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Characterization of Petroleum Compositions and the Causes for Large Heterogeneities in Deep Offshore Settings in Eastern Brazilian Marginal Basins

Abstract

In the last five years, the marginal basins along eastern Brazil have been the focus of renewed petroleum exploration. Recent drilling results in deep offshore settings of these basins have provided evidence of petroleum systems with very large compositional heterogeneities. This work aims at characterizing the different types of petroleum properties and the processes responsible for their heterogeneities in marginal basins in eastern Brazil. It is widely known that petroleum composition and physical properties vary according to several processes. Source-rock richness and kerogen type and maturity determine the composition of the expelled petroleum, with API gravities, gas-to-oil ratios (GOR) and gas dryness increasing with maturity. In the basins along the Brazilian eastern margin, contributions from more than one source-rock level (usually Albian to Turonian marine marls and shales) led to the difficult task of unravelling mixtures using information from oil (gas chromatographic, biomarker and isotopic data) and gas (composition, carbon and hydrogen isotopes). In the studied basins, some of the variations of API gravity and GOR can be attributed to petroleum phase separation along upward migration pathways. During and after accumulation in a reservoir, processes like charge mixing, biodegradation, and remigration accounted for very complex range of oil and gas compositions. In some cases, it could be shown that early-generated black oils accumulated in shallow reservoirs received a variable contribution of biogenic methane from surrounding rocks. Later pulses of lighter, more mature oils mixed to variable extents with previously accumulated oils, causing an increase in API and GOR. As source rocks entered the late-oil and gas windows, upward moving gas interacted with earlier black-oil and volatile-oil accumulations, leading to complex gas composition and phase separation. Gas caps broke through seals, and gas condensates were pooled in shallower reservoirs, thus forming stacked accumulations with quite variable petroleum composition and properties. The distribution of fluid types as a function of migration distance from the source rock is thus far from straightforward. Hence, predicting petroleum composition and phases by petroleum systems modeling in this type of setting is a very challenging task, requiring refined facies maps, petrophysical data, detailed PVT compositional kinetic models and calibration data.