Phase Behavior of Hydrocarbon Fluids in Shale Systems from Molecular Simulation
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Production from shale reservoirs is getting more attention from the oil industry. However, the shale is not understood as well as conventional reservoirs. One complexity is the unclear fluid phase behavior in shale nanopores. Since the knowledge of the hydrocarbon phase behavior is fundamental for the petroleum reservoir simulation, the phase behavior in shale reservoirs has received significant attention in recent years. Since hydrocarbon fluids are stored inside nanopores of shale matrices, a great interaction exists among the pore boundary and fluid molecules. Thus, fluid phase behavior in a shale reservoir is substantially different from conventional behavior. Due to this interaction, the fluid molecules are distributed heterogeneously inside the nanopores and the phase diagrams are shifted under confinement. Molecular simulation techniques have been developed in previous studies for an advanced performance in the phase behavior description under confinement. In this work, a new molecular simulation method, gauge-GCMC, is presented to study the phase behavior of multiple component fluids considering the confinement effect. This method is verified by matching the phase diagrams of simple and complex hydrocarbons with theoretical results and the simulation data from other techniques. The simulation results show that the density differences between vapor and liquid phases are reduced while critical densities increase under confinement. Also, the confined phase behavior has a great change in the fluid compositions, because heavier components have a stronger adsorption effect than that of lighter components. Shale rocks usually have a wide pore size distribution (PSD) and the traditional single pore-size models are not accurate enough to represent a real shale system. To understand the PSD effect on the phase behavior, the gauge-GCMC is used to generate phase diagrams based on two types of cylindrical models (single pore and multiple pores, including one based on Eagle Ford shale rock). The simulation results show that with an increasing pore size, the phase equilibrium properties approach the bulk values. In addition, the small pore causes a stronger shift in the phase diagram, compared with large pores. The small pores are filled before the large ones, which means that liquid condensation will first happen in the small pores. In the Eagle Ford test, it is possible to use a single pore model with a 10 nm diameter to represent the phase diagrams of this complex pore system. To investigate the contribution from boundary material on the fluid phase behavior, two types of pore models (slit and cylinder), which are built from three materials (two inorganic minerals and one kerogen), are used to generate the phase diagrams of pure fluids (Cv1 and Cv3) and one ternary fluid (Cv1/Cv3/nCv5). Under confinement, liquid densities are reduced while vapor densities are increased in both pore models. Critical points are shifted to lower densities. For the ternary case, a large shift of the nCv5 composition is shown in the vapor phase ternary diagrams, while only small changes have been observed in the liquid composition. When the temperature increases to one typical shale condition, phase separation of the ternary fluid is available in slit pore tests, while only one phase is formed in tests of cylinder pores. Based on the comparison of all results, the cylinder pore, which has more adsorption surface area, can provide a stronger adsorption effect than the slit pore. The calcite models have a greater confinement effect on fluid properties, and the other two materials cause the similar shift effect on phase diagrams.
Jin, Bikai (2018). Phase Behavior of Hydrocarbon Fluids in Shale Systems from Molecular Simulation. Doctoral dissertation, Texas A & M University. Available electronically from