Adsorption is one of the most important forms of storage of gas in shale reservoirs. Shale gas adsorption in the actual reservoir is not only affected by individual factors such as water content, temperature, and pressure but also by the synergetic effect of these factors. In this study, we conducted laboratory experiments on methane adsorption in dry and wet shale at different pressures and temperatures. The synergetic effect of water content, temperature, and pressure on shale gas adsorption is explored. The results show that increasing temperature weakens the interaction between methane and shale and reduces adsorption capacity due to the exothermic nature of adsorption. Water reduces methane adsorption capacity by occupying adsorption sites and blocking pores in the shale system. Although temperature and water reduce methane adsorption individually, the effect of these two factors weakens each other. Temperature has a more significant effect on methane adsorption in shales with low water content, while water has a more remarkable impact on methane adsorption at a low temperature. Furthermore, the increase in pressure reduces the negative influence of water and temperature on methane adsorption. By quantitatively analyzing the relationship between methane adsorption in dry and wet shales, a predictive adsorption model for wet shale considering the influence of in situ conditions is proposed and validated. Validation shows that the proposed model has high accuracy and broad applicability to shales with different properties.

Summary: Gas condensate is stored in multiscale pores, fractures, and vugs within geological formations. Confinement within these structures significantly influences the phase behavior of gas condensate, rendering it challenging to characterize through conventional bulk pressure/volume/temperature (PVT) measurements. In this study, we used microfluidics and in-situ computed tomography (CT) scanning to directly measure the upper dewpoint of gas condensate and the gas/oil ratio in porous media during depressurization. We used two microfluidic chips with different pore sizes to investigate the confinement effects on gas condensate phase behavior at various scales, including pores as small as 50 nm. Our results revealed a significant increase in the upper dewpoint within the pores compared to bulk PVT measurements, with a more pronounced deviation at smaller pore sizes. Additionally, the proportion of condensate oil in porous media exceeded that observed in bulk PVT measurements at the same pressure. To validate our microfluidic findings, we conducted in-situ CT scanning experiments using a porous media model created by packing quartz particles. CT scans revealed pores ranging from a few micrometers to over 100 micrometers. Consistently, we observed an increase in the upper dewpoint and liquid ratio within these pores. Our study provides crucial experimental evidence indicating that the phase behavior of gas condensate in porous media deviates from bulk PVT measurements. The observed increase in the upper dewpoint, even within micrometer-sized pores, has important implications for phase equilibrium calculations.

Shale, a heterogeneous and extremely complex gas reservoir, contains low porosity and ultra-Low permeability properties at different pore scales. Its flow behaviors are more complicated due to different forms of flow regimes under laboratory conditions. Flow regimes change with respect to pore scale variation resulting in change in gas permeability. This work presents new insights regarding the change of pore radius due to gas adsorption, effective stress and impact of both on shale gas permeability measurements in flow regimes. From this study, it was revealed that the value of Klinkenberg coefficient has been affected due to gas adsorption-induced pore radius thickness impacts and resulting change in gas permeability. The gas permeability measured from new proposed equation is provides better results as compare to existing equation. Adsorption parameters are the key factors that affect radius of shale pore. Both adsorption and effective stress have an effect on the pore radius and result gas permeability change. It was found that slip effect enhances the apparent gas permeability and also changes with effective stress; therefore, combine impact of slip flow and effective stress is very important as provides understanding in evolution of apparent permeability during shale gas production.

Measurement of gas sorption capacity in a shale gas reservoir is significant to comprehending the mechanism of gas storage and resource assessments. In this study, gas sorption experiments on shale samples have been conducted, and a gas sorption analytical model has been proposed. This model is validated with previously published data. With this, the effective porosity is analyzed by combining the gas sorption and stress equations, and the shale gas-in-place (GIP) is calculated using a previous and newly proposed method. The influence of porosity (adsorbed/sorbed) on shale GIP is also examined. The results show that the proposed model provides the adsorbed and absorbed gases' contribution in total gas storage capacity, and its results are better than the Langmuir model. Moreover, it is also determined that the effective porosity performs a key part in characterizing the shale gas reservoirs, and it decreases with the increase in pore pressure. The results also reveal that higher total gas storages are obtained due to gas absorption, at low pressure, using the new proposed method. Further, with the increase in pressure, the total gas storage capacity increases, according to the shale sample characteristics, i.e., absorption and adsorption. Furthermore, the total gas storage is also altered due to adsorbed/sorbed porosity. The amount of absorbed gas ranges from 18.99-19.45% and is observed in this study.

The Dongsheng gas field is a water-bearing tight gas reservoir characterized by high connate water saturation. During gas production, the transformation of connate water into movable water introduces a unique water production mode, significantly impacting gas reservoir recovery. Current experimental and theoretical methods for assessing formation water mobility are static and do not address the transformation mechanism from connate into movable water. In this study, we considered dynamic changes in formation stress and proposed the mechanism for the transformation of connate water into movable water during depressurization, involving the expansion of connate water films and the reduction of pore volume. We developed a novel methodology to calculate the dynamic changes in movable and connate water saturation in tight reservoirs due to reservoir pressure reduction. Furthermore, we quantitatively evaluated the transformation of connate water into movable water in the Dongsheng gas field through laboratory experiments (including formation water expansion tests, connate water tests, and porosity stress sensitivity tests) and theoretical calculations. Results show that under original stress, the initial connate water saturation in the Dongsheng gas field ranges from 50.09% to 58.5%. As reservoir pressure decreases, the maximum increase in movable water saturation ranges from 6.1% to 8.4% due to the transformation of connate water into movable water. This explains why formation water is produced in large quantities during gas production. Therefore, considering the transition of connate water to movable water is crucial when evaluating water production risk. These findings offer valuable guidance for selecting optimal well locations and development layers to reduce reservoir water production risks.