Two-Phase Flow in Volatile Oil Reservoir Using Two-Phase Pseudo-Pressure Well Test Method

Abstract

Abstract When the bottomhole pressure (BHP) of volatile oil reservoirs falls below the bubblepoint pressure, two phases are created in the region around the wellbore, and a single phase (oil) appears in regions away from the well. The oil relative permeability reduces towards the near-wellbore region due to increasing gas saturation. This behaviour is quite similar to a gas-condensate reservoir below the dew-point, where the gas relative permeability is reduced due to the existence of a liquid bank around the wellbore. There are numerous publications in the literature concerning the behaviour diagnostic and well deliverability calculation in the case of gas-condensate reservoirs. However, the behaviour of volatile oil reservoirs is not well understood. This paper aims at understanding the behaviour of volatile oil reservoirs. We used reservoir compositional simulations to predict the fluid behaviour below the bubblepoint, and then exported the flowing bottomhole pressure to a well test package to diagnose the existence of different mobility regions. In this study, the applicability of the two-phase pseudo-pressure method on volatile and highly volatile oil reservoirs was investigated, and it was found that this method is a very powerful tool for the prediction of true permeability and mechanical skin. Also, this method is capable of distinguishing between mechanical skin and condensate bank skin, which can be very helpful for designing after-drilling well treatment and IOR process designs. Introduction In gas-condensate reservoirs, retrograde condensation occurs when the flowing bottomhole pressure declines below the dew-point pressure, creating four regions in the reservoir with different liquid saturations. Away from the well, an outer region has the initial liquid and gas saturation. Next, nearer the well, there is a rapid increase in liquid saturation and a decrease in the gas mobility where the liquid still is immobile. Closer to the well, an inner region is formed where liquid saturation is higher than the critical condensate saturation and both oil and gas phases are mobile. Finally, in the immediate vicinity of the well, there is a region with a lower liquid saturation due to capillary number (the ratio of viscous to capillary forces) effects. Such a region has been inferred from a number of experimental core studies at low interfacial tension and high flow rates. The existence of the fourth region is important because it counters the reduction in productivity caused by liquid drop-out. The various mobility zones described above can be identified by well test analysis, using a variety of analytical and numerical models(1–3). Well test analysis is now commonly used to identify and quantify near-wellbore effects, reservoir behaviour (i.e. zones of different mobilities and storativities) and reservoir boundaries. Finding all of this information from well tests in gas-condensate reservoirs, however, is challenging. This is due to changes in the composition of the original reservoir fluid and the impact of wellbore dynamics. Nonetheless, gas-condensate flow behaviour is now reasonably well understood.