First Stoichiometric Model of Oil Biodegradation in Natural Petroleum Systems: Part II*: Application of the BioClass 0D Approach to Oils from Various Sources
Published:January 01, 2012
Frank Haeseler, F. Behar, D. Garnier, 2012. "First Stoichiometric Model of Oil Biodegradation in Natural Petroleum Systems: Part II: Application of the BioClass 0D Approach to Oils from Various Sources", Basin Modeling: New Horizons in Research and Applications, Kenneth E. Peters, David J. Curry, Marek Kacewicz
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The purpose of the this study was to apply the biodegradation model BioClass 0D proposed by Haeseler et al. (2010) to three nonbiodegraded oils representative of the three main types of source rocks (types I, II, and III of Tissot et al., 1974; Tissot and Welte, 1978). The oils are described by seven chemical classes: (1) the gas fraction is split into H2S, CO2,C1, and C2–C4; (2, 3) the C6–C14 fraction including saturates and aromatics; and (4–6) the C14+ fraction, including n-, iso-, cyclo-alkanes, aromatics, and nitrogen, sulfur, and oxygen–containing compounds (NSOs). This 0D model reconstructs the chemical evolution of the residual oil with increasing biodegradation and the amounts of products generated during either aerobic or anaerobic processes. Results show that with increasing biodegradation, the residual oil composition depends on the initial proportion of the different chemical classes. For instance, for the type I oil enriched in paraffins, the C14+ n-alkanes are still present when 60% of the original oil has already disappeared, whereas for the type II oil, the same chemical class disappears after only 30% of total hydrocarbon loss. During methanogenesis, the gas-oil ratio of the initial fluid significantly increases with increasing biodegradation. However, the volume of methane may be reduced because of its solubility in water or it may leak through the cap rock. The production of H2S is always very low when sulfur minerals that can provide electron acceptors are absent. Results also show that the amount of water needed to provide the electron acceptors depends strongly on the biological process responsible for oil biodegradation. The water ratio between aerobic biodegradation and methanogenesis might be as high as 107. Consequently, aerobic biodegradation may be limited compared with methanogenesis in petroleum systems in which the oil-water volume ratio varies during fluid history.
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Basin Modeling: New Horizons in Research and Applications
Temperature-time–based first-order kinetic models are currently used to predict hydrocarbon generation and maturation in basin modeling. Physical chemical theory, however, indicates that water pressure should exert significant control on the extent of these hydrocarbon generation and maturation reactions. We previously heated type II Kimmeridge Clay source rock in the range of 310 to 350°C at a water pressure of 500 bar to show that pressure retarded hydrocarbon generation. This study extended a previous study on hydrocarbon generation from the Kimmeridge Clay that investigated the effects of temperature in the range of 350 to 420°C at water pressures as much as 500 bar and for periods of 6, 12, and 24 hr. Although hydrocarbon generation reactions at temperatures of 420°C are controlled mostly by the high temperature, pressure is found to have a significant effect on the phase and the amounts of hydrocarbons generated.
In addition to hydrocarbon yields, this study also includes the effect of temperature, time, and pressure on maturation. Water pressure of 390 bar or higher retards the vitrinite reflectance by an average of ca. 0.3% Ro compared with the values obtained under low pressure hydrous conditions across the temperature range investigated. Temperature, pressure, and time all control the vitrinite reflectance. Therefore, models to predict hydrocarbon generation and maturation in geological basins must include pressure in the kinetic models used to predict the extent of these reactions.