Capillary Condensation in Shale: A Narrative Review

Shale reservoirs are estimated to account for approximately 10-30% of oil and gas worldwide, yet operators rarely produce more than 10% of the original hydrocarbons in place from them. These poor production numbers are a result of the assumption that the same pressure-volume-temperature (PVT) analysis procedures that are employed in conventional reservoirs are also applicable to shale and tight reservoirs. However, traditional PVT analysis does not account for the nanoporosity of the shale and, therefore, neglects the ability of nanopores to significantly alter the phase behavior of reservoir fluids. To quantify the effects of shale nanoporosity on the phase behavior of reservoir fluids, a novel gravimetric apparatus was developed. Unlike other gravimetric apparatuses in the literature, ours is compatible with both simple and complex experimental fluids and up to several hundred grams of unconsolidated or consolidated porous media at temperatures and pressures up to 232ᵒC and 5,000 psi, respectively. Furthermore, our apparatus does not require a buoyant force correction, which is one of the major shortcomings of most commercially available gravimetric apparatuses. These unique features allow us to study fluid phase behavior in shale and tight cores with high accuracy and efficiency. In the course of an exhaustive three-year research program, we have used this apparatus to measure the first capillary condensation isotherm for a fluid mixture with more than two components and discovered new phenomena of capillary condensed and supercritical fluids in the nanopores of shale rock and synthetic porous media. By reviewing the works produced over the course of this research, we are now able to answer longstanding questions as to when and how nanoconfinement-induced phase behavior occur in shale reservoirs and the implications that different types of phase behavior, including capillary condensation and nanoconfined supercriticality, have for oil and gas production.