ABSTRACT More than 45 billion barrels of recoverable oil have been discovered in the Santos and Campos Basin pre-salt play to date. The prolific nature of this play relates to a supercharged Barremian-to-Aptian synrift petroleum system; a regionally extensive Aptian evaporite top seal; an extraordinary combination of high-storage capacity, high deliverability, undersaturated and overpressured lacustrine carbonate reservoirs; excellent crude oil quality (in areas that are CO 2 -poor); and large closure areas with access to multiple thermally mature, oil-prone source kitchens. A calibrated megaregional 3-D seismic data volume is a critical factor in the development and understanding of the Santos Basin pre-salt play. The data volume comprises more than 99,000 km 2 of mixed-vintage, mixed-azimuth 3-D seismic data, which were consistently pre-stack depth migrated (PSDM), reimaged using a calibrated anisotropic velocity model, and consistently datumed, amplitude balanced, and phase matched. The data have application to both pre-salt exploration and pre-salt field development. At basin scale, the data are used to define a 210,000 km 2 pre-salt play fairway and to understand controls on pre-salt hydrocarbon accumulation. At field and reservoir scales, inverted elastic seismic data attributes and data analytics are used to determine and predict reservoir and fluid properties, thereby enabling effective field appraisal and development.

ABSTRACT The Cabo Frio High corresponds to a regional basement arch located on the continental platform between the Santos and Campos basins. The distal margin of the Cabo Frio Outer High is characterized by gravity and magnetic anomalies suggesting an association with magmatic centers that affected the salt basin. Volcanic rocks are observed both on the proximal margin, where the Cabo Frio Volcanic Complex is marked by several magmatic episodes, and on the distal margin, where the Cabo Frio Outer High is marked by intrusive and extrusive igneous features affecting the pre-salt and post-salt sedimentary successions. The most important magmatic events in the area are related to (a) the pre-rift phase, with massive lava flows both onshore and offshore of the incipient continental margin; (b) the synrift phase, as indicated by several wells that drilled subaerial basaltic lava flows intercalated with lacustrine sediments; (c) the sag basin and transitional evaporitic post-rift phase, as indicated by sills and laccoliths overlain by salt and also by discordant igneous structures intruded into salt layers; and (d) the post-breakup phase, with major magmatic activity registered in the Upper Cretaceous and in the Paleogene. Volcanic events in the Cabo Frio region are a major factor in basin development and greatly impact the petroleum resources assessment, particularly when igneous rocks intrude into pre-salt source rocks and reservoirs. The geochemical data from producing fields and exploratory wells in the Cabo Frio region indicate that the main source rock system for the known accumulations are the upper Barremian calcareous black shales, deposited in brackish-to-saline water lacustrine environments from the Coqueiros Formation. In the continental shelf, the oil fields are characterized by intense biodegradation, which has deteriorated the oil quality. Several factors are important elements that control the prospectivity of the Cabo Frio region, such as thermal maturity of the source rocks, reservoir depth, seal effectiveness, magmatic events, and mixing of oils generated from different maturity pulses.

