Abstract: The Sergi Formation, a Jurassic pre-rift sequence composed mostly of fluvial sandstones, is one of the major hydrocarbon reservoirs of the Recôncavo Basin in northeastern Brazil. Interstitial clays are important components of sandstones and exert significant control on reservoir properties, including permeability, irreducible water saturation and residual-oil saturation. These clays can be grouped into three types: (1) depositional clays; (2) mechanically infiltrated (MI) clays; and (3) authigenic (neoformed) clays. Each type shows a characteristic petrographic aspect that permits recognition and quantification using thin sections. Depositional clays were incorporated into the rocks as mud intraclasts resulting from reworking of overbank fines by fluvial processes. Early mechanical compaction crushed the mud clasts among more rigid grains, forming a compaction matrix. Mechanically infiltrated (MI) clays occur chiefly as coatings of tangentially accreted particles (cutans) or, locally, as complete pore fills. MI clays appear to be concentrated within the upper part of the formation. These clays can modify the pore geometry of sandstones. Shrinkage porosity, developed by diagenetic transformation of clays, is the dominant porosity type in the upper part of the Sergi Formation. Authigenic clays are kaolinite and chlorite. Kaolinite occurs as pore fills in large secondary pores and, where present in large amounts, may generate high microporosity in the reservoirs. Chlorite occurs as pore linings and, locally, as pore fills. In the reservoirs, chlorite causes permeability reduction and is related to the presence of low resistivity in water-free, oil-producing zones. These authigenic clays show a distinct distribution within the basin. Kaolinite dominates in the western portion, where Sergi reservoirs are found at shallow depths (above 1,000 m), whereas chlorite is dominant in the eastern portion, where Sergi reservoirs are found at greater depths. The distribution of these clay minerals is the result of differences in burial/temperature histories, which are still reflected by present depths.

Abstract The Camamu–Almada Basin, located in northeastern Brazil, is part of the rift system that formed during the Early Cretaceous break-up of South America and Africa. Previous studies have characterized the occurrence of a single petroleum system in this basin, the Morro do Barro(!), which encompasses a Neocomian synrift lacustrine source rock and turbiditic reservoirs of the same age. 1-D and 2-D tectonic, thermal, and geochemical modeling was applied to better understand the evolutionary history of the petroleum system, as well as to provide a basis for better assessment of the exploration risk and petroleum potential of the Camamu–Alamada Basin. The hydrocarbon generation modeling indicates that most of the oil was generated by the end of the rift phase (Barremian–Aptian). Present kerogen transformation ratios range from 10–20% nearby the continent (west) to 100% in the deeper areas (east). Fluid-flow modeling showed that the presence of a thick section of low-permeability shales above the source rocks favored the downward migration of petroleum to the sandstones of the Sergi Formation. Petroleum migration through normal faults, which juxtaposed source rocks of the Morro do Barro Formation to sandstones of the Sergi Formation, also played a major role in the filling of these carrier beds. Secondary migration extended considerably into the postrift phase.

