ABSTRACT Potential reservoir facies represented by lacustrine shoreline grainstones and rudstones are typically relatively thin compared to those from marine basins because of limited fetch and reduced wave action producing a shallow wave base. This is especially the case in low-gradient endorheic lakes in which rapid lake-level oscillations preclude the development of a stable shoreline. However, the closed lake deposits of the Barra Velha Formation locally have thick (decameter-scale) continuous packages of grainstones and rudstones comprising fragments of crystal shrubs, spherulites, intraclasts, and, in some cases, peloids and volcanic fragments. Grainstones and rudstones of this type occur on the escarpment and dip slopes of tilted fault blocks along which a marked thinning of the Barra Velha Formation is evident. They mainly consist of sharp-based, decimeter-to-meter–scale, fining-upward packages with well-sorted and well-rounded grains, planar/low-angle lamination and, less commonly, cross-lamination and planar cross-bedding. Those that occur on dip slopes are generally finer than those associated with escarpment slopes, the latter also being texturally less mature. At the formation scale, grainstone-dominated successions show radial depositional dip azimuth patterns orientated normal to paleoslope. The grainstones are interpreted as wave-dominated fan-delta shoreline deposits. Although much effort has focused on the origin of the in situ components of the Barra Velha Formation, such as crystal shrub facies, detrital deposits of the type documented here constitute significant potential targets.

ABSTRACT A favorable combination of multiple geological elements in the Lower Cretaceous (Barremian to Aptian), such as organic-rich source rock, porous reservoirs, synrift structures, and very effective evaporite seal, was responsible for forming giant oil accumulations in the pre-salt section of the Santos Basin. The Aptian pre-salt reservoirs, in the Barra Velha Formation (BVF), purpose of this work, consist of layers, which are centimeter-to-decimeter thick of lacustrine carbonates. The sedimentary facies are the products of chemical (e.g., crystal shrubs and spherulites), microbial, and hydrothermal precipitation that commonly appear mixed with reworked grains. Each facies, with greater or lesser presence, depends on the structural framework in which it was deposited. The knowledge of the genesis and geologic history of BVF is essential to understand the formation of the largest deep-water oil reserves in Brazil. The BVF was divided, from base to top, into three cycles: (1) upper-rift, (2) lower-sag, and (3) upper-sag. These cycles make up a second order sequence with flooding-shallowing upward cycles. The association of calcitic spherulites with hydrated talc and stevensite indicates precipitation in an evaporitic-alkaline lake, rich in magnesium and calcium, oversaturated in calcite and with a salinity greater than 3500 ppm but less than 35,000 ppm. The complexity of the facies arrangement in the lake reflects deposition in a proximal environment influenced by evaporation; hydrothermal activity, with complex water chemistry; oscillating groundwater; and frequent lake-level fluctuations. The initial rifting of the Santos Basin was accompanied by extensive volcanic activity that lasted throughout the whole rifting phase, up to the upper-sag phase, influencing both the geological evolution and paleophysiography as well as the chemical characteristics of the lake system.

Abstract: The lacustrine carbonate reservoirs of the South Atlantic host significant accumulations of chemically reactive and Al-free Mg-silicate minerals (e.g. stevensite, kerolite and talc). Petrographic data from units such as the Cretaceous Barra Velha Formation in the Santos Basin suggest that Mg-silicate minerals strongly influenced, and perhaps created, much of the observed secondary porosity. The diagenetic interactions between reactive Mg-silicate minerals and carbonate sediments are, however, poorly known. Here we develop a conceptual model for the origin of secondary porosity in the Barra Velha Formation guided by considerations of the chemistry that triggers Mg-silicate crystallization, as well as the geochemical and mineralogical factors that act as prerequisites for rapid Mg-silicate dissolution during early and late diagenesis. We conclude that sub-littoral zones of volcanically influenced rift lakes would have acted as the locus for widespread Mg-silicate accumulation and preservation. Organic-rich profundal sediments, however, would be especially prone to Mg-silicate dissolution and secondary porosity development. Here, organic matter diagenesis (especially methanogenesis) plays a major role in modifying the dissolved inorganic carbon budget and the pH of sediment porewaters, which preferentially destabilizes and then dissolves Mg-silicates. Together, the sedimentological, stratigraphic and geochemical predictions of the model explain many enigmatic features of the Barra Velha Formation, providing a novel framework for understanding how Mg-silicate–carbonate interactions might generate secondary porosity more broadly in other lacustrine carbonate reservoirs across the South Atlantic.