ABSTRACT Thirteen selected oil samples representing the largest oil fields in the Santos Basin were analyzed by quantitative diamondoid analysis (QDA). The results indicate that mixing of oils of different maturities from different petroleum kitchens is a very important process in the basin with exploration implications, especially in ultra-deep water. It was found that oil fields farthest from shore, in the deepest water such as Jupiter, Tupi, and Mero, are charged from two directions. They are charged from oil-window maturity kitchens nearer shore to the northwest of the fields, and they are also charged from higher maturity kitchens in ultra-deep water to the southeast of the fields. A correlation is present between high CO 2 concentrations in the gas cap and the amount of cracked oil component in each field. This would suggest that the cracked oil component and CO 2 share similar migration routes into the reservoir. The same deep faults described as migration routes for CO 2 in the Santos Basin may cut deeply buried source rocks accounting for the correlation. Because the highly cracked component recognized in oil fields farthest from shore is derived from deeper water kitchens to the southeast of the fields, it follows that the CO 2 is probably also migrating along deep faults from the same ultra-deep-water kitchens. From an exploration standpoint, on the positive side, our results confirm an excellent source rock in the ultra-deep water. However, there appears to be both a CO 2 and a thermal maturity risk, which must be addressed with regard to ultra-deep-water exploration in the Santos Basin. It could be that locating shallower kitchens in ultra-deep water may be important for mitigating both the maturity and CO 2 risks. In addition, our results show that fields located nearer to the shore, that is, to the northwest, such as Buzios, Sapinhoá, Sururu, and Lapa, contain no cracked oil component. It appears they are only sourced from the northwest from kitchens in the middle oil window. This suggests that the large fields in the southeast (deeper water), such as Tupi, Mero, and Jupiter, have blocked any migration into Buzios, Sapinhoá, Sururu, and Lapa from the ultra-deep-water kitchens to the southeast. From the data, it is observed that fields without the second ultra-deep-water charge based on diamondoids also tend to be low in CO 2 . One exception is there to the general trend of oil mixing occurring in the deepest water reservoirs, and that is at Carcará. Like the oils from Tupi, Mero, and Jupiter, the Carcará oil in this study is a mixture of oils from an oil-window kitchen and a much more mature, deeper kitchen. However, gravimetric data show a very deep trough next to the Carcará Field. It is presumed that it is from this trough that the high-maturity component in the oil is derived.

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.

ABSTRACT Santos Basin, offshore southeastern Brazilian margin, is unusual among the other offshore basins for its almost 700 km width and extensive submarine area covered by the São Paulo Plateau. Within the past 12 years, this basin has also become the site for some of the largest offshore oil fields ever discovered in deep water. Therefore, the nature of the crust under this basin and its role in the opening history of the South Atlantic have been intensely studied recently. Using gravity, magnetic, and seismic data combined with the depositional history of the basin has allowed us to map a short-lived spreading center in the southern Santos Basin. Various other authors have also interpreted this spreading center, but we believe the 3-D prestack depth migrated data presented here offer the most convincing case for this center published in the scientific literature. This early phase spreading center, named herein the aborted spreading axis (ASA), jumped to the east when the South American plate finally broke through and developed the present-day mid-oceanic ridge around 113 Ma. As a result of the earlier rupture, an important tectonic lineament developed comprising a several-hundred-km broad plateau separated from the Brazilian mainland by an associated trough. This feature was a major factor in defining the early water circulation and the depositional setting of the early Aptian pre-breakup sediments in the restricted Santos Basin. These deposits comprise the main reservoirs and source rocks of the giant pre-salt fields in Santos Basin. The high-standing volcanoes, lava deposits, and associated valleys could have guided early marine incursions into the basin to the north through waterways created by the tectonic trough. Those episodic events have probably controlled the coquina deposits and the heterogeneous lacustrine carbonates in a hypersaline gulf setting, to be overlain by confined evaporitic sediments. Widespread and thick evaporite deposition followed this previous stage along the Brazilian margin when a broader seawater invasion flooded the sinking continental margin.

ABSTRACT The Mero Field is one of the most recent large oil discoveries in the pre-salt play of Brazil, and its original oil in place (OOIP) is estimated at 11.94 bboe. It was discovered 10 years ago by the pioneer well 2-ANP-2A-RJS, drilled by Petrobras in partnership with the National Agency of Petroleum, Natural Gas and Biofuels (ANP). The Mero Field was part of the Libra Block, awarded in the first Brazilian bidding round under a production sharing agreement to Petrobras (operator), Shell, Total, CNOOC, CNPC, and PPSA. Geological and stratigraphic analysis based on public wells drilled in the Mero Field and high-quality 3-D seismic data mapping show wide variation in the facies distribution of microbial carbonate and coquina reservoirs. Thickness variation in coquinas and shale intercalation can be observed in well correlation and are associated with paleo basement highs. Igneous rocks are common in the reservoir. Petrophysical evaluation indicates significant variations in fluid composition between Mero Field and Libra Complex. Although the Mero Field is composed of good-quality oil (29º API), the Libra Complex consists mainly of gas condensate with high carbon dioxide (CO 2 ) content, demonstrating that these structures are disconnected. Petrophysical data also indicate that Mero Field is characterized by two compartments, with different oil–water contacts (OWCs). It can be explained by semipermeable barriers probably because of internal variation in facies distribution. This chapter aims to present a general overview of the geological and petrophysical characteristics of the Mero Field based on data that have just become public.

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 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 complex exploration and production of the South Atlantic Aptian pre-salt deposits are partly influenced by the significant heterogeneity of its sedimentary facies (characterized as a “mosaic” of facies). In large degassing modern rift systems, the source of the carbon dioxide (CO2) involved in the carbonate genesis process remains an uncertainty at the exploration scale, which raises the question of the importance of degassing in pre-salt paleolakes during primary carbonate formation. Can facies types be predicted on the basis on degassing? How does the external CO2 source (magmatic, organic, or atmospheric) organize the chemical landscape and influence carbonate production and facies variability? What other processes control the production of this “mosaic”? We address these questions by means of a thorough literature review, followed by a discussion of five continental carbonate analogs from various geodynamic provinces. The main pre-salt facies are illustrated, discussed, and grouped into six main depositional environments (from subaerial hydrothermal spring deposits to deep lacustrine settings). Taking a practical case study as an example, Lake Abbe (Djibouti Republic) exhibits some of the proxies listed in this discussion, helping us to grasp the complex lateral evolution of the depositional environments. Our holistic approach emphasizes that the “mosaic” of facies reflects various chemical landscapes regulated by external forcing such as climate and geodynamic settings. In conclusion, we emphasize that CO2 is a major control in carbonate deposition in magmatic-rich areas. Undeniably, the huge supply of CO2 in these areas is at the origin of the huge volume (reservoir size) continental carbonates that precipitated, especially in magma-rich rift areas of extensional geodynamic settings.

ABSTRACT This chapter compiled data from the latest history of exploration and investigated the key risks associated with the pre-salt petroleum system processes and elements in the Santos and Campos basins. The discussion goes through the analysis of rock-driven uncertainties, such as reservoir architecture, entrapment geometry, effectiveness of the cap rock, fluid-driven uncertainties represented by the distribution of oil and/or gas around the province, temperature, and hydrological conditions, as well as pressure transmission. The pre-salt reservoirs underwent a complex sedimentological history, and their stratigraphic interpretation is critical for mitigating the risks associated with reservoir connectivity and heterogeneity, as well as transmissibility. The main risks for entrapment are the presence of stratigraphic components of four-way or three-way controlled closures, their integrity affected by faults, and lateral seal presence. The main risks related to the source rocks and their maturation processes are the proportion of black and cracked oils present, the effectiveness of migration, and carbon dioxide (CO 2 ) contamination observed in some parts of the area. The risk assessment for migration pathways comprises the proper understanding of the northeast–southwest trend of rift extensional faults for upward migration, together with the northwest–southeast transverse faults, and how the fluid circulation through faults was connected to the carrier beds inside the rift section. The most significant region of the pre-salt-oil province is the central high of the Santos Basin, which has been charged by hydrocarbons that were generated in its landward (or internal) and seaward (or external) depocenters. Several external highs are there in the ultra-deep waters of the basin that have great exploration potential and have not yet been tested. These highs are surrounded by depocenters that have potential to hold rich source rocks. A final map of geological success probability summarizes the less risky sweet spots along the westernmost and central areas of the Santos Basin, with the higher success probability extending toward the eastern outboard of Santos and Campos basins.

