INFLUENCE OF STRUCTURAL AND THERMAL EVOLUTION ON PETROLEUM SYSTEM IN THE CABO FRIO HIGH AREA AND SURROUND AREAS, SANTOS BASIN

Introduction

The Cabo Frio High (CFH) is a structural feature between the Santos and Campos basins. The uplift was promoted by arching and great magmatic activity including intrusive and extrusive rocks in many stratigraphic levels (Mohriak et al., 2021; Brandão et al., 2024). Recent discovery of oil in carbonates of the Barra Velha Formation in the Cabo Frio Central High block brought a new paradigm for petroleum exploration in the pre-salt of that area. To keep the exploratory success, it is necessary to update the knowledge about the petroleum system Itapema-Barra Velha (!) with refinements on the understanding of structural and thermal history. The main objective of this study the structural configuration and magmatic influencing on the petroleum quality in the area.

Experimental

Seismic interpretation of the horizons of rift and drift formations including the magmatism features drive the geological characterization of the petroleum system. Results bulk (⁰API) and of organic geochemistry (liquid and gas chromatography, carbon and hydrogen isotopic analyses, saturated biomarkers) were gathered from the archives of the National Agency of Petroleum (ANP) and literature. Optical and scanning electron microscopy analyses were performed with mapping of chemical elements in thin sections of limestones from the pre-salt formations. Optical microscopy was performed using a Leica DM2700 P microscope and SEM-EDS using an JEOL JSM 7100 F equipment.

Results and Discussion

Upper Cretaceous and Lower Cenozoic magmatism play an important role in the maturation, migration, and trap formation of petroleum system in the CFH and surrounding areas. Large igneous bodies in the pre salt source rock overcharge thermal contribution in the source rock influenced the organic matter maturation (Figure 1A). Magmatic Intrusive and extrusive events influence the tectonic scenario by earthquake igneous-tectonic uplift related generating turbidites to form reservoir and traps (Figure 1A, 1B). Hydrothermal feature magmatic related inject fluids and gas in the discordance reservoir related (Figure 1B). The tectono-magmatic activities influence the migration by breaching the salt layer and fracture zone formation, allowing the oil and water infiltration and percolation (Figure 1A). The magma bodies weight influences the gravitational tectonism of the salt layers dislocation locally uplifting the overburden and formation of faults which served as pathway for water and oil (Figure 1A, 1B).

Oils found in the CFH area are derived from lacustrine source rocks composed by dark shales, calcareous deposited in brackish to saline lakes during the Buracica (local stage) equivalent to the late Barremian. Diagnostic geochemical characteristics are values of δ¹³C_saturates ≈ -26 ‰, high hopane/sterane ratios >> 1, and Tetracyclic Poly Prenoids /C₂₇Diasteranes > 1 (Mello et al., 1988; Mohriak et al., 2021; Freitas et al., 2022). Oils accumulated in the pre-salt reservoirs have API degrees mostly between 25 and 27, and the entire range of saturated compounds expected in pristine oils is present in GC trace, with virtually nil or very low content of 25-norhopane (not shown here). However, there are oils having abundant n-alkanes and 25-norhopane (Figure 2A). Demethylated hopane (25-norhopane) is an indicative of relatively severe oil biodegradation with the destruction of n-alkanes and most isoalkanes (Peters et al., 2004).  Such apparent paradox can be reconcile with, at least, two oil pulses (“refreshing”). The first oil pulse was accumulated and biodegraded, the second migration of pristine oil mixed with the already biodegraded oil (Lópes et al., 2015). C₂₉ sterane biomarkers αββ/(αββ+ααα) of non biodegradated oil indicate oil generation at peak of “oil window” (Peters et al., 2004). Oils reservoired in the post-salt are extensively biodegraded as shown by GC trace with no n-alkanes, presence of some iso- and cycloalkanes, the characteristic “hump” UCM (unresolved complex mixture), and significant abundance of 25-norhopane, and their degrees API commonly are ≈ 13, (Figure 2b). Not far from the study area light oils, condensate and gas accumulations reservoirs, e.g., Seat, Pão de Açúcar e Gávea, generated under higher thermal maturity, suggesting that in addition of the thermal flux expected by the stretching of the crust during the formation of pull apart basin, an extra thermal event added extra heat to the system. Such process is suggested by diagenetic features found in thin sections of reservoir rocks of the Santos and Campos basins (Jahnert, 1989; Brito et al., 2024) and by “magma emplacement” in deep crustal levels (Brandão et al., 2024). Alterations in the geothermal gradient has already been found in the offshore marginal basins in West Africa and counterparts of southeastern offshore Brazilian basins (Baudino et al., 2018; Hedley et al., 2022). In the limestones of the Itapema and Barra Velha formations in well 1-BRSA-905-RJS in the CFH area, the presence of primary CO₂ fluid inclusions in syngenetic (shrub calcite), eodiagenetic (neomorph calcite, calcite and dolomite in pore) and mesodiagenetic (quartz in pore) minerals indicates that CO₂ emplacement occurred during these different stages (Figure 3). In the limestones of the Barra Velha Formation, CO₂ was recovered with a content of 40% and the R/Ra ratio of 3 indicates that the CO₂ originated in the mantle (Santos Neto et al., 2012). The mantle origin, the microscopy and fluid inclusions data and the knowledge of the existing magmatic cycles (Mohriak et al., 2021; Gordon et al., 2023; Brandão et al., 2024) point to the influence of the heat of the Hauterivian-Aptian and post-Aptian magmatism in heating the water in which the syngenetic/eodiagenetic and mesodiagenetic minerals were precipitated, respectively.

Conclusions

Intense structural activity in the CFH area generated great number of faults, the natural migration avenues for hydrocarbons and other fluids. Equally, faults can open windows in the evaporate section through halokinesis. With breached seal, hydrocarbons can reach shallower (post-salt) reservoirs subject more intense water influx and lower reservoir temperatures, consequently more subject to biodegradation. The intense magmatism in the region may have increased the geothermal gradient and/or adding extra heat directly from intrusive bodies. Such conditions may change the expected thermal and maturation histories, influencing the petroleum composition. Fluid inclusions and mineral assembly in the pre-salt rocks have shown evidence of hydrothermal activity associated with Hauterivian-Aptian and post-Aptian magmatism in the CFH area. This integrated study highlights the importance of the understanding of the structural evolution and thermal history for prediction of hydrocarbon type. In the studied area faults, reaching shallower parts of the basin, allowed the migration of hydrocarbons to traps with favorable conditions to biodegradation. Hydrocarbons trapped in pre-salt reservoirs can have a wide range of thermal maturities varying from black to light oils, condensate and gas. More investigations are necessary to improve the knowledge about the influence of different kinds of magmatism on thermal history of the CFH area.