Abstract: High Resolution Stratigraphy and Stochastic Simulation of Albian/Cenomanian Deep-Water Reservoirs From Campos Basin

Souza Jr., Olinto G. - Petrobras/E&P; Remi Eschard - IFP; Paulo R. S. Johann - Petrobras/E&P; Frederique Foumier - IFP

The 3D numerical reservoir model of the Namorado field (Campos basin, Brazil) has been reconstructed with a new method combining a high-resolution sequence stratigraphy approach to stochastic reservoir simulations constrained by well and seismic data. The Namorado oil field is located in the Campos basin, 80 km from the Brazilian coast, under a water deep comprising between 110 and 250 m. From 60 drilled wells, 47 were used in this study. The geophysical data is represented by a stacked 3-D seismic block. Fourteen cored wells were analyzed.

The reservoir of the Namorado oil field is a turbidite succession deposited during the drifting phase of the Brazilian margin in the Albian-Cenomanian times. The base of the series corresponds to a major unconformity over platform and slope carbonates, and the top to a transgressive hemipelagic mudstone marker. The reservoir itself is 90 to 180m thick, and consists of pebbly sandstones, massive clean sandstones and laminated and rippled argillaceous sandstones. Reservoir units are separated by silty shales and hemipelagic marls, interbedded with carbonated debris-flow deposits and slumped units.

The reservoir was divided in three genetic sequences (Fig. 1) by applying a sequence stratigraphy approach on the wells, combined with an interpretation of 3D seismic data after a post-stack inversion. The genetic units are characterized by an overall fining upward trend due to succession in time of three depositional systems: amalgamated and channelized high-density turbidites, channel-levee systems, and an hemipelagic sedimentation. The trapping of sediments of the channelized units is also controlled by the substrate topography, due to a syn-sedimentary salt tectonic.

This conceptual geological model was used as a framework to constrain a stochastic numerical model of the lithofacies distribution in the reservoir. The seismic information, calibrated with the geological model, were added as a complementary constrain. Even in this case were numerous wells are available, the use of seismic data allowed us to reduce the uncertainty of the lateral variations of the facies proportions, resulting in a more realistic numerical geological model. Two methods were used to construct the spatial distribution model of the lithotype proportions: a quantitative and a qualitative approach. In the first method, a strong geological calibration is requested is called for, but in the second, the facies proportions are calculated from classic methods of estimation.

The simulation result is a set of equiprobable representations of the reservoir heterogeneity, which can be later used to perform fluid-flow simulations (Fig. 2).

AAPG Search and Discovery Article #90933©1998 ABGP/AAPG International Conference and Exhibition, Rio de Janeiro, Brazil