(173f) Natural Gas Recovery from Kerogen Nanopores

Existing strategies for oil and gas recovery are designed based on macroscopic properties of the produced hydrocarbon fluids. However, recent studies on source rocks revealed that properties of fluids stored in nanopores of organic constituent material kerogen deviate from the bulk behavior. Hence, the traditional equation of state and fluid properties correlations are no longer applicable. This, in turn, leads to added uncertainties in hydrocarbon in-place and recovery calculations for the source rocks that are rich in kerogen. In this paper, we seek to address the question at a fundamental level from the thermodynamics standpoint by simulating isothermal expansion of a quinary hydrocarbon mixture in model nanopore under typical subsurface conditions, and measuring the fluid composition and amount. Molecular Monte Carlo simulations are employed to investigate the equilibrium relationship between the bulk fluid at the outside of the pore and the remaining mixture inside during the stages of pressure depletion. The fluid stored in nanopores shows a composition that varies significantly with the pore size. The smaller the pore is, the heavier its mixture that is in equilibrium with the bulk fluid becomes. During the depletion, the small hydrocarbon molecules escape readily from the pores. The composition of the remaining fluid inside the pore thus becomes progressively heavier and viscous. We show that nanopore confinement limits significantly the release of hydrocarbon molecules from the pores with sizes less than 10nm. For each hydrocarbon component, a strong correlation exists between molar fraction of the component in the produced fluid with that remained inside the pore. This correlation can serve as the basis for establishing alternative methods for the engineering calculations.