Shale and tight rocks are associated with tiny pore throats, on the order of nanometers, and subsequently large capillary pressure. The calculation of the minimum miscibility pressure (MMP) in nanopore space is complex because the phase compositions from flash calculations are affected by capillary pressure. This paper examines the effect of capillary pressure on the calculation of MMP using cubic equation-of-state (EOS) and three techniques: the method of characteristics (MOC), multiple mixing cells, and slim tube simulation. Ternary mixtures of hydrocarbons and real reservoir fluids are considered. Using MOC, capillary pressure changes both liquid and vapor compositions and alters the tie lines. The reason for the change in the MMP is illustrated graphically with ternary and quaternary diagrams. The modified slim tube simulation tool is also used to estimate MMPs of CO2 with Bakken and Eagle Ford oil. We use an upgraded flash calculation in the slim tube procedure to estimate MMPs with large capillary pressures for real reservoir fluids. The results show that high capillary pressure changes liquid and vapor phase compositions and this change tends to either decrease or increase the CO2 MMP depending on the original oil composition. The importance of MMP for gas injection in shales as well as the effect of large gas-oil capillary pressure on the characteristics of immiscible floods in shales is discussed.


Unconventional oil and gas resources, such as shale gas, tight oil, and shale oil contribute significantly to hydrocarbon production in North America (Hakimelahi and Jafarpour, 2015). Although strong oil and gas demand and technological progress have led to major unconventional resources production increase in the USA, and worldwide, in recent years, there are still uncertainties in understanding the complex behavior of such reservoirs as reported by Dong et al (2011). Despite multiple research studies in the area, the altered phase behavior of hydrocarbon fluids due to large gas-oil capillary pressure in the confined space of shales and tight rocks is not yet fully understood. Numerous research studies have been conducted to investigate the phase behavior of reservoir fluids in confined space of shale reservoirs. Based on the previous studies by Zarragoicoechea et al (2004) and Singh. et al (2009), the confined space in shale nanopores can alter the phase behavior of petroleum mixtures either by changing the petroleum mixture constituent components critical properties, such as critical pressures and temperatures, or such an alteration can be owing to large gas-oil capillary pressure in confined nanopores which is proposed in the studies by Shapiro et al (2000), Nojabaei, B. et al (2013) and Sugata P. Tan. et al (2015).

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