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 The presence of natural seepage slicks and seeps composed of a mixture of cracked and uncracked lacustrine saline oils suggests the existence of active Barremian hydrocarbon source rock systems in the frontier deep and ultra-deep waters of the Santos Basin, Brazil. Acquisition, interpretation, and integration with meteoceanographic data of 24 Radarsat and 50 Sentinel images resulted in the identification of 78 oil slicks spread over the 700 km 2 study area from water depths that range from 400 to 3000 m. The identified seepage slicks resulted from the convergence of optimum tectonic, temporal persistence, and environmental scenarios, confirming that some pre-salt oils are effectively leaking from deep petroleum systems to the sea surface. When integrated with piston core, seismic, geochemical, and 3-D modeling data, it is clear that the seepage slicks are directly related to the salt tectonic processes and the presence of transtensional and listric fault zones, suggesting an origin closely associated with salt windows on the unconformity that defines the top of the sag sequence and seepage features on the seafloor. The geological framework of the Santos Basin’s ultra-deep waters is different from the proximal areas of the basin. In this sense, four geological domains are interpreted: The first domain occurs in shallow water in the platform region and can be called the seal risk zone; the second corresponds to the platform to salt-ramp region that occurs from shallow to continental slope waters and is a gas/condensate-prone zone; the third includes the salt-ramp to mini-basin domains, comprising the Upper Cretaceous reservoir turbidity fairway associated with the axis of the central rift system located from the deep to ultra-deep-water region; and the fourth is composed of mini basins and stratified layers of the evaporitic sequence in the ultra-deep waters where giant oil accumulations are present in the carbonate pre-salt reservoirs. These four structural domains determine different petroleum habitats that depend on salt thickness and the structural configuration of the rift sequence. The main hydrocarbon migration model for the identified seeps and oil slicks associated with the salt-weld or salt-wall domain of the Santos Basin’s ultra-deep waters is related to the existence of major fault zones. This type of feature is known as a transtensional fault zone that developed from the basement to the pre-salt reservoirs, with them sometimes functioning as the trigger for the halokinesis-derived listric normal faults that can displace the entire sedimentary wedge and can be observed on the seafloor. The presence of surface slicks is associated with oil seeps detected through piston cores in areas related to these types of faults, which confirms that such systems are the main oil conduits to charge and recharge pre-salt and post-salt oil and gas accumulations. Therefore, this hydrocarbon migration model should be well understood and considered for the exploration for oil and gas, principally post-salt targets. In summary, the integration of seepage slicks, seismic data, and geochemical analyses of reservoir oils and oil seeps can improve the petroleum system comprehension of frontier areas and, in the case of this chapter, open up a huge exploration frontier for the deep and ultra-deep-water outboard area of the Santos Basin.

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 The Pre-Salt Polygon was established in 2010, encompassing an area of about 150,000 km 2 offshore southeast Brazil. It covers parts of both the Campos and Santos basins and contains giant and supergiant discoveries found in mid-to-late Aptian reservoirs. Three fiscal regimes coexist within this area: concession, production sharing, and onerous transfer of rights. Pré-Sal Petróleo S.A. (PPSA) is a state-owned company created in 2013 and represents the Brazilian government’s interests within the Pre-Salt Polygon. It has three main objectives: (1) to manage production sharing agreements, (2) to represent the Brazilian government in unitization agreements involving open acreage (noncontracted and strategic areas), and (3) to trade the Brazilian government’s share of oil and natural gas. Unitization is a common feature within the Pre-Salt Polygon, and PPSA is a key player in the process with a portfolio of seven unitization agreements already executed, two under negotiation, and 11 others in early stages of discussion with some of the world’s most important oil companies. This chapter presents a brief description of the Brazilian unitization process with open acreage within the Pre-Salt Polygon, highlighting its peculiarities and challenges, and the important role played by PPSA.

