HC Migration and Fluid Type in Shallow and Deep Water Santos Basin, Brazil: A 2D Modeling Approach
A. Lemgruber and F. T. T. Gonçalves
Laboratório de Modelagem Multidisciplinar de Bacias Sedimentares, Brazil
now working at Vale E&P, Rio de Janeiro, Brazil
Santos basin is a large sedimentary basin in Brazilian continental margin, with approximately 350.000 km2, that recently gained status due to its newly reserves discoveries in the pre-salt zone.
Santos basin is divided in two main tectonic phases: rift and passive margin, separated by a transitional period (Pereira & Feijó, 1994). The rift phase includes continental sediments placed in mid-grabens with thickness up to 3 km and its upper part is characterized by a sag phase that culminated with the deposition of a thick layer of salt. The passive margin phase, also called post-salt section, extends from Albian up to Recent, begins with the Albian carbonate platform and evolves to a marine phase. This post-salt section can reach up to 10 km thickness and is widely deformed by halocinetic mechanism.
Two petroleum systems have been recognized in this basin (ANP/UNESP/LEBAC, 2003). In The rift phase (pre-salt section) the Guaratiba formation is an organich rich interval, deposited in a continental environment (lacustrine), witch is probably responsible for recently accumulation discoveries under the salt layer. The other organic rich interval, located in the passive margin phase (post-salt section), have been recognized for a long time as the principal source unit of Santos basin (until the pre-salt discoveries). This source unit is the Itajaí-Açu formation, deposited under marine conditions, and its hydrocarbon may be mixed with those generated by the rift source rocks.
This work refers to the bi-dimensional petroleum system modeling of two published sections, used to illustrate the main characteristics of petroleum generation and accumulation in basins with thick salt layers.
The shallow water dip-oriented geologic section of Santos Basin (Figure 1) includes the platform, slope and shallow water within Merluza oilfield. In this section post-salt package is considerably thicker than the rift section and the salt layer is deformed with salt diapirs and welds. The deepwater section (Figure 2) represents the pre-salt in surrounding Tupi oil field. In this section the salt layer is thick and continuous, and the post-salt section have about the same thickness than the rift one.
Work development and procedures
The petroleum system modeling was realized with Petromod software, developed by IES company. The 2D-model construction started with the definition of the section’s geometry and its chrono-stratigraphy. Lithological composition and its lateral variation were attributed to the defined layers based on published data and on Petromod’s default parameters. Source rock characteristics (kerogen type, total organic carbon and hydrogen index) were accredited to the intervals supposed as rich in organic matter.
As for the boundary conditions, several simplifications were necessary due to the lack of information. The paleobathymetry was attributed according to theoretical passive margin evolution, the paleo-surface temperature was defined using Wygrala model (1989), and the paleo-basal heat flow was ascribed after one-dimensional studies made in several locations in order to finding the paleo-heat-flow that better corresponds to its geo-history, according to Royden & Keen (1980).
Concerning the salt geometric evolution, the salt thickness was supposed to be uniform along the section during its deposition. Its evolution was imposed do the model through Petromod’s salt movement tool until reaching actual geometry.
The results obtained for the shallow water section point out that the rift source rocks achieved the gas generation window in almost the entire section. By the other side, the Albian source rocks reached the gas generation window only in the structural lows associated with salt diapirism. Concerning its migration, the hydrocarbon generated in the rift section tends to flow toward the post-salt section through the salt welds.
The results for the deepwater section show maturity levels inferior than those intuitively supposed for such deep depths (6000-8000m). This happens due to the heat dissipation through the salt layer and also due to the significant water column (>2000m) that reduces the overburden. In this section the rift source rocks reached the gas generation only where the salt layer was thinner. It was also observed that the lack of salt welds restrained the fluid flow in the rift section, favoring the hydrocarbon migration, and accumulation, toward the rift structural highs
Finally, it is possible to identify two regions, which are distinct in migration and fluid type, due to differences in overburden and salt thickness: a) A zone with more gas was identified in shallow water (the Lagosta, Merluza and Mexilhão gasfields fit this profile); b) In deep-water with thick layers of salt the reduction of the thermal maturation increases the possibilities for oil accumulation. Certainly others aspects, as well as drainage areas and petrophysic characteristics must be taking into account for better accumulations predictions.
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PETROBRAS, 2007 – Webcast com o Presidente José Sérgio Gabrielle de Azevedo, o Diretor de Exploração e Produção Guilherme de Oliveira Estrella e o Diretor Financiero e de Relações com os investidotes Almir Guilherme Barbosa : Análise da área de TUPI - http://www2.petrobras.com.br/ri/port/ApresentacoesEventos/ConfTelefonicas/pdf/webcast_tupi_port.pdf
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AAPG Search and Discovery Article #90091©2009 AAPG Hedberg Research Conference, May 3-7, 2009 - Napa, California, U.S.A.