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Petroleum Systems Modeling Advances Applied In the Recent Discoveries Made In Brazilian Marginal Basins

Henrique L. de B. Penteado and Laury M. de Araújo
Petrobras S.A., Rio de Janeiro, Brazil


With increasing energy requirements worldwide, petroleum exploration is moving towards ever deeper and more complex prospects. In this general economic context, Petrobras has been concentrating its exploration efforts in the South Atlantic, particularly in deep offshore Brazil. As a result of those efforts, since 2006 large petroleum discoveries have been made in Brazilian marginal basins. Foremost among the discoveries are those in Aptian pre-salt reservoirs in Santos Basin, such as the Lula (previously known as Tupi), Cernambi (Iracema) and Sapinhoá (Guará) fields. However, significant petroleum accumulations have also been found in other basins, such as in the well-known Campos Basin, and in the Espírito Santo and Sergipe-Alagoas basins.

As is always the case in petroleum exploration, success rates are a function of the seamless integration of a large spectrum of complementary techniques. Petroleum systems modeling has played an increasingly important role among several techniques applied in the exploration workflow of Petrobras. Some of the more classical applications of petroleum systems modeling comprise estimations of temperature and pressure histories, timing of oil and gas generation, migration pathways, reservoir filling and risk of seal failure. In addition, a considerable effort in research and development in Petrobras has been dedicated to a better assessment of petroleum charge and composition. Special attention has been given to developing studies that focus on understanding the dynamic evolution of oil and gas compositions with increasing source-rock maturity. Furthermore, investigation on petroleum compositional changes due to post-expulsion processes such as phase separation, evaporative fractionation and biodegradation has been constantly providing important insights on these processes.


Petroleum charge has long been recognized as one the most critical factors in the effectiveness of petroleum systems. The usual approach to estimate petroleum potential is to use Rock-Eval data (e.g. Behar et al., 2001). Because it is a relatively simple, fast and cost-effective technique, Rock-Eval pyrolysis allows source-rock properties to be measured in a large number of samples. Kinetics of petroleum generation derived from Rock-Eval data have also been an industry standard widely applied in modeling studies. However, yields of expelled petroleum obtained in hydrous pyrolysis experiments have been consistently lower than the petroleum potentials suggested by open-system Rock-Eval analyses, especially for types II-III kerogens (e.g. Lewan and Ruble, 2002). The amounts of expelled petroleum reported by these authors are around half of those given by Rock-Eval. Recognizing the importance of understanding these discrepancies and their implications on assessing petroleum charge in basins, a small number of representative source rocks from Brazil and other countries containing different kerogen types has been the subject of a comparative study of their petroleum generation potential using both Rock-Eval and hydrous pyrolysis techniques. As a consequence of this work, considering the petroleum yields obtained from hydrous pyrolysis as a reference of those occurring in natural systems, a correction curve has been established that allows the conversion of Rock-Eval source-rock potential to amounts of actually expellable petroleum. These results have been systematically used in the assessment of petroleum charges in Brazilian marginal basins to provide more realistic estimates. Further studies are being undertaken on the comparison of generation kinetics and fluid compositions provided by both pyrolysis techniques.


Taking into account the huge costs involved in offshore operations and the economic dependence of discoveries on petroleum type, it is of utmost importance to be able to predict fluid composition and properties. Hence, a compositional kinetic model for petroleum primary and secondary cracking using classes for PVT modeling has been developed for Brazilian lacustrine and marine source-rock sequences. This kinetic scheme has been widely applied in 3D petroleum systems modeling in Brazilian marginal basins to assess timing of oil and gas generation, as well as for the prediction of petroleum composition and PVT properties.

As a starting point, a total of more than 70 non-biodegraded and non-altered oils derived from both lacustrine and marine source rocks from basins in southeastern Brazil, with API gravities ranging from 27 to 55, was characterized by a comprehensive set of analytical procedures. Good-quality samples of petroleums obtained from producing fields had their PVT and geochemical properties measured, allowing assessments of source typing and maturity. These petroleum samples are deemed to represent the full range of oil and gas compositions from their respective lacustrine and marine source rocks. Using quantitative gas chromatographic analyses, the oils were sliced according to boiling point and molecular weight ranges, and the mass percentages of each slice from C6 to C60+) were measured. With these results, a PVT-type description of compound classes similar to that proposed by Di Primio and Horsfield (2006) was adopted for the oil phase. Combining results for the oils with those for individual gases in the gas phase using measured gas-to-oil ratios, an enhanced PVT description was achieved for the whole petroleum (C1 to C60+).

