One of the biggest World-class oil districts, Santos basin (Brazil), is the site of several oil fields discovered since the first discovery well, Paraty, 2005. A set of pre-saline carbonates deposits found at 5 km depth opened a door into one of the most prolific basins discovered during the XXI century. About 4000 km2 of new High Resolution 3D seismic acquired during 2011–2012 and more than 20 wells drilled in block BMS-9 allows to improve the knowledge of the area, but still the reservoir characterization remains as a major challenge since the pre-saline carbonates reservoir corresponds to complex deposits with strong diagenetic process. The goal of this paper is to revisit the main geological factors controlling reservoir properties in the oil fields discovered in this block.

Geological overview

The Santos basin is placed in the East passive margin of Brazil, exhibiting a complex structural evolution. This basin was formed in the Afro-America separation, during the rift phase, that was responsible for the generation of assymetrical grabens/tilted-blocks systems. Several associated transcurrent faults were also created.

The petroleum system of the Santos basin has been well defined in most of their key elements. The main source rock for the area are the lacustrine deposits, black shales, from the Itapema Fm, a kerogen type I, capable to fill most of structures recognized in the basin. Migration occurs from Paleogene age, when a very effective seal, up to 2000 m of an evaporatic section was quickly deposited (composed from different events with diverse types of salt minerals) and the structural traps were also created suffering minor readjust. The reservoir is a thick package of carbonates, deposited during Barremian-Aptian ages, which can be split into two main episodes, (1) rift stage and (2) sag stage, the most prolific one till now, where several giant oil fields have been already discovered. This study is focused in the sag section, where more well data has been collected.

The main reservoir, Barra Velha Fm, with around 500 m cored, has a porous column about 300 m, with net-pay ranging from 30–200 m and average porosity around 12%. Permeabilities associated range from 50 md to 1000 md. This carbonate reservoir was deposited in an alkaline lacustrine environment, and carbonate fabric was highly influenced by subtle changes in the lake water level, and the paleo-geography present at the time of deposition, affecting and constraining the type of carbonate building blocks to be deposited. Three main facies have been defined by mean of the cores description (Fig. 1), i) in situ constructions, shrubs, composed by microbialites, stromatolatites, ii) reworked constructions, with presence of spherulatites and iii) massive laminites with possibility of high shale content, indicating a different periods of shallowing and deepening of the environment. Some common characteristics of the reservoir are:

  • highly ciclycity (identified by sequence stratigraphy analysis using Gamma Ray),

  • vertical anisotropy (variable porosities as a consequence of lake level variation),

  • existence of corrosion/erosion;

  • presence of Mg minerals diminishing porosity in some wells.

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