Abstract: In this paper, a general framework of theoretical models and algorithm is developed to predict phase envelopes (saturation points) and quality lines of shale gas and oil in nanopores. The equation of state (EOS) and the modified Young−Laplace equation are used to take into consideration the effect of phase behavior and capillary pressure on phase envelopes, respectively. The Zuo and Stenby parachor model is applied to determine interfacial tensions between the vapor and liquid phases. In addition, a critical property shift of pure components is utilized to account for the impact of nanopore confinement on phase envelopes. The algorithm has proven to be robust for generating phase envelopes including critical points, cricondentherms (maximum temperatures), and cricondenbars (maximum pressures) for a variety of fluids at different compositions, vapor mole fractions (quality lines), and pore sizes. The models and algorithm are then used to explain the recently measured data of normal boiling point or bubble point temperatures for pure n-heptane in type I kerogen, binary mixtures of n-pentane + n-hexane and n-pentane + n-heptane, and a ternary mixture of n-pentane + n-hexane + n-heptane in the nanofluidic devices. For pure n-heptane in type I kerogen, with a presumption of nanopores being completely wetted by the liquid phase, the models agree well with the experimental data within a reasonable range of type I kerogen nanopore distributions in the presence of capillary pressure effect only as well as both capillary pressure and nanopore confinement effects. However, for the binary and ternary mixtures in the nanofluidic devices, the complete wettability assumption seems no longer valid. The wetting fluid−wall interaction parameter (λ) is then adjusted to match the experimental data at the nanopore radius of 5 nm. The adjusted parameters are λ = −142.2 ∼ −167.5 and λ = −14.0 for the three tested binary and ternary mixtures in the presence of capillary pressure effect only as well as both capillary pressure and nanopore confinement effects, respectively. The models provide not only good predictions at other radii but also a correct trend for the mixtures in the presence of capillary pressure effect only but a wrong trend against the experimental data in the presence of both capillary pressure and nanopore confinement effects. In addition, in the presence of both capillary pressure and confinement effects, a decrease in bubble and dew point pressures with decreasing pore radius is observed for shale gas and oil. For gas condensate mixtures, field production data show that produced liquid and gas ratios decrease even at reservoir pressures above bulk retrograde dew points. It is obvious that the model with critical property shift contradicts the field observation. More research activities in this area are required. Although in the presence of capillary pressure effect only, a decrease in bubble point pressures is estimated for shale oil, an increase in dew point pressures is predicted for shale gas with decreasing pore radius.