Our research is focused on the basic science and engineering of hydrocarbon phase behavior and flow at nano, mico (pore), and macro (reservoir) scales. We believe in flexibility while attacking research problems and looking in directions that sometimes are fundamentally different from what others have done. This can result in high-impact research solutions. We have applied this research philosophy to multiple problems in this research area in collaboration with other faculty and researchers. 

Some highlights of our research are listed below:


AICheJ_2016Hydrocarbon phase behavior in nano capillaries

Phase behavior in shale reservoirs remains a challenging problem in the petroleum industry due to several complexities. One complexity arises from strong surface-fluid interactions in shale nanoscale pores. Currently, there are limited experimental data for hydrocarbon phase behavior in shale systems. In this multidisciplinary research , we have investigated the hydrocarbon phase change in nanoscale capillaries using a novel experimental approach. Our group in collaboration with Prof. Lutkenhaus‘s group (Chemical Engineering), for the first time, used differential scanning calorimetry to accurately measure the effect of confinement on hydrocarbon bubble point in 4.3 nm and 38.1 nm model porous materials. 



Multi-scale reservoir simulation using lattice Boltzmann method 

Fluid flow and transport in shale gas or oil reservoirs exhibit coupled solid/fluid interaction at several scales. Current approaches often do not account for the real physics in small scales. In this research, we apply the lattice Boltzmann method for modeling fluid flow at various scales. Our group in collaboration with Prof. Gildin‘s group (Petroleum Engineering) have worked on this problem. Thanks to their efforts, for the first time, we have developed a fractured reservoir simulation model based on the lattice Boltzmann method. In collaboration with Prof. Nasr-El-Din‘s group (Petroleum Engineering), for the first time, we have applied this method to simulate fracture acidizing. 



Asphaltene-rich liquid saturation at PVI=0.3

Asphaltene-rich liquid saturation at PVI=0.3

Compositional simulation of asphaltene precipitation during CO2 Injection using CPA-EOS

Numerical modeling of asphaltene precipitation in petroleum reservoirs is important in relation to possible precipitation and productivity loss around the wellbore in the producing well. Current reservoir compositional models rely on cubic equations of state for asphaltene precipitation. The cubic equations, despite their relative reliability in describing reservoir fluids phase behavior, become unreliable in asphaltene-rich phase description. In this research, we have implemented the CPA-EOS in compositional modeling of asphaltene precipitation during CO2 injection. Our efficient algorithm reduces significantly the additional computational cost from the incorporation of the CPA-EOS.