No abstract

CO2 adsorption under pressure and temperature conditions for geological storage of CO2 is evaluated for two non-shale reservoirs in Canada. One is the Weyburn carbonate reservoir, where the world’s largest CO2 storage project is carrying on, and the other is a tight sandstone reservoir. Wettability of reservoir rock under high-pressure CO2 is also evaluated. Rocks from both reservoirs show a significant mass increase as a result of CO2 adsorption but distinctly different behaviors. A method for estimating the density of the adsorbed CO2 phase from gravimetric adsorption data is developed, and the result is in fair agreement with the expectation from analogy of adsorption with liquid condensation. A formula is proposed to predict CO2 storage capacity of reservoir rocks based on directly measured adsorption data. It is shown that CO2 adsorption could substantially increase the storage capacity and decrease leaking potential by decreasing overpressure to the reservoir caprock. Nearly 30 and 40% more CO2 could be stored by adsorption in the carbonate and tight sandstone rocks, respectively. Rock wettability reflected by the water contact angle suggests that CO2 could enter small rock pores to increase adsorption and utilization of reservoir capacity. The results can contribute to the evaluation of the impact of adsorption on CO2 storage.

Whereas the importance of shale oil and gas production to the energy supply is increasing, the recovery of shale oil and gas is low and the environmental performance needs improvement. Injection of CO 2 captured from industrial emitters into shale reservoirs could enhance the oil and gas recovery and retain CO 2 through adsorption in shale to offset greenhouse gas emissions. In this work, we present a study on adsorption of CO 2 in an organic-rich shale. Unusual adsorption behaviors have been observed: The rate of adsorption increased with increasing pressure without showing a trend of saturation. Moreover, mass loss occurred at an elevated pressure. The adsorption behaviors have been elucidated by extraction of hydrocarbons from shale by CO 2 , from which the interactions of CO 2 with hydrocarbons are elucidated and new insights are obtained.

A new method is presented for simultaneous observation of time-dependent interfacial and wetting behavior for a system of hydrocarbon liquids, water, rock sample, and CO2. Application of this method for assessment of using CO2 to enhance oil and gas recovery from water-rich tight reservoirs is discussed with exemplary results. The discussion includes predicting time evolution of capillary pressure in tight rocks and swelling of liquid hydrocarbons trapped by water, and estimating the composition of the liquid phase composed by the trapped hydrocarbons and CO2 transferred through the water barrier.

Shales are mostly unexploited energy resources. However, the extraction and production of their hydrocarbons require innovative methods. Applications involving carbon dioxide in shales could combine its potential use in oil recovery with its storage in view of its impact on global climate. The success of these approaches highly depends on various mechanisms taking place in the rock pores simultaneously. In this work, properties governing these mechanisms are presented at technically relevant conditions. The pendant and sessile drop methods are utilized to measure interfacial tension and wettability, respectively. The gravimetric method is used to quantify CO2 adsorption capacity of shale and gas adsorption kinetics is evaluated to determine diffusion coefficients. It is found that interfacial properties are strongly affected by the operating pressure. The oil-CO2 interfacial tension shows a decrease from approx. 21 mN/m at 0.1 MPa to around 3 mN/m at 20 MPa. A similar trend is observed in brine-CO2 systems. The diffusion coefficient is observed to slightly increase with pressure at supercritical conditions. Finally, the contact angle is found to be directly related to the gas adsorption at the rock surface: Up to 3.8 wt% of CO2 is adsorbed on the shale surface at 20 MPa and 60 °C where a maximum in contact angle is also found. To the best of the author’s knowledge, the affinity of calcite-rich surfaces toward CO2 adsorption is linked experimentally to the wetting behavior for the first time. The results are discussed in terms of CO2 storage scenarios occurring optimally at 20 MPa.