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The present article exhibits the achieved results based on the evaluation of two petroleum systems, which compares reservoirs of fluvial environments of sedimentary basins located in the south and north Atlantic, in Brazil (Recôncavo Basin) and in Portugal (Lusitanian Basin), respectively. The main contribution of this study is the survey of the static (source, reservoir, and sealing rocks, in addition to traps) and dynamic elements (tectonic, migration, thermal, and diagenetic processes) of the two studied petroleum systems, seeking to understand the reasons for the success and failure of the analyzed reservoirs in relation to the accumulation of hydrocarbons. The following materials were used for this study: lithostratigraphic charts, event charts of petroleum systems, interpreted 2D seismic reflection lines, lithological profiles, outcrop data, geochemical analysis of source rocks, petrographic analysis, and description of diagenetic processes, which acts in the reservoir rocks. The methodology presents two phases: the first with a multiscale characterization of the elements of petroleum systems and economic aspects, and another with an integrated analysis of the reservoir potentials, based on the efficiency analysis table of the petroleum system elements and interpretative diagrams of the petroleum system elements. The occurrences of hydrocarbon accumulations indicate that the structuring of the Recôncavo Basin in horsts and grabens provides the formation of efficient migration routes, combined with an excellent source rock, reservoirs with good permo-porous characteristics, and effective seal rocks. On the other hand, in the Lusitanian Basin, the Paleozoic source rocks occur in mini-basins, with little lateral continuity, which negatively affects the generation of hydrocarbons. Besides this fact, saliferous tectonics were the main cause of hydrocarbon migration along faults or their walls towards the upper strata and to the surface. The fluvial reservoir rock shows a strong action of diagenetic processes, which affects its petrophysical properties. The main implication of this work is its contribution to the analysis of analogous reservoirs, based on the detailed investigation of the static and dynamic elements of petroleum systems.

Due to the success of oil and gas production, turbidites have become exploratory targets over the past 40 years in the rift and passive margin basins in the North and South Atlantic. The turbiditic reservoirs in rift and passive margin settings of Atlantic sedimentary basins located in Brazil (Campos Basin) and Portugal (Lusitanian Basin) represent potential economic units for the hydrocarbon exploration. However, despite being considered analogous reservoirs, these units present distinct potentials for the accumulation of hydrocarbons. In this context, the work presented discusses the results obtained from the analysis of static (source rock, reservoir rock, seal and trap) and dynamic elements (migration, tectonic, diagenetic and thermal processes) of both studied petroleum systems, using geological, seismic, well, geochemical and petrographic data. The developed methodology of multiscalar characterization of the two petroleum systems was successful, leading to a specific classification of the efficiency of the static and dynamic elements. These served as the basis for a petroleum systems analysis of the potential of turbiditic reservoirs in both analyzed basins. In the Campos Basin, the salt diapirs and the associated faults provided the origin of excellent migration routes for the hydrocarbons generated in lower intervals, allowing them to reach Cretaceous turbidite reservoirs. At Lusitanian Basin, the diagenetic processes reduced significantly the porosities of the potential turbiditic reservoirs, besides the intense influence of the salt tectonics that may have been responsible for the migration of hydrocarbons along faults or by their walls, towards upper formations and to the surface.

The Amaral Formation has a wide geographic distribution within the Lusitanian Basin, at the western Iberian Margin (Portugal). The different depositional contexts for this unit enabled the distinction of three sectors: lagoon, lagoon-barrier, and marine-distal. The integration of the evolutionary taphonomic analysis of its fossil assemblages with the analysis of multiscale properties through the CAMURES methodology (Multiscale Reservoir Characterization) allowed the application of a methodology for the classification of coquina which was previously developed for the Morro do Chaves Formation (Sergipe–Alagoas Basin, Brazil). Here, it was adapted according to the complexity of the Amaral Formation deposits. The classification of ten taphofacies, in association with four lithofacies, allowed the definition of 84 petrofacies, based on the nature of the sedimentary and taphonomic processes. The relationship between the structural context, the systems tracts, the diversity of the fossil record, the classification of taphofacies and petrofacies, and the understanding of vertical and lateral variations of the sediments’ deposition within the unit support the construction of geological and theoretical models for coquina deposits. These models will allow for prediction of the spatial distribution of facies in other coquina analogous hydrocarbon reservoirs, as well as specifying the delimitation of reservoir zones for 3D geocellular modeling and flow simulation of hydrocarbon-producing reservoirs, thus improving predictive analyses.

The Baixo Alentejo Flysch Group (BAFG) is an important stratigraphic unit that covers over half of the South Portuguese Zone (SPZ) depositional area, and it is composed by three main tectono-stratigraphic units: the Mértola, Mira, and Brejeira formations. All of these formations contain significant thicknesses of black shales and have several wide areas with 0.81 wt.%, 0.91 wt.%, and 0.72 wt.% average total organic carbon (TOC) (respectively) and thermal maturation values within gas zones (overmature). This paper is considering new data from classical methods of organic geochemistry characterization, such as TOC, Rock–Eval pyrolysis, and organic petrography, to evaluate the unconventional petroleum system from the SPZ. A total of 53 samples were collected. From the stratigraphical point of view, TOC values seem to have a random distribution. The Rock–Eval parameters point out high thermal maturation compatible with gas window (overmature zone). The samples are dominated by gas-prone extremely hydrogen-depleted type III/IV kerogen, which no longer has the potential to generate and expel hydrocarbons. The petrographic analyses positioned the thermal evolution of these samples into the end of catagenesis to metagenesis (wet to dry gas zone), with values predominantly higher than 2 %Ro (dry gas zone). The presence of thermogenic hydrocarbon fluids characterized by previous papers indicate that the BAFG from SPZ represents a senile unconventional petroleum system, working nowadays basically as a gas reservoir.

Regional geophysics research provides for prospect assessment of Timor-Leste, part of the Southeast Asia Archipelago in a region embracing the Banda Arc, Timor Island, and the northwest Australia Gondwana continental margin edge. Timor Island is a microcontinent with several distinct tectonic provinces that developed initially by rifting and drifting away from the Australian Plate. A compressive convergence began in the Miocene whereby the continental edge of the large craton collided with the microcontinent, forming a subduction zone under the island. The bulk of Timor Island consists of a complex mélange of Tertiary, Cretaceous, Jurassic, Triassic, Permian, and volcanic features over a basal Gondwana craton. Toward the north, the offshore consists of a Tertiary minibasin facing the Banda Arc Archipelago, with volcanics interspersed onshore with the basal Gondwana pre-Permian. A prominent central overthrust nappe of Jurassic and younger layers makes up the mountains of Timor-Leste, terminating south against an accretionary wedge formed by this ongoing collision of Timor and Australia. The northern coast of the island is part of the Indonesian back arc, whereas the southern littoral onshore plus shallow waters are part of the accretionary prism. Deepwater provinces embrace the Timor Trough and the slope of the Australian continental margin being the most prospective region of Timor-Leste. Overall crust and mantle tectonic structuring of Timor-Leste is interpreted from seismic and potential field data, focusing mostly on its southern offshore geology where hydrocarbon prospectivity has been established with interpretation of regional seismic data and analyses of gravity, magnetic, and earthquake data. Well data tied to seismic provides focal points for stratigraphic correlation. Although all the known producing hydrocarbon reservoirs of the offshore are Jurassic sands, interpretation of Permian and Triassic stratigraphy provides knowledge for future prospect drilling risk assessment, both onshore and offshore.