Experimental Investigation of Retrograde Condensation in Porous Media at Reservoir Conditions

Abstract

Abstract The phenomena of retrograde condensation and the flow of gas-condensates in porous media under simulated reservoir conditions have been studied experimentally. Depletion tests on a 6 component synthetic gas mixture with a dew point of 33 MPa (4800 psi) at 37.8 degrees C were conducted in glass micromodels and long sandstone cores. Micromodels with homogeneous and heterogeneous patterns, were employed to observe the patterns, were employed to observe the mechanisms of gas-condensate flow at the pore level. The micromodelling results were then employed in designing experiments in vertical and near horizontal cores to study the phenomena at larger scale and in evaluating the recovery and composition of gas and gas condensates. The observations made on the micromodels revealed that whilst condensate continuity was maintained through thin films, its growth was observed to be non-uniform and strongly dominated by capillary and gravitational forces. The depletion tests on the cores verified pore level observations, and in particular, the minimum condensate saturation for the downward flow of condensate was found to be quite low. Implications of the results on gas-condensate laboratory experimental methods have been briefly discussed. Introduction In a rich gas reservoir or the gas cap of a volatile oil reservoir, the reduction of reservoir pressure below the dew point causes liquid to condense from the initially single phase fluid. The accumulation of condensate phase fluid. The accumulation of condensate usually leads to a significant drop in well productivity and the loss of valuable liquid productivity and the loss of valuable liquid reserves. The selection of the most suitable recovery scheme depends on the degree of understanding of various phenomena occurring in the reservoir during the various stages of recovery. It is generally believed that the flow behaviour of gas-condensate in porous media is different frost that of gas-oil and water-oil systems. However, the number of reported studies relevant to gas-condensate flow phenomena is very limited, and it is quite common to apply information, such as the relative permeabilities and the critical liquid saturation, generated frost related studies on gas-oil systems. Gasoline-nitrogen and water-gas systems have been used to simulate gas-condensate flow in cores resulting in a critical flow saturation ranging frost 30% to 50% of the pore volume. Saeidi and Handy studied the retrograde condensation of methane-propane mixtures, with a maximum liquid condensate saturation of 18%, in a horizontal sandstone core. No flow of condensate was observed with an interstitial water saturation of 30% or in the absence of connate water. They, however, found that the shapes of relative permeability curves far condensing systems and vapourising systems (oil-gas) were different. Gravier et al studied the condensate flow behaviour of a methane-pentane-nonane mixture in eight rock samples taken from a carbonate reservoir with permeabilities ranged from 0.5 to 40 10(-3)mu m2 permeabilities ranged from 0.5 to 40 10(-3)mu m2 (0.5 to 40 millidarcy). P. 527