Optimization of Tertiary Water-Alternate-CO2 Injection

Abstract

Abstract A new analytical model for the tertiary miscible CO2-WAG is developed. The model is based on analytical solutions of non-self-similar and self-similar problems for a system of hyperbolic equations of mass conservation laws. Explicit formulae allow to analyze the propagation of displacement and phase transition fronts, mechanisms of trapping of oil with the sequential injection of water and gas slugs, mobility ratios on shock fronts and the dynamics of water and gas slugs. Six different regimes for gas-water injection, after waterflooding, have been distinguished depending on the water-gas ratio, They differ from each other by the structure of the mixture zone and by the mechanisms of displacement caused by two-phase displacement and phase transitions phenomena. The analytical model presented shows that the higher the WGR the lower the recovery, but the more favourable is the mobility ratio on the displacement front, which suggest the existence of an optimal water-gas ratio (WGR) for the tertiary miscible WAG. As it follows from the analytical model there does exist a minimum slug size which prevents gas breakthrough via all the water slugs. With the injection of thinner slugs a connected gas network appears in the reservoir and it catches the front of water creating an unstable gas-oil front at the presence of the connate water only. So, simultaneous injection of gas and water, which corresponds to the reduction of slug size to the zero limit, is not an optimal WAG regime as it was suggested in the literature. On the other hand, the thinner the slugs the higher the displacement efficiency, which suggest the existence of an optimal slug size with the tertiary miscible WAG. Introduction Tertiary miscible gas injection after waterflooding is an effective method of improved oil recovery. The mechanism of an additional recovery is the dissolution of the low mobility residual oil in the gas injected. Nevertheless, the injected gas has a high mobility, compared to the water one, and this leads to unstable displacement because the injected gas moves mainly in highly permeable zones resulting in low areal sweep efficiency. Due to the lower mobility of water, when compared with oil mobility, the injected gas cannot displace oil from the low permeable zones which have not been swept during the waterflooding. The displaced oil forms a high viscosity bank in front of the injected gas improving sweep, but not significantly. Also, some residual oil in the gas swept zone remains unrecovered due to the blocking by water during the primary flood, this water is not removable by the gas injected. Injection of water during the tertiary gas flood decreases the mobility of the injected fluid. So, the displacement from the water-swept zones is occurs with a higher sweep coefficient when compared with the tertiary gas flooding. At some water-gas ratio the mobility of the gas-water system is even higher than the water mobility, so the injected fluid enters in some zones which that were not swept during the waterflooding. The local redistribution of the reservoir pressure near to water and gas slugs, which happen due to the different viscosities for water and gas, also results in some improvement of the sweep efficiency. The effect of the increased sweep efficiency caused by the use of water during the gas flooding has been observed in a number of laboratory simulation studies and in pilot tests. The physical mechanisms of the incremental recovery using miscible WAG can be captured by a 1-D model that takes into account interaction between water and gas slugs during the sequential injection, phase transitions and effects of phase compositions on relative permeabilities and phase viscosities. This model, however, does not take into account areal heterogeneity and viscous fingering. P. 575