In some areas, seismic data can exhibit the effects of strong azimuthal anisotropy (AA). One of the major causes of AA can be anomalous horizontal stress regimes, which can be modeled as horizontally transverse isotropy (HTI). The Stybarrow field, located offshore NW Australia in the Carnarvon sedimentary basin, is one such area, where strong horizontal stress conditions have been present throughout the basin’s tectonic history. We find evidence for AA in repeat 3D seismic data acquired at two separate azimuths over the Stybarrow field. AA is observed in amplitude versus offset (AVO) reflection amplitude difference maps and cross plots, and is consistent with dipole shear logs and borehole breakout data in the area. We model azimuthal AVO responses using Ruger’s HTI AVO equation, using the anisotropy parameters derived from dipole shear logs, and compare the results with AVO data from the two 3D seismic surveys. Certain fault blocks (but not all) exhibit the same AAVO trend in the seismic data as those modeled from log data, consistent with a stress-induced HTI anisotropic model interpretation.
The effect of single-phase fluid saturation on the seismic bulk modulus of a rock is well understood; however, the behavior becomes more complex when multiple fluids are present. Several fluid mixing theories have been developed (e.g., Voigt, Reuss, and Hill) and each is valid in certain situations; however, in some scenarios it is unclear which theory to select, or indeed whether any are accurate. The critical wave propagation behavior depends on the manner that fluids are spatially distributed within the rock, compared to a seismic wavelength. We apply elastic finite-difference modeling to different rock-fluid distribution scenarios and replicate behavior described by various theoretical, empirical and lab data results. Significantly, our results compare well with observations from lab experiments, yet do not rely on poroelastic or squirt-flow models whose parameters are difficult to estimate in real reservoir settings. Our elastic scattering approach is less computationally expensive than poroelastic modeling and can be more easily applied to actual reservoir rock and fluid distributions. Our results provide us with a powerful new tool to analyze and predict the effects of multiple fluids and ‘patchy’ saturation on elastic moduli and seismic velocities. They also challenge assumptions about the controlling factors on saturated bulk moduli, suggesting they are more strongly affected by the spatial fluid distribution properties and wave scattering, than by pore-scale fluid flow effects.