Phase behavior of hydrocarbons in confined nanopores is quite different from that of the bulk. In confined space, the high capillary pressure between vapor phase and liquid phase, and depressed critical properties under confinement will all affect the in-situ phase behavior. According to the theory of adsorption-induced structural phase transformation in nanopores, we modify the molar volume term of the Peng-Robinson equation of state (PR-EOS) by considering the reduced mole number of fluids caused by absorption to describe the phase behavior of fluids under confinement. Then capillary pressure is coupled with phase equilibrium equations, and the resulting system of nonlinear fugacity equations based on the modified PR-EOS is solved to present a comprehensive examination of the effect of capillary pressure and confinement on saturation pressures. Binary mixtures of methane with heavier hydrocarbons and a real reservoir fluid from the Eagle Ford confined at different pore sizes are considered. The effect of capillary pressure and confinement on the phase envelop shifts are compared. The modified PR-EOS show that there exists a linear relationship between critical temperature shift and pore size reductions, a quadratic relationship between critical pressure shift and pore size reductions which are consistent with the experimental and molecular simulation results. The shift in the phase envelop of binary mixtures and Eagle Ford fluids show that both the capillary pressure and confinement decrease the bubble point pressures, while they oppositely influence dew point pressures. It is worthy to be noted that the effect of capillary pressure on phase envelop shifts will be suppressed when taking the critical point shifts caused by confinement into consideration. For Eagle Ford fluids, the effect of confinement on phase envelop shift is dominant compared with that of capillary pressure, and the capillary pressure cannot be overlooked when pore radius decreases to 50 nm. While the confinement begins to play an important role on the saturation pressures when pore radius decreases to 100 nm. In addition, the methodology presented in this study can be extended to the phase equilibrium calculations of multiple pores since the modified PR-EOS can provide a consistent phase behavior description of fluid molecules over the whole range of pore sizes.

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The phase behavior shifts of hydrocarbons confined in nanopores have been extensively verified with experiments and molecular dynamics simulations. However, the impact of confinement on large-scale reservoir production is not fully understood. This work is to put forward a valid method to upscale the pore-scale fluid thermodynamic properties to the reservoir-scale and then incorporate it into our in-house compositional simulator to examine the effect of confinement on shale reservoir production. Firstly, a pore-scale fluid phase behavior model is developed in terms of the pore type and pore size distribution (PSD) in the organic-rich shale reservoir using our modified Peng-Robinson equation of state (PR-C EOS) which is dependent on the size-ratio of fluid molecule dynamic diameter and the pore diameter. And the fluid composition distribution and PVT relation of fluids in each pore can be determined as the thermodynamic equilibria are achieved in the whole system. Results show that the initial fluid composition distribution is not uniform for different pore types and pore sizes. Due to the effect of confinement, heavier components are retained in the macropore, and lighter components are more liable to accumulate in the confined nanopores. Then an upscaled equation of state is put forward to model the fluid phase behavior at the reservoir-scale based on our modified PR-C EOS using a pore volume-weighted average method. This upscaled EOS is validated with the pore-scale fluid phase behavior simulation results and can be used for compositional simulation. Finally, two different reservoir fluids from the Eagle Ford organic-rich shale reservoir are simulated using our in-house compositional simulator to investigate the effect of confinement on production. In addition to the critical property shift which can be described by our upscaled PR-C EOS, capillary pressure is also taken into account into the compositional simulation. Results show that the capillary pressure has different effects on production in terms of the fluid type, leading to a lower producing Gas/Oil ratio (GOR) for black oil and a higher GOR for gas condensate. Critical property shift has a consistent effect on both the black oil and gas condensate, resulting in a lower GOR. It should be noted that the effect of capillary pressure on production is suppressed for both fluids with the shifted critical property.

Rock mechanical properties are critical for drilling, wellbore stability, and well stimulation. There are usually two laboratory methods to determine rock mechanical properties: static compression tests and acoustic velocity measurements. Rocks are heterogeneous, so there are significant differences between static elastic constants and the corresponding dynamic ones. Usually, static test results are more representative than dynamic methods but the static tests are time consuming and costly. Dynamic methods are nondestructive and less expensive, which are practical in the laboratory and field. In this paper, we compare the static and dynamic elastic properties of Eagle Ford Shale by triaxial compressive tests and ultrasonic velocity tests. Correlations between static and dynamic elastic properties are developed. Conversion from dynamic mechanical properties to static mechanical properties is established for better estimating reservoir mechanical properties. To better understand the relationship of static and dynamic mechanical properties, 30 Eagle Ford Shale samples were tested. According to the test results, the dynamic properties are considerably different from the static counterparts. For all tested samples, static Young’s modulus is lower than dynamic Young’s modulus, ranging from 55% to 90%. The difference of the static and dynamic Young’s moduli decreases with the increasing of confining pressure. The reason may be because the microcracks closed in high confining pressure. Correlations between static and dynamic Young’s modulus are developed by regression analysis, which are crucial to understand the rock mechanical properties and forecast reservoir performance when direct measurement of static mechanical properties is not available or expensive. There are no strong correlations between static and dynamic Poisson’s ratios observed for the tested samples. Two potentially major reasons for the discrepancy of the static and dynamic properties of Eagle Ford Shale are discussed. Lithology and heterogeneity may be the inherent reasons, and external causes are probably the difference in strain amplitude and frequency.

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