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Abstract

The effect of relