Abstract

Using inverted seismic data from a turbidite depositional environment, we have determined that accounting only for rock types sampled at the wells can lead to biased predictions of the reservoir fluids. The seismic data consisted of two volumes resulting from a (multi-incidence angle) sparse-spike amplitude variation with offset inversion. Information from a single well (well logs and petrological analysis) was used to define an initial set of lithofluid facies that characterized rock type and porefill fluid to emulate a typical exploration setting. Based on our geologic understanding of the study area, we have augmented this initial model with lithofluid facies expected in the given depositional environment, yet not sampled by the well. Specifically, the new lithofluid facies accounted for variations in the mixture type and proportions of shales and sands. The elastic property distributions of the new lithofluid facies were modeled using appropriate rock-physics models. Finally, a geologically consistent, spatially variant, prior probability of lithofluid facies occurrence was combined with the data likelihood to yield a Bayesian estimation of the lithofluid facies probability at every sample of the inverted seismic data. Applying the augmented geologic prior probabilities, we were able to generate a scenario consistent with all available data, which supports further development of the field. In contrast, using the initial, purely data-driven lithofluid facies model based on a single well, the Bayesian classification would lead to prospectivity downgrade or suboptimal development of the field. We found that limited well control in quantitative interpretation needs to be counterweighted by geologic prior information based on detailed stratigraphic interpretation, to derisk geologic scenarios without bias.

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