Chromatographic Partitioning of H2S and CO2 in Acid Gas Disposal

Abstract In the Long Coulee Glauconite F reservoir in southern Alberta, where acid gas (98% CO2, 2% H2S) has been injectedsince 2002, H2S breakthrough in producing wells occurredsubsequent to the breakthrough of CO2. It was hypothesized that the preferential solubility of H2S in formation brine is responsible for this chromatographic separation. Since the delay in H2S breakthrough is of relevance in geological storage of impure CO2 streams, a series of experiments were conducted to measure the solubility of CO2 and H2S in formation brine at in-situ conditions. Immiscible displacement experiments were performed in a slim tube packed with silica sand to study breakthrough behavior of different gas components. The experiments were then modeled using a compositional simulator, and the effect of different factors on the delayed breakthrough of H2S was examined using a series of sensitivity studies. It was confirmed that the preferential solubility of H2S over CO2 leads to it being stripped off at the leading edge of the gas displacement front and results in its delayed breakthrough. A similar delay in H2S breakthrough occurs even at higher H2Sconcentrations (e.g., 30%) in the injected gas. Through thesimulation studies it was shown that the delay in H2S breakthrough becomes more pronounced if the gas front is more diffusive. For example, it was shown when gravity forces or mobility ratio favor stable displacement, CO2 and H2S breakthroughs occur closer to each other. This paper describes the experiments and the simulation studies and presents the implications of the chromatographic partitioning of H2S and CO2 in the geological storage of acid gas or impure CO2. Introduction A number of operators in Alberta have implemented injection into depleted gas and oil pools as a means of disposal and storage of acid gas (Bachu and Gunter[1]). In many cases the composition of the injected gas is similar to that of impure CO2 in that the majority of the injected gas is CO2. For example, in the Long Coulee Glauconite F pool in south-eastern Alberta (Figure 1), CO2 concentration in the injected gas is about 98% (with H2S making up the majority of the balance). Significant interest has been shown in the study of these reservoirs as commercial-scale analogues for geological storage of CO2 (Bachu and Gunter[1], Bachu and Haug[2]). Bachu et al.[3] and Pooladi-Darvish et al.[11] have studied the Long Coulee Glauconite F pool and the breakthrough of acid gas in some of its producing wells. The gas cap of the pool was discovered in 1967 and the much smaller oil leg in 1984. By the end of 2006production from the pool was 1.93?109 m3 (68 Bcf) of gas and 139,000 m3 (875 MSTB) of oil. At the time of the start of acid gas injection in 2002, its pressure had declined from an initial value of approximately 13,000 kPa to 1000 kPa. Breakthrough of acid gas was observed between 2003 and 2005 in the remaining three gas producing wells. Subsequently, breakthrough was also observed in the producing oil wells.

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