maximum historical effective stress. Disequilibrium compaction leads to a direct relationship between maximum effective stress and porosity; thus, having present day effective stress near its maximum value implies that current porosities indicate current effective stresses and hence current pore fluid pressures. This generally stable behavior has allowed the development and application of a number of pressure-prediction transforms which have facilitated improvements in the safety and efficiency of deepwater drilling (e.g., Eaton, 1975, Gutierrez et al., 2006). (Effective stress is assumed to be the stress acting on the rock frame; in this work, it is taken as equal to the difference between total stress and pore-fluid pressure as proposed by Terzaghi, 1923.)