Phase Behavior of Hydrocarbons in Shale Nanomatrix-Fracture System: Experiment and Simulation

Abstract

Currently, the methods of nanofluidic chip and molecular dynamics simulation have been widely applied to characterize the effect of nanoscale confinement on the fluid phase behavior in shale rocks. However, most of the published literatures just concentrate on the pure nanoscale pores. Actually, in shale rocks, the phase transition phenomenon of fluids is happened in a nanomatrix–fracture system, which highly differs from the pure nanoscale pores. In this work, we combine the methods of experiment and simulation to address the phase behavior of hydrocarbons in a nanomatrix–fracture system, which can effectively represent the actual pore space of fluids in shale. A new experimental device for the fluid phase behavior is firstly developed in this study, which is based on the conventional PVT test equipment. But for this newly-proposed device, the test cell is separated into two connected spaces. During experiment, one of them is filled with nanoporous material to represent the shale nano-matrix, and the other one is used to simulate the fracture system. Then, by using this device, through a step-wise reduction on the test cell volume, the bubble point pressure of a hydrocarbon mixture (C1/C8) is tested. The applied nanoporous materials in this study include MCM-41 (pore size: 4 nm) and SBA-15 (pore size: 2.5 nm). Through a comparison, the effect of nanopore size is analyze. Thereafter, the obtained experimental data are compared against the simulation results of our previous proposed mathematical model to discuss the effect of fracture system. Simultaneously, a set of Grand Canonical Monte Carlo (GCMC) simulation runs are also performed for the microscopic mechanisms for the nanoconfinement effect on fluid phase behavior. The obtained bubble point pressures of C1/C8 mixture in the SBA-15 and MCM-41 porous systems are 4.65 MPa and 4.80 MPa respectively. They are lower than the that of the pure bulk fluids (5.07 MPa). It can be found that with the nanopore size reduces, the deviation is obviously increased. Then, the experimental data is compared with the calculation results of our mathematical model (4.22 MPa and 4.37 MPa), it is found that without the consideration of fracture system, the bubble point pressure of hydrocarbons can be underestimated. Furthermore, based on the GCMC simulation results, it is found that the wettability characteristics of shale rock can significantly impact the phase behavior of hydrocarbons, while the pore size distribution in shale typically controls fluid phase transitions during production. This study provides a novel experimental method to characterize the fluid phase behavior in nanoporous shale rocks. Some important new insights are obtained to understand the complicated phase transition phenomenon in shale reservoirs.