In-situ extraction of heavily sulfured oil by use of steam injection comes with a high risk of hydrogen-sulfide (H2S) production resulting from aquathermolysis reactions. This could lead to casualties, environment damage, and corrosion of surface facilities and wells. Also, a strong need exists to understand aquathermolysis reactions and to forecast the generation of acid gases in such context. Toward that goal, a tailor-made work flow was developed to estimate H2S concentration at the wellhead.
A three-steps approach that combines laboratory studies and numerical prediction has been developed. It consists first of a fast, preliminary assessment of the highest H2S risk areas based on the measurements of sulfur characteristics of reservoir core samples. Second, aquathermolysis experiments from the core samples are conducted to calibrate the compositional chemical model of the reservoir simulator. The latter is eventually used to carry out thermal compositional reactive simulations at field scale. The reservoir simulator allows simulations of the steam-assisted gravity drainage (SAGD) processes and handles H2S distribution over oil/water/gas phases and its migration in these phases.
Simulation results show that acid gases are generated within the steam chamber before they accumulate at the chamber edges, where they dissolve in the water and oil phases. This contributes to reduce viscosity, allowing the oil to flow along the steam chamber edges before it has reached the steam temperature. Therefore, the H2S produced at surface is mainly carried toward the wells by water and, to a lesser extent, oil. This flowing oil has not reacted with the steam; its composition is close to the initial reservoir oil but enriched with dissolved gases. The steam chamber shape, the temperature distribution, and the H2S produced at surface are strongly modified when heterogeneities are introduced in the reservoir model.
Synthetic cases allow a deeper understanding of the effects of heterogeneities. Vertical permeability, thus, is a key factor of H2S production variations. When steam reaches a lower permeability lithology, a delayed rise in H2S production at the wellhead is observed as the rates of aquathermolysis reactions increase. Finally, foam-assisted SAGD is considered. While the foam improves the steam/oil ratio, no clear improvement was observed regarding H2S production.