The kinetics for primary cracking of lacustrine and marine source rocks were derived from Rock-Eval data, with corrections introduced for the amounts of expelled petroleum as described above. This correction is necessary because most of the heavy components (resins and asphaltenes) of bitumen and early-generated oil detected in Rock-Eval analyses remain adsorbed within the source rock (e.g. Lewan and Ruble, 2002). As kerogen cracking proceeds, heavier and less stable compound classes can undergo secondary cracking, thus producing lighter and more gas-rich petroleum (e.g. Behar et al., 2008 and 2010). Even though the latter authors proposed a sophisticated compositional kinetic scheme to simulate the major reactions taking place within different source rock types, a simpler approach was adopted here concerning the composition of the first-expelled petroleum. The initial composition attributed to the expelled petroleum (oil and gas phases) from each type of source rock was that of the least mature, non-altered natural petroleum equivalent. The kinetics and stoichiometry of secondary cracking of each compound class were derived from experiments of artificial cracking of oils using several pyrolysis techniques. By coupling the primary and secondary compositional kinetic schemes, petroleum composition and its PVT properties (density, API gravity, gas-to-oil ratio, saturation pressure) can be continuously assessed throughout source rock maturation.

Petroleum compositions provided by this new PVT-type kinetic scheme reproduce well those of real accumulations in Brazilian marginal basins, thus allowing its application as a powerful predictive tool in exploration prospects in frontier areas. Furthermore, the correlation of petroleum composition with source-rock maturity made possible by this kinetic scheme allows the oil composition of discovered accumulations to be used as calibration for source-rock evolution in petroleum systems modeling.


After expulsion, several processes may alter the compositions of oil and gases. Phase separations during vertical migration might lead to differences in API gravity and gas-to-oil ratios (GOR) in petroleum accumulations with similar original compositions. Variable extent of mixing of oils and gases with different maturities, and sometimes different origins, seems to be a common phenomenon that enhances heterogeneities among fields. Petroleum biodegradation by bacteria under reservoir conditions induce a preferential loss of light ends and saturated compounds in oils, making them heavier and more viscous. Evaporative fractionation caused by a substantial influx of gas changes the composition and behavior of petroleum phases (Thompson, 2010). Addition of biogenic gas in shallow reservoirs provides a source of non-thermogenic methane. Several of these processes have been topics of continued research in Petrobras and elsewhere aiming at achieving a better prediction of petroleum composition in prospects before drilling.

Among these alteration processes, the effects of phase separation and evaporative fractionation on petroleums have been tested by modeling using the PVT-based kinetic scheme mentioned before in synthetic cases of several stacked reservoirs. The modeled results were compared to the compositions of the oil and gas phases in accumulations where these processes were interpreted to have occurred based on PVT and geochemical parameters. Overall, the numerical experiments performed have shown that evaporative fractionation can be adequately reproduced in the scale of petroleum systems modeling, giving fluid compositions compatible with those of natural accumulations. Thus, a perspective is opened for the use of petroleum systems compositional modeling to assess its effects of evaporative fractionation on fluid composition in exploration prospects. Nonetheless, it must be mentioned that during the supply dynamics of increasingly evolved petroleum charges to several stacked traps, petroleum vertical migration, accumulation, mixing and phase separation are highly complex and intertwined processes.


Besides developing continuous research on related topics, the credibility and robustness of results provided by petroleum systems modeling strongly depends on systematically improving existing basin models. A concept of “living” petroleum systems models is part of current practice in Petrobras nowadays. Basinwide or local models are constantly updated and calibrated as new wells are drilled and geologic data become available. So, structural and facies maps, heat flow histories, pressure field and fluid flow, data on petrophysical and geochemical properties are constantly updated in models, rendering them ever more reliable and their predictions increasingly better for the geological contexts being explored by the company.


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AAPG Search and Discovery Article #120098©2013 AAPG Hedberg Conference Petroleum Systems: Modeling the Past, Planning the Future, Nice, France, October 1-5, 2012