Abstract The Recôncavo basin, on the Atlantic Coast near the city of Salvador, has an area of about 10,000 km 2 and is the principal petroleum province of Brazil. Since 1939, approximately 255 wildcats have been drilled and have discovered 43 accumulations which total 942 million bbl of producible oil and 992 billion ft 3 of gas. API gravity of most oil ranges from 35 to 40°. The Bahia Supergroup, the main objective for petroleum exploration, has a maximum thickness of 6,500 m. This nonmarine unit ranges in age from Late Jurassic(?) to Early Cretaceous. The Upper Jurassic(?) typically consists of a redbed sequence (Alianç a Formation) overlain by a blanket sandstone (Sergi Formation). The Sergi is the best reservoir rock of the basin. The Lower Cretaceous (Wealden) strata are mainly dark-gray and grayish-green shale of the Itaparica, Candeias, and llhas Formations and are considered to be the oil and gas source rocks. The A Sandstone, the lenticular sandstone bodies of the Candeias Formation, and the São Paulo and Santiago Sandstones of the llhas Formation are the best reservoir rocks of the Lower Cretaceous section. The Recôncavo basin is an intracratonic half gaben. Intensive faulting occurred during the deposition of Candeias and lower llhas when the basin became a rapidly sinking trough. Accelerated growth of the Salvador and Mata-Catu uplifts, the most prominent structural features of the basin, produced the two principal (NE- and NW-trending) sets of normal faults. A late post- Sao Sebastião tectonic phase reactivated ancient faults and caused new ones to form. Consequently, the basin is characterized by a complex system of faulted blocks. The six major fields, containing 96 percent of the total producible oil, are related to the structural evolution of the basin. It is believed that the early period of faulting, contemporaneous with the deposition of the Candeias and lower llhas, was a decisive factor in the control of petroleum migration to, and accumulation in, the Sergi and A sandstones. The horst blocks of Agua Grande, Buracica, and Dom João fields (the first two having been partly uplifted during this tectonic phase) trapped about 623 million bbl of recoverable oil in these two sandstone bodies. Accumulation in llhas reservoirs was controlled mainly by the later, post-São Sebastião, phase of faulting. Folds developed in the downthrown blocks of normal faults, but the folding was not caused by compressional stress. These folds form traps for accumulations in the São Paulo, Santiago, and other llhas sandstones. Examples of such traps, in which about 187 million bbl of producible oil accumulated, are the Miranga and Taquipe fields. The genesis of the lenticular sandstone reservoirs in the Candeias field—a strati- graphic trap—is related to syntectonic deposition of the Candeias Formation; fractured shale and limestone also are reservoirs in this field. Candeias trapped about 93 million bbl of producible oil.

Abstract The Camamu-Almada basin (northeastern Brazil), is part of the rift system formed during the Early Cretaceous breakup of South America and Africa. The basin contains some small onshore gas accumulations and two offshore oil fields. A previous study (Mello et al. , 1995) characterized the occurrence of a single petroleum system in the Camamu-Almada basin: the Morro do Barro(!) petroleum system. In 2003, ANP , the Brazilian National Agency for Petroleum, Natural Gas, and Biofuels, coordinated a study on the tectono-sedimentary evolution and petroleum potential of the basin, headed by Lab2M – Laboratory of Multidisciplinary Modeling of Sedimentary Basins (COPPE /Rio de Janeiro Federal University). A combination of sequence stratigraphy and quantitative basin modeling techniques (Karner et al. , 1997 ; Driscoll and Karner, 1998 ; Karner and Driscoll, 1999a) was applied in order to allow a better understanding of the spatial and temporal relationships between the elements and processes of petroleum systems. The application of sequence stratigraphic principles (Vail, 1987 ; Christie-Blick and Driscoll, 1995) led to the recognition of five, second-order depositional sequences. More emphasis was given to the rift section, which was subdivided into four, third-order depositional sequences (Vail et al. , 1991). The Morro do Barro Formation comprises thick layers of shales having high total organic carbon (TOC) content (mostly from 2 to 5%) and hydrogen index (HI) values (up to 1,000 mgHC/gTOC), indicating that these rocks are composed mainly of a lipid-rich Type I kerogen. The Rio de Contas Formation, under adequate thermal conditions, may prove itself to be an additional hydrocarbon source. Known petroleum accumulations in the Camamu-Almada basin are associated with structural or structural-stratigraphic trapping within pre-rift and rift reservoirs. Most of the petroleum has been found in the Morro do Barro Formation reservoirs (almost 75% of original volume of oil-in-place), followed by Sergi Formation (around 25% of original volume) and Rio de Contas Formation reservoirs. The integration of the results achieved by seismic interpretation and basin modeling allowed identification of potential exploratory targets in the basin. Such structural, stratigraphic and combined plays were grouped as pre-rift, rift, or post-rift. Camamu-Almada basin potential has yet to be fully confirmed. Investments in upcoming years are needed to identify new hydrocarbon accumulations.