The Condition of Capillary Condensation and Its Effects on Gas-In-Place of Unconventional Gas Condensate Reservoirs

Abstract In shale gas reservoirs, the adsorption of gas can be multi-layer adsorption because of the presence of small pores and heavy hydrocarbon components in the kerogen portion of the source rock. Particularly, in unconventional gas condensate reservoirs, the gas can become condensate, filling the pores at pressures different from the dew-point pressure of the bulk fluid. The commonly used Langmuir isotherm does not provide a valid model for capillary condensation because it is based on the assumption that the adsorption mechanism is a monolayer adsorption. To solve this problem, we developed a method to compute the adsorption isotherms of capillary condensation for multi-component hydrocarbons, based on the general Kelvin equation. However, this method was limited to pressures below the lower dew-point pressure, due to the assumption of incompressible liquid and closeness to the dew-point pressure of the bulk fluid. In this work we extended the adsorption and gas in place models for capillary condensation to the high pressure range. Based on fundamental thermodynamic principles, we developed an iterative method to determine the dew point shift caused by pore confinement. This method is applied to determine the phase of the confined hydrocarbons, as well as to compute the hydrocarbons in place at the initial reservoir condition. Furthermore, we analyzed the properties of the confined fluid and checked the capillary condensation effects on the gas in place caused by fluid composition, pore size distribution, temperature, and pressure. This methodology is also applied to the Eagle Ford shale formation. The analysis results show that the gas in place can be underestimated with the conventional model by more than 10% if the initial pressure is lower than the shifted dew-point pressure.