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DOI:10.1306/11132524122
Porosity evolution and geometry in Santos Basin Aptian pre-salt petrofacies
William Freitas12 , Thisiane Dos Santos2 , Mariane Trombetta2 , Sabrina Danni Altenhofen2 , Argos Belmonte Silveira Schrank12 , Guilherme Martinez2 , Anderson Maraschin2 , Felipe Dalla Vecchia2 , Amanda Goulart Rodrigues1 , Luiz Fernando De Ros1 , and Rosalia Barili12
1 Instituto de Geociências, Campus do Vale. Federal University of Rio Grande do Sul (UFRGS), Av. Bento Gonçalves, 9500 Agronomia, Porto Alegre 90650-001, Brazil
2 Institute of Petroleum and Natural Resources (IPR), Building 96J, Pontifical Catholic University of Rio Grande do Sul (PUCRS), Av. Ipiranga, 6681-Partenon, Porto Alegre 90619-900, Brazil
Ahead of Print Abstract
The pre-salt deposits from offshore southeastern Brazil account approximately 3/4 of the total hydrocarbon production of the country. Consequently, they are the subject of various studies aimed at better understanding the primary and diagenetic controls on their reservoir quality. The Barra Velha Formation (Aptian, Santos Basin) constitutes the main reservoirs of the pre-salt sag section, essentially composed of magnesian clays, calcite spherulites and fascicular shrubs, and intraclasts reworked from these aggregates. The pore systems of these rocks are highly complex, owing to depositional and diagenetic controls. Therefore, the origin and distribution of porosity and permeability are difficult to understand. In order to better understand and characterize the pore systems of the unusual pre-salt reservoirs, this study aimed to recognize the relationships among their porosity and permeability values, and pore types, within the context of the evolution and geometry of their pore systems. X-ray microtomography (m-CT) scanning of 251 samples from 3 wells was performed to obtain the three-dimensional (3-D) porosity distribution, and the main pore types were described in detail in 583 thin sections. Thirteen petrofacies were defined for the studied samples, and the 3-D pore network was reconstructed for characteristic samples of each petrofacies. Image segmentation was applied to quantify pore sizes and shapes, as well as to visualize the connections between them. Petrofacies with low quality or considered non-reservoirs correspond to rocks where the magnesian clay matrix was partially replaced by dolomite, or where dolomite or silica filled interparticle pores where pores were generated by matrix dissolution, leading to poorly connected vuggy pores. On the other hand, high quality reservoirs correspond either to in situ rocks with porosity generation mainly through widespread dissolution of the Mg-clay matrix, further enhanced by the dissolution of calcite spherulites and shrubs, as well as reworked rocks with high interparticle primary porosity, and crystalline rocks formed by pervasive dolomite replacement followed by dissolution, creating intercrystalline porosity. Dissolution played not only a significant role in increasing porosity, but also in increasing pore connectivity and pore size, as observed through pore network segmentation tools and through the Area 3D, EqDiameter, and ShapeVA3d attributes. Increased understanding of the pre-salt reservoir porosity patterns is important not only for exploration for new accumulations, but also for optimizing the recovery from currently producing reservoirs.
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Please cite this AAPG Bulletin Ahead of Print article as:
William Freitas , Thisiane Dos Santos , Mariane Trombetta , Sabrina Danni Altenhofen , Argos Belmonte Silveira Schrank , Guilherme Martinez , Anderson Maraschin , Felipe Dalla Vecchia , Amanda Goulart Rodrigues , Luiz Fernando De Ros , Rosalia Barili: Porosity evolution and geometry in Santos Basin Aptian pre-salt petrofacies, (in press; preliminary version published online Ahead of Print 15 November 2025: AAPG Bulletin, DOI:10.1306/11132524122.
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