A New Way of Compositional Simulation Without Phase Labeling

Abstract

Current relative permeability models rely on phase labeling, and cannot accurately capture the effect of compositional variations on relative permeabilities and capillary pressures in enhanced oil recovery (EOR) processes. Discontinuities in flux calculations not only cause serious convergence and stability, but also affects the estimated recovery factor. We developed a fully compositional simulation model using an equation of state (EoS) for relative permeabilities to eliminate the unphysical discontinuities in flux functions caused by phase labeling. In addition, we extended our relative permeability EoS to three phases. The model can capture complex hysteresis effects on three-phase relative permeability. The tuned model is used for simulation of multi-cycle WAG injection. The approach allows for a new search scheme to improve initial estimates for flash calculation. The results show increased robustness of high-resolution compositional simulation for both front calculations (recovery estimates) and convergence of flash algorithms. This paper provides a novel way forward to develop a fully compositional reservoir simulation based solely on continuous and robust equation-of-state relative permeabilities. In addition, this paper provides a detailed analysis of the effects of discontinuous phase labeling on simulation performance and accuracy for 1-D and 2-D water-alternating-gas flooding and three-hydrocarbon-phase flow. The results demonstrate the significant benefits of using an EoS for relative permeabilities.

Hysteresis effects of three-phase relative permeabilities on black-oil reservoir simulation under WAG injection protocols

“…Caudle et al (1951) were among the first to highlight the impact of hysteresis effects (hereinafter denoted as HEs) on the values of relative permeability of a non-wetting phase. Occurrence of such effects for the non-wetting and the intermediate wetting phases have been documented by a set of experimental (e.g., Oak, 1990;Kalaydjian et al, 1997;Suicmez et al, 2007;Alizadeh and Piri, 2014a;Chukwudeme et al, 2014;Moghadasi et al, 2016) and theoretical (e.g., Killough, 1976;Carlson, 1981;Larsen and Skauge, 1998;Blunt, 2000;Shahverdi and Sohrabi, 2013;Kianinejad et al, 2015;Ranaee et al, 2015Ranaee et al, , 2016Khorsandi et al, 2018) studies. A complete characterization of HEs for three-phase flow systems is still challenging due to complex pore-scale mechanisms driving fluid displacement.…”

“…This study is focused on black-oil simulators, which are widely used in the context of reservoir simulation applications because of their potential to obtain acceptable results with relatively low computational costs in cases where compositional effects are negligible (Ertekin et al, 2001;Khorsandi et al, 2018). Simulation of three-phase fluid flow in black-oil models takes into account the occurrence of mass exchange between oil and gas phases, according to the following set of equations (e.g., Chen et al, 2006) (1) 2( 3)where indices w, g and o respectively denote water, oil and gas phases; ] is the source/sink term of phase α evaluated at standard conditions; S α [-] [L 2 ], and v α [LT −1 ] respectively denote saturation, pressure, viscosity, density, relative permeability and Darcy velocity of the α-phase at the reservoir conditions; B α [-] is the formation volume factor.…”

Development of a fast EoS based compositional model for three-phase core flooding

“…The hysteresis effects were also considered in their threephase relative permeability model. They used their mode for simulation of multi-cycle WAG injection [14].…”