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Objectives/Scope : Nowadays steam injection is commonly used as a thermal EOR method. However this process is also associated with chemical reactions in the reservoirs, called aquathermolysis, which produce the highly toxic and corrosive acid gas H2S in the presence of sulfur-rich heavy oil. The overall objective of this work is to understand the aquathermolysis reactions in reservoirs undergoing steam injections and provide Oil companies with a numerical model for reservoir simulators that forecasts H2S production risk. Methods, Procedures, Process : Our H2S prediction method for reservoir simulations is based on a new simplified reactive scheme of 5 reactions. It describes selected pseudo-components: Asphaltenes, Resins, H2O, Aromatics, Saturates, pyrobitumen, gas plus H2S and is derived from the mass balances of several aquathermolysis experiments on an oil sand sample from Foster Creek Project in Athabasca. The pseudo-components molecular formulas were estimated from their experimental atomic composition. The reactions stoichiometric coefficients were then determined from the atomic balance equations. Finally the reactive scheme was coupled with a fluid thermodynamic description and validated at reservoir scale through SAGD simulations. Results, Observations, Conclusions : The numerical modeling is assessed against both lab-scale experiments and data from an SAGD process in Athabasca. It is firstly found that the compositional kinetic model, which simulates the aquathermolysis reactions as a function of time and temperature, can accurately reproduce the SARA composition variations observed in laboratory (Figures 1, 2). The matching was achieved simply by tuning the kinetic parameters of the reactions, while the stoichiometric coefficients remain fully constrained by the system of atomic balance equations. Regarding H2S, as it is produced in a very small (though highly toxic) amount, its production is not sufficiently constrained by the simplified experimental mass balances. Consequently a mass balance on sulfur distribution was performed and integrated into the reactive scheme. Numerical results show that H2S predictions are greatly improved by this new method due tothe limited number of components containing sulfur (Figure 3). Most importantly the integration of this sulfur-based-compositional kinetic model in a SAGD reservoir simulation (Figure 4) has led to a H2S to SARA (bitumen) ratio computation that was consistent with data published by oil companies. This was achieved without adjusting the reactive scheme. Finally a sensitivity analysis of H2S production on some critical parameters for SAGD processes is also presented. Novel/Additive Information : This numerical approach can be used for reservoir simulations involving steam injection. As an input the chemical model requires only the atomic contents and the molar mass of SARA fractions, which is easily obtained from classic geochemical analyses. Provided that the initial oil composition is known, the H2S production against time at surface can hence be forecast for different oil fields, helping operators to size their H2S removal facilities.