ABSTRACT The offshore Santos and Campos basins of the southeastern Brazilian margin are currently the focus of extensive hydrocarbon exploration following some of the largest global oil discoveries made within the so-called pre-salt section. It is widely accepted that these basins initially developed during the Neocomian breakup of Gondwana and separation of Africa from South America. However, significant debate exists concerning the regional tectonic significance and timing of Early Cretaceous tholeiitic basalts drilled across the Pelotas, Santos, and Campos basins; the distribution of continental crust; distribution and temporal development of thickened oceanic crust; and basement influence on basin development and timing. We have reviewed earlier published tectonic analyzes in addition to a comprehensive integration of both old and new seismic reflection and refraction data, gravity, and well calibrations to place new constraints on the tectonic evolution of the Santos and Campos basins. Upper and lower crustal refraction velocities and densities across the São Paulo Plateau were once considered to indicate continental basement. Our reinterpretation shows they are equally consistent with thickened oceanic crust (which we term magmatic crust ). We define tectonic domains within the Santos and Campos basins and show that crustal thicknesses across the Outer Basin High and Jupiter Terrace range from 15 to 20 km, whereas the Deep Basin and standard (Penrose) oceanic crust to the east of the Outer Basin High show crustal thicknesses of 1–3 km and 6–8 km, respectively. We interpret the along- and across-strike variations in crustal thickness variations to be a function of the proximity to the Tristan da Cunha plume and its magma budget combined with structural reworking of this thickened oceanic crust by superimposed late-stage extensional faulting. Seismic reflection profiles from the Pelotas, Santos, and Campos basins show the existence of relatively thick oceanic crust characterized by SDR (seaward dipping reflector) geometries that progressively decrease in age to the east and onlap earlier syn-tectonic volcanic flows and/or extended continental basement that form part of a “necking zone.” Analyzing SDRs from the northern Jacuipe Basin demonstrates that they are upper crustal counterparts to Layer 2 of oceanic crust, whereas the lower crust is equivalent to Layer 3 of oceanic crust even exhibiting a crisscross reflectivity pattern possibly related to shear within magma chambers. In particular, we suggest that SDRs represent subaerial seafloor spreading that laterally merges structurally and petrologically into Layer 2 of Penrose oceanic crust. In this interpretation, the first SDR flows onto thinned continental crust are critical because the causative eruptive center defines the location of continental breakup, the timing of breakup, and the initiation of subaerial magmatic spreading. Based on the identification and distribution of SDRs in the Pelotas, Santos, and Campos basins and seismic mapping calibrated with exploration well data, we propose a general template for the structural and stratigraphic development of southeast Brazil that comprises (1) a relatively thick continental crust in the extreme western, proximal part of the margin, (2) deposition of pre-rift and synrift volcanic flows (equivalent to the Paraná basalts) on extended continental crust, (3) a continental crustal necking zone, (4) an exhumation point (i.e., the complete necking of the continental crust) after which post-breakup, magmatic SDR crust onlaps earlier syn-tectonic basement and volcanics, and (5) for the Campos Basin, a second necking zone involving the extensional deformation of magmatic crust. Continental extension is assumed to span Berriasian–late Valanginian (134–145 Ma), consistent with rift basins along the entire eastern Brazilian margin. Lithospheric breakup is considered to be late Valanginian–early Hauterivian (132–134 Ma), triggered by the rapid emplacement of the Paraná Large Igneous Province. As such, deposition east of the continental necking zones is post-breakup (Arutu-, Buracica-, Jiquia-, and Alagoas-aged sediments) on new “real estate” crust. For the Pelotas and southern Santos basins, subaerial magmatic crust was emplaced east of the continental necking zone with the generation of SDRs that progressively decrease in age to the east. In the northern Santos Basin, post-breakup magmatic crust is emplaced east of the continental necking zone, but SDR geometries are not observed. For the Campos Basin, subaerial seafloor spreading forms oceanic crust east of the continental necking zone, and later, seaward of the magmatic necking zone. This second phase of spreading is characterized by additional SDRs. A time-transgressive distribution of magmatic basement age is implied, with older crust emplaced along the continental necking zone and younger crust to the east; depocenter migration is evidenced by the shift in the easterly limit of Buracia-, Jiquía-, and Alagoas-aged sedimentation. In places, ridge jumps may be superimposed (e.g., Abimael Ridge), which locally reverses this age progression. Although several authors have previously suggested that SDRs may represent subaerial seafloor spreading, this is the first analysis to provide an integrated and coherent, self-consistent tectonic analysis of SDRs that defines the location and timing of continental breakup, the initiation of seafloor spreading, the transition to Penrose oceanic crust, and the timing of margin flooding.

