LAUSR

Abstract Current paper proposes a model to account for different pore sizes in shale and its influence on hydrocarbon distribution. Such a partitioning scheme provides a multiporosity-like approach where the fluid composition in different pore sizes varies due to size filtration and sieving effect. The proposed approach opens up new ways to interpret anomalous gas-oil ratios in shale. Low permeability shales are believed to form a considerable portion of the recoverable reserves in North America. Such an enhanced potential comes with new challenges and technical difficulties. Recent advances in high precision analytical tools have revealed that pore size distribution in shale reservoirs spans a wide range. Molecules in pores with different sizes may exhibit significantly different thermodynamics behavior. Rock fluid interactions and space hindrance effects play an important role when pore sizes become close to species’ molecular dimeters. The tight porous media in such situations can act as a semi-permeable membrane that selectively filters molecules based on their sizes. This effect can result in a composition difference between pores with large and small diameters in shale reservoirs (size filtration or sieving effect), with small pores mostly filled with smaller hydrocarbon molecules and large molecules residing in larger pores. To account for such a diverse behavior, this paper proposes a pore partitioning approach, which divides shale media into two different porosity systems: large and small pores. We use a modified version of the Peng-Robinson equation of state to model the equilibrium hydrocarbon distribution in large and small pores. Our thermodynamics calculations show that as pore dimeter decreases, the concentration of larger hydrocarbon molecules in those pores decreases because of size filtration. Considering the small pore size in shale and rock-fluid interactions, our current model was used to analyze the potential of different injection gases as improve recovery agents. Our results show that a higher pore wall affinity for CO 2 (compared to CH 4 and N 2 ) helps it reach deeper in small shale pores, making it a perfect fit for improve oil recovery from extremely tight media. Results show that our model provides a powerful tool to evaluate the complicated rock-fluid dynamics in liquid shales.