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The objectives of this study are to determine the effect of complex overburden in offshore continental settings on the seismic wavefield and on the resultant seismic images and attributes. Seismic waves exhibit complex wave paths when propagating through heterogeneous geologic structures. A key step in understanding the consequences for imaging and, more importantly, amplitude versus angle behavior is to model this complexity in a known earth-velocity model. The earth model used, represented by the seismic velocities, should exhibit similar behavior to the real data but still remain as simple as possible. This is also the case in velocity-model building. However, the inability to include subtle geologic features leads to inaccuracy and uncertainty in the velocity model. Understanding how this inaccuracy manifests itself is vital in any predictive exercise using seismic attributes. To improve this understanding, several synthetic data sets were simulated using full-wavefield synthetics. It is evident from the results that subtle velocity features are required in the imaging velocity field to ensure accurate angle gather behavior whether output is from a ray-based Kirchhoff migration or full-wave equation algorithm. If this requirement is met, seismic attributes from an amplitude-preserving migration can be used as a facies prediction in conjunction with the correct imaging algorithm.

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An iterative and linearized inversion algorithm carried out in the x-t domain has been applied to a prestack seismic data set from the central Gulf of Mexico, offshore Louisiana. Sonic and density curves from a well located close to the seismic line are used to generate the initial starting models for the inversion. We tested the geologically realistic hypothesis that the starting models have an accurate impedance structure outside of the potential pay zone and that the prospective pay zone will have mechanical properties consistent with the presence or absence of hydrocarbons. The inversion, performed with starting models with pay zones with a Poisson’s ratio appropriate for 100% brine saturation or with a Poisson’s ratio intermediate between expected values for full brine and hydrocarbon saturation, does not converge to the real seismic gather. However, with a starting model having a Poisson’s ratio appropriate for hydrocarbon saturation in the target zone, there is convergence from the initial to the real seismic gather.

An alternative approach to identifying amplitudevariation-with offset (AVO) anomalies is to consider the AVO polarization in the AVO intercept-AVO gradient (A-B) plane. This method does not require deviations or separations from a background trend exhibited in traditional crossplots such as intercept-gradient (A-B) or near trace-far trace (N-F). A benefit of the hodogram or polarization method is that the wavelet is taken into consideration. Crossplotted intercept and gradient are polarized along a "background trend" for nonanomalous events and at angles different from the "background trend" for anomalous events. This allows recognition of anomalous behavior otherwise buried in a background. Attributes resulting from this methodology include (1) the polarization angle, (2) the polarization angle difference, (3) the AVO strength, (4) the polarization product, and (5) the linear-correlation coefficient. These different attributes can then be used to enhance AVO interpretation. Synthetic modeling for a succession of gas and brine layers encased in shale units indicates that the method can potentially be an effective hydrocarbon indicator. Application of the method to a real seismic dataset shows polarization anomalies associated with hydrocarbons.