ABSTRACT Although dating back thousands of years, including a brief quote in the Bible, petroleum began its use for industrial purposes only in the last century. In Brazil, the implementation of integrated activities contributed to the progressive development of the hydrocarbon sector based on geological research, predominantly conducted through the use of surface geology analysis, gravimetric and magnetometry data, and drilling of poorly defined prospects. After consolidating some small accumulation discoveries along with new demand growth and the advent of new indirect investigation technologies, unforeseen economic perspectives opened to Brazil and a national company was established to be responsible for managing and running the oil exploration and production activities. Although strengthened by the years of research, possession and control of the oil business monopoly, high investments, and accumulated technical experiences, Petrobras was no longer capable of handling the oil source potential that the Brazilian sedimentary basins could deliver. Therefore, envisioning production beyond the possibilities of only one controlling company, despite being large and technically capable, a law was enacted in 1997, the Petroleum Law, which established the National Agency of Petroleum, Natural Gas and Biofuels (ANP) and opened the Brazilian oil business to foreign capital investments ( ANP, 1988 ). This law unfolded an exploration race in the sector that culminated in the greatest hydrocarbon discoveries ever made in Brazil, the Lula oil field. The new oil business legal framework and the country’s attractive economy brought investments to the Brazilian sedimentary basins, resulting in the collection of six petabytes of technical data and almost 380,000 boxes, of cutting samples and conventional cores, all under ANP custody. By encouraging the use of these data, as well as promoting the acquisition and production of new information from the Brazilian sedimentary basins, the country seeks to reheat the basic research market, implementing policies and investments to enhance exploration and production activities, new data acquisition and reprocessing of existing data libraries, optimizing the cost of technical data access, improving service delivery, and the relationship with regulated agents.

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 Oil and gas exploration started in the Santos Basin of Brazil during the 1970s. After almost 25 years of drilling 102 dry and subcommercial exploration wells, the exploration campaigns came to a near halt. With the opening of the Brazilian petroleum market in 1997, the National Agency of Petroleum, Natural Gas and Biofuels (ANP) was founded, and exploration in the basin resumed. The years between 1999 and 2004 saw an increase in the exploration effort of major oil companies, including ExxonMobil, Petrobras, Shell, British Gas, Galp, and Eni, among others. The new drilling campaign added 65 exploration wells in only six years. However, the oil discovery success ratio was below 5%. The lessons learned were significant, showing that the search for Tertiary and Upper Cretaceous turbidites of the Santos Basin would not be as successful as in the Campos Basin. Furthermore, the turbidite reservoir paradigm hindered the adoption of new and more productive paradigms—in particular, the directive to “Go Deep.” With the advancement of molecular geochemistry and deep-water seismic and 3-D petroleum system modeling technology, the incredible journey from near failure changed the fate of the Santos Basin to a huge success. In 2006, the Tupi oil field which targeted a new pre-salt play concept, encountered good-quality oil sourced by lacustrine calcareous black shales of the rift-upper Barremian Itapema Formation source rock system that accumulated in more than 400 m, thick-net-pay microbialite reservoir in the sag–mid-to-late Aptian system. In the following years, several giant oil fields, utilizing the same play concept, were discovered in the basin, including Sapinhoa, Búzios, and Mero. These fields showed similar reservoir performance to the Tupi Field, which had more than 30 wells producing more than 25,000 bbl/day, and some of them producing up to 45,000 bbl/day (e.g., 1-BRSA-1305-RJS). In December 2019, the Santos Basin pre-salt system contained more recoverable reserves than all other Brazilian sedimentary basins combined. This chapter describes how the petroleum system approach using rock and oil samples from the Santos Basin supports the dismantling of previous paradigms and the creation of new ones that resulted in the immense success of Santos Basin exploration. This work is based on the application of the petroleum system concept from source to trap, integrated with 3-D modeling and recent results of oil and gas production data from the largest oil fields found to date in the Santos Basin.

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.