The various modes of acid gas storage in aquifers, namely structural, residual, and local capillary trapping, are effective only if the rock remains water‐wet. This paper reports an evaluation, by means of the captive‐bubble method, of the water‐wet character in presence of dense acid gases (CO2, H2S) of typical rock‐forming minerals such as mica, quartz, calcite, and of a carbonate‐rich rock sampled from the caprock of a CO2 storage reservoir in the South‐West of France. The method, which is improved from that previously implemented with similar systems by Chiquet et al. (Geofluids 2007; 7: 112), allows the advancing and receding contact angles, as well as the adhesion behavior of the acid gas on the mineral substrate, to be evaluated over a large range of temperatures (up to 140°C), pressures (up to 150 bar), and brine salinities (up to NaCl saturation) representative of various geological storage conditions. The water‐receding (or gas‐advancing) angle that controls structural and local capillary trapping is observed to be not significantly altered in the presence of dense CO2 or H2S. In contrast, some alteration of the water‐advancing (or gas‐receding) angle involved in residual trapping is observed, along with acid gas adhesion, particularly on mica. A spectacular wettability reversal is even observed with mica and liquid H2S. These results complement other recent observations on similar systems and present analogies with the wetting behavior of crude oil/brine/mineral systems, which has been thoroughly studied over the past decades. An insight is given into the interfacial forces that govern wettability in acid gas‐bearing aquifers, and the consequences for acid gas geological storage are discussed along with open questions for future work.

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The safety of acid gas geological storage is to a large extent controlled by the capillary properties of the caprock. This low-permeable (e.g., clayey) porous media usually saturated with water acts as a capillary barrier to the underlying stored acid gas, provided its water-wettability is preserved and water/acid gas interfacial tension (IFT) is high enough. The displacement or capillary breakthrough pressure, above which the stored acid gas intrudes into the caprock, is directly related to those two interfacial properties. Water/acid gas IFTs have recently been thoroughly characterized. However, little is known on the effect of acid gases (CO2, H2S and their mixtures) on the water-wettability of caprocks. We present an experimental setup and procedure for measuring contact angles on mineral substrates in the conditions of geological storage. Measurements have been carried out in a range of pressures extending up to 150 bar, both with CO2 and H2S, and with mineral substrates representative of caprock minerals such as quartz and mica, as well as with a substrate sampled from the caprock of a depleted gas reservoir. We observed that the wettability alteration of mica is moderate in the presence of dense CO2, but pronounced in the presence of dense H2S. In contrast, the wettability of quartz and of the 'real' caprock substrate is not altered by dense CO2 or H2S. In addition to those substrate- and acid gas-dependent wettability effects, the much lower water/acid gas IFTs as compared to water/hydrocarbon gas IFTs are responsible for a loss in capillary-sealing potential of a given caprock when a hydrocarbon gas is replaced with acid gas, especially when the acid gas is rich in H2S. This potential, as evaluated by the displacement or capillary breakthrough pressure, should be determined very carefully when planning an acid gas geological storage operation. 1. Introduction As an increasing number of H2S-containing (sour) gas reservoirs are being exploited around the world, there is a growing interest for injecting and storing in geological formations the H2S rich-acid gas that is separated from the (sour) natural gas in gas processing plants. For instance, acid gas disposal in geological formations has been practised over the past 15 years in Western Canada, where more than 3 Mt of H2S and 3 Mt of CO2 have been injected, with a maximum up to 83% of H2S in one of the 40 storage sites (deep aquifers or depleted hydrocarbon reservoirs; Bachu, 2007). The reinjection of H2S-rich acid gases in massive quantities is currently being considered in some reservoirs such as the Kashagan oil field in the North Caspian Sea. These reservoirs usually contain CO2 along with H2S as associated gases, which are both separated in the gas plant. The injection of the resulting acid gas stream in a geological formation is interesting for the two following reasons:to avoid atmospheric emissions of CO2, andto avoid H2S desulphurization through the Claus process, which has many drawbacks, both environmental and economical (Abou-Sayed et al., 2005). The implementation of this option on a large scale requires a proper assessment of the effects induced by the presence of acid gas on the integrity of the formation. This assessment is the subject of many research studies, mostly conducted in the context of CO2 geological storage. A large part of this effort addresses the different possible leakage mechanisms by which CO2 may escape from the geological formation where it is stored. This effort needs to be extended to acid gases containing significant amounts of H2S.

We propose an accurate method to predict interfacial tension between water and nonpolar fluids by using Cahn gradient theory. The only necessary elements are (i) a water contact energy function and (ii) an equation of state (EoS) for the nonpolar fluid, chosen here as the Peng-Robinson EoS. The contact energy, a function of the fluid (adsorbate) surface density, is related to interfacial tension (IFT) by means of the Gibbs adsorption equation. Examining a large number of IFT data, we observe that the water contact energy is a universal function of adsorbate's surface density when proper scaling variables are used: it depends neither on adsorbate nor on temperature. A corresponding-states principle appears to govern the interfacial behavior between water and any nonpolar compound that is sparingly soluble in water. A predictive method (without any adjustable parameter) is therefore available for estimating IFT between water and any nonpolar fluid, whether the fluid is in supercritical or in subcritical states. The method performs well when the adsorbate is sparingly soluble in water, but slightly overestimates IFTs when the adsorbate's solubility in water is significant (e.g., CO2 and H2S). A similar behavior should also hold for interfaces involving a solid substrate.

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