There is a growing body of evidence that gas situated within the pores of nanoporous materials may not have the same equation of state (pressure, volume, and temperature, PVT) properties as macroscopic free gas. However, there is limited experimental measurement of in-situ fluid properties for gases taken up by nanoporous shales. In this work, we use a gas injection porosimetry approach to measure the gas storage capacity of four different North American shales (Bakken, Marcellus, Haynesville, and Mancos) and in-situ gas density for a few different hydrocarbon and noble gases. We find the porosity measured with helium to be reasonable between 5% and 16.4%. However, when using other gases such as methane, argon, and ethylene, the equivalent porosity estimations are extremely high, with the highest measured value being 309% for ethylene gas in a Marcellus shale sample. Such extreme results raise questions on the validity of the underlying assumptions of the porosimetry equations, in particular, the description of gas density within shale nanopores with macroscopic density. The experimentally measured density of in-situ gas is found to be up to 28 times higher than the theoretically estimated one at the equilibrium PVT conditions. This in-situ densification of gas is independently verified using X-ray CT imaging on one of the samples – the Marcellus. The underlying mechanism for gas densification could be explained by adsorption, in which case the proportion of adsorbed gas is estimated to be between 12% and 96% for the various gas-sample pairs. Surface area measurements show that a monolayer of adsorbed gas can only account for 27%–42% of the adsorbed gas. This calls into question the commonly assumed Langmuir monolayer model of adsorption, and indicates that gas densification within shale nanopores can be attributed to a multilayer adsorption mechanism and/or other unidentified mechanisms that require further study.
All Science Journal Classification (ASJC) codes
- Energy Engineering and Power Technology