Connate water strongly restricts shale gas enrichment and production, and most artificially injected water is confined in shale pore networks owing to low water recovery during hydraulic fracturing, which leads to a more complex pore water distribution. However, previous studies have focused on the water vapor sorption of gas shales rather than liquid pore water. This study clarifies the occurrence and distribution of pore water and the controlling factors by conducting thermogravimetry (TGA) under liquid water saturation and water vapor sorption experiments on four gas shales from the Wufeng Formation in South China. Nuclear magnetic resonance (NMR) T₂ and T₁–T₂ technologies were used to monitor the dynamic changes and states of moisture, and the microscopic pore structures during water vapor sorption were detected using low-temperature nitrogen adsorption-desorption. The results indicate that TGA is adequate for determining the adsorbed, bound, and movable water contents. These four gas shales are characterized by high adsorbed and movable water contents, and some bound water. The adsorbed water primarily occurs in tiny pores (<100 nm), controlled by organic matter, followed by clay minerals. The movable water, typically associated with quartz, primarily exists in pores of >100 nm, particularly macropores of >1000 nm. The bound water predominantly correlates with pores ranging from 10 to 2000 nm in clay minerals. The water vapor sorption process of the gas shale is well clarified. Water molecules primarily adsorb on the clay mineral's hydrophilic surface, followed by oxygen functional groups in the organic matter. Therefore, clay minerals control water vapor sorption at low relative humidity (RH <0.75), whereas organic matter primarily affects vapor sorption at high RH. The TGA of liquid water-saturated gas shales can clarify the water distributions in full-scale pore networks, whereas the water vapor sorption method primarily discloses the moisture in small nanopores (<100 nm) but ignores most bound and movable water. This paper provides insight into liquid water distribution and occurrence states within shale pore networks, contributing to a better understanding of gas–water–rock interaction systems in-situ and hydraulic fracturing shale gas formations.

Characterizing the microscopic occurrence and distribution of in-situ pore water and oil is crucial for resource estimation and development method selection of shale oil. In this paper, a series of nuclear magnetic resonance (NMR) experiments were conducted on shales from the Gulong Sag, Songliao Basin, China, at AR, WR-AR, WOR-AR, Dry, SO, and WR states. In-situ pore water and oil were reconstructed after WOR-AR. An improved T₁–T₂ pattern for shale oil reservoirs comprising water and oil was proposed to classify and quantitatively detect pore fluids at different occurrence states. The total and free oil contents derived from NMR T₁–T₂ spectra at AR states were found to correlate well with those from multistage Rock-Eval. Moreover, the NMR-calculated total and free oil are generally larger than those measured from multistage Rock-Eval, whereas adsorbed oil is the opposite, which implies that adsorbed, bound, and movable oils in shale pores can be accurately and quantitatively detected via NMR, without absorbed hydrocarbons in kerogen. As per the NMR T₂ and T₁–T₂ spectra at WOR-AR state, the microdistributions of in-situ pore water and oil were clearly demonstrated. Adsorbed, bound, and movable oils primarily occur in the micropores (<100 nm), mesopores (100–1000 nm), and macropores (>1000 nm), respectively, whereas capillary-bound water is primarily correlated with micropores. Thus, the microscopic occurrence and distribution of adsorbed oil are remarkably affected by pore water, followed by bound oil, and movable oil is hardly affected. This study would be helpful in further understanding the microscopic occurrence characteristics of pore fluids in-situ shale oil reservoirs.