ABSTRACT Búzios, discovered in 2010, is a supergiant pre-salt field, located in the Santos Basin. The main reservoirs are lacustrine carbonates, deposited from the Barremian until the Aptian. Preliminary estimates indicate a volume of oil in place (OIP) on the order of 29,900 MMBOE, thereby ranking it as the largest of the pre-salt fields. The understanding of pre-salt reservoirs continues to be a challenge because of complex facies distributions and tectono-stratigraphy. This study focuses on describing the tectono-stratigraphic framework of Búzios Field, using criteria from 3-D seismic, well log, and core data. Three-dimensional seismic interpretation reveals the Búzios’ rift configuration as a series of horst, graben, and half-graben structures, which are highly faulted (N30W–N30E) because of a complex transfer zone interpreted in the area. Based on seismic interpretation, the rift section was subdivided into a lower and upper rift section. The lower rift section was strongly affected by normal faults, whereas the upper rift was exposed to a less expressive faulting process and has a thinner sedimentary wedge. The upper section corresponds to a commonly observed coquina interval (the Itapema Formation), which serves as the lower pre-salt reservoir in the Búzios Field. Lastly, prior to salt deposition, the post-rift mega-sequence (sag section) is comprised of the Barra Velha Formation, which is composed of biotic and abiotic carbonate reservoirs in a complex structural setting. Based on core analysis from the 3-BRSA-944A-RJS well, the most common facies in the Itapema Formation reservoirs are rudstone and grainstone, composed of bivalve shells, with an average porosity and permeability of 12.5% and 88.7 md, respectively. The Barra Velha Formation reservoirs consist of four main carbonate facies: spherulites (most common), crystal shrub, carbonate laminates, and rare stromatolites, which display an average porosity and permeability of 9.4% and 122.6 md, respectively.

ABSTRACT The aggressive E&P campaigns in the pre-salt section of the Santos Basin, in the past decade, have imposed important challenges for characterizing the elements and processes of the basin’s petroleum systems. Among them, one of the most important is the reservoir system. Although the pre-salt supergiant hydrocarbon discoveries have shown very high-quality carbonate reservoirs, with soaring well productivities, there are many challenges for reservoir management and field development, particularly related to the occurrence of naturally fractured reservoirs and fluid distribution with high carbon dioxide (CO 2 ) content in many accumulations. Therefore, reservoir heterogeneities and fluid distribution in the producing zones need to be properly assessed to mitigate exploration and development risks. The integration of geological, petrophysical, and pressure, volume, temperature (PVT) data of 36 wells, representative of the main oils fields of the pre-salt section of Santos Basin, including Tupi, Sapinhoá, South Tupi, Buzios, and Mero fields, among others, showed that two reservoir units are responsible for almost 99% of all pre-salt accumulation in the basin: (1) the lacustrine microbialite carbonates deposited in the sag section during the Aptian and (2) the coquinas carbonates deposited in the rift section during the upper Barremian. Petrophysical analysis, using cores, sidewall core samples, and logs, has shown an anomalous behavior of permo-porous properties (relatively low porosities with high absolute permeabilities), suggesting the existence of a network of microfractures, fractures, vugs, and active faults in the pre-salt sedimentary structures. As a consequence of the fractured and interconnected reservoir network, hydraulic continuity has been observed in the gross-pay reservoir intervals of the microbialite carbonates of the Barra Velha Formation and coquinas of the Itapema Formation. The PVT analysis showed the presence of very high CO 2 content, predominantly in the reservoirs of the Barra Velha Formation, with the CO 2 behaving as a supercritical fluid, yielding very high gas gravity. The key elements of reservoir characterization and fluid distribution that can affect reservoir hydraulic modeling and recovery efficiency will be discussed in this chapter. The objective is to provide a better understanding of the relationship between reservoir quality and fractures and CO 2 effects, to use properly predictive reservoir models.

ABSTRACT This study is part of a fully integrated petroleum system assessment of new frontiers in the deep and ultra-deep waters of the Santos Basin. It includes geochemistry from more than 50 selected wells containing pre-salt oils and potential source rock systems representing the entire pre-salt sequence drilled to date. The pre-salt hydrocarbon province located in the offshore Santos Basin, southern Brazil, has attracted the attention of exploration companies with the discovery of the Tupi oil field in 2006. Since then, many discoveries, including Mero, Buzios, Sapinhoá, Atapu, Itapu, and others, have made this basin one of the most prolific oil provinces in the world. Because the number of wells that have penetrated the deeper Barremian sequences in the ultra-deep water in the Santos Basin are scarce, and data publications are virtually nonexistent, the exploration of the pre-salt hydrocarbon province has been dominated, by introducing new seismic acquisition technology, enhancing seismic quality through reprocessing, and deploying conceptual 3-D basin models. However, little direct effort has been devoted to understanding petroleum system elements and processes in the area. In this study, a set of rock samples representing sediments of the mid-to-late Aptian Barra Velha, upper Barremian Itapema, and lower Barremian Piçarras formations from the pre-salt section of the Santos Basin was investigated. The organic-rich rocks were collected for extraction and correlation with oil samples gathered from pre-salt oil fields over a wide area of the pre-salt province. Results of the integration of the geochemical with geological and geophysical data indicate that the most prolific source rock system is the upper Barremian Itapema Formation deposited in an euxinic lacustrine brackish-to-saline environment. This unit appears to have sourced almost all the hydrocarbons that accumulated in the pre-salt lacustrine shrublike texture, reworked and spherulitic limestone and coquina reservoirs in the Santos Basin. In contrast, the lower Barremian Piçarras Formation and the mid-to-late Aptian Barra Velha Formation appear to have minor importance. Although the upper Barremian Itapema Formation has not been encountered by the drill bit in outboard areas of the basin, its presence has been suggested by the existence of partially cracked oils sourced from deep depositional pods in fields such as Jupiter, Tupi, and Mero. The source to trap migration route for these cracked oils suggests a long-distance pathway from very deep source depocenters, located at the eastern part of the Tupi Outer High trend in the distal part of the ultra-deep-water Santos Basin, through southeast to northwest transform faults to the reservoirs. The identification of these very deep depocenters using a structural map of the basement creates an entirely new way of looking at oil generation, migration, fluid heterogeneities, and accumulations within the Santos Basin. The identification of the location of depo-pods of generation of the Barremian mega-sequence outside the already explored regions of the Santos Basin drastically lowers the exploration risk in the outboard unexplored areas of the basin.

ABSTRACT Advanced geochemical technologies (AGT) were applied to 12 oils from pre-salt formations (pre-salt oils) from the Santos Basin and compared to four post-salt reservoired oils. Three primary methods were used to categorize the oils: (1) diamondoid methods, that is, quantitative diamondoid analysis (QDA) and quantitative extended diamondoid analysis (QEDA); (2) biomarker analyses using gas chromatography–mass spectrometry–mass spectrometry (GCMSMS); and (3) compound specific isotope analysis of alkanes and hopanes plus tricyclic terpanes (CSIA-A and CSIA-Bh/CSIA-TT, respectively). Each method either provided new information or reinforced interpretations derived from other methods diminishing uncertainties in the overall interpretations. GCMSMS data suggested the preliminary source relationships for charges of early-to-middle oil-window maturity based on biomarker correlations. Those suggestions from GCMSMS data were either bolstered or more finely discriminated by the CSIA data. Data from diamondoid analyses gave insight into components that could not be described by biomarkers and the CSIA methods related to post-mature oil, oil cracking, and oil mixtures. QDA showed post-mature components for some oil samples, indicative of oil-window plus post-oil-window mixtures. QEDA showed that, in addition to one predominant lacustrine source, other lacustrine sources contributed to some of the pre-salt oil accumulations. Oils taken from pre-salt reservoirs in the study include samples from the following fields: Bem-Te-Vi, Sapinhoá, Jupiter, Mero, Buzios, Tingua, Tupi, Sururu, and Carcará. Biomarker and CSIA data confirm correlative relationships among nine pre-salt oils with source rocks deposited in brackish-to-saline water lacustrine depositional environments, putatively from the upper Barremian (Itapema Formation). Among those, QDA shows the samples from Tupi (three samples), Mero (two samples), and Jupiter to be of mixed maturity, including some normal oil-window plus post-mature cracked oil. Oils from Sapinhoá, Buzios, and Sururu fields show only the normal oil-window maturity. Oils from Bem-Te-Vi and Carcará correlate to a different source proposed to be the mid-to-late Aptian-sag lacustrine hypersaline system (Barra Velha Formation), of which the Carcará oil shows a major cracked component, whereas the Bem-Te-Vi oil does not. The oil from Tingua Field appears to be the lone representative of a fresh-to-brackish water system, putatively, the lower Barremian rift system (Piçarras Formation). Four oils from post-salt reservoirs recovered from Albian carbonates from the Guaruja Formation in the southern Santos Basin show contrasting biomarker, CSIA, and diamondoid (QEDA) patterns distinguishing them from any of the pre-salt oils. Taxon-specific biomarker parameters based on GCMSMS analysis are definitive for making those distinctions, including, for example, 24- n -propylcholestanes (marine algal steranes), dinosteranes concentrations (dinoflagellate steranes), and other A-ring methyl steranes and 24-norcholestanes (putatively diatom related). One of the highly cracked post-salt oils is an example of oil co-sourcing, showing features of both lacustrine and marine components in the biomarker and diamondoid parameters.

ABSTRACT In this chapter we present the results of a 3-D petroleum systems modeling (PSM) project of the deep-water pre-salt region in the Santos Basin. Model building has been based on a large well data set. Simulations have been calibrated against temperature, porosity, and pressure and were compared to data of petroleum properties. The input assumptions are documented in detail, with special focus on two crucial uncertainties in this petroleum province: (1) salt restoration and (2) modeling of the heat flow history, including discussion of technical aspects and workflows. Two different scenarios of the salt restoration, assuming differing amounts of mobile salt over time, were tested. The two scenarios are compared with respect to their impact on thermal modeling results. The heat flow history was modeled based on an application of crustal modeling. Results corroborate the recently published hypothesis that heat flow decline during the early drift phase of the Santos Basin was retarded because of extensive magmatic underplating. The thermal history modeling results reveal that temperatures within the pre-salt sequence have remained largely stagnant since mid-Cretaceous times until present day. Maximum temperatures were accordingly reached in mid-to-Late Cretaceous times in the majority of the area. This is because of the fact that very low burial rates have prevailed since mid-Cretaceous times in this basin, which resulted from its distal setting that could not compensate for the gradual heat flow decline during the drift phase. The temperature history of the pre-salt sequence is additionally affected by the cooling effect of the salt layer, at least on a local scale. The two different scenarios of the salt restoration demonstrate the impact of this effect and show its relevance when assessing maturity via modeling of salt basins. Only the deepest source rock system of the lower Barremian Piçarras Formation, informally called the “talc-stevensite,” shows transformation ratios above 90% (corresponding to the “gas window”). The second and most important source rock system, belonging to the Itapema Formation, informally called the “coquinas” source rock, modeled in the studied area, shows transformation ratios of up to 50%, corresponding to the “oil window.” The third and shallowest source rock system in the model, belonging to the sag mid-to-late Aptian sequence called Barra Velha Formation, is early mature to immature and is not considered to be a significant factor in the oil system of the studied area. The modeled timing of transformation, expulsion, migration, and accumulation in this petroleum system (informally summarized as “charge”) suggests that the main charge pulses from the pre-salt source rock systems took place between mid-Cretaceous and mid-Tertiary times, whereas transformation may have locally been ongoing until present day. Simulations of petroleum migration are not discussed in detail here because of the scope of this study and constraints regarding the volume of this chapter. The preliminary migration model successfully reproduces most known petroleum accumulations in the area, and yielded fair to good fits to measured GOR, and API gravity data. However, the modeled accumulated volumes of several fields, including the Tupi Field, are too small. This suggests that these accumulations possibly received charge from additional pods of source rock located to the south and east, that is, outside of the modeled area.