document preview

Abstract
This paper presents extensive laboratory results of unsteady state displacement of methane by super critical carbon dioxide SCO2 in consolidated reservoir core plugs. The fluid flow of the both phases is presented in terms of relative permeability using explicit methods. The main objective of this study was to investigate the feasibility of SCO2 injection for enhanced gas recovery for a newly discovered gas field situated in the North West Shelf of Western Australia.

The core-flooding experiments of SCO2-methane were carried out on three short plugs and one long vertical sample. The impacts of various parameters were broadly studied on the recovery efficiency and gas multiphase flow at pore scale. These were pressure, temperature, composition, injection-rate, and permeability heterogeneity. Results indicated that the recovery factor at CO2 breakthrough is a function of in situ gas composition, injection rate, and pore pressure. In contrast temperature, absolute permeability and core position factors moderately affected the recovery factor.

A new power model has been developed for interpolating experimental gas-gas relative permeability data. This model can accurately account for subsequent gas compositional changes during the displacement process.

Introduction
Conventionally, relative permeability is used to describe and model the multiphase-flow of immiscible fluids through porous medium. The analysis of such complex multiphase flow in porous media is normally ascribed as a Darcy-type formulation. The extension of Darcy’s law to include phase relative permeability concept appeared to have been first suggested by Muskat and Meres (1936) and co-workers Wyckoff and Botset (1936). Relative permeability of a phase was presented as a function of the phase saturation and a fraction of the pore volume that is occupied by the phase. At a given saturation, fluid flow in porous media could be the function of several macroscopic transport properties such as relative permeability, capillary pressure and dispersivity. Experimentally determined, these properties depend on fluid saturations, saturation history, fluid properties (viscosity, density and composition) and pore space morphology.

In the case of two gases flowing (SCO2 – methane) simultaneously through a porous medium, researchers interpret the flows behaviour in terms of gas dispersion and molecular diffusion. This means when the two gas phases are in contact in porous media, their interface will be a zone of miscibility ranges from one pure phase to another. Hence, effects of capillary force on the phase distribution are expected to be diminished because gas phase cannot create a finite contact angle with the pore walls. Both phases, as injected, tend to saturate the larger pore and then the smaller pores if the viscous forces are great enough to overcome the capillary forces that are produced by morphology of the porous media. As a result recovery efficiency will not be affected by the phase’s relative permeability.
On the other hand, in recent studies by Amin et al. (2010) and Sidiq and Amin (2010) an immscible interface between SCO2 and methane is documented. This finding allows the displacement of methane in porous medium by super critical SCO2 to be modeled in terms of relative permeability. Since the medium of the passage can effect the relative permeability of the flowing phases through its pore morphology and permeability heterogeneity. Whereas its wettability can only marginally influence the gases relative permeability as the gas phases are well acknowledged for being the most non-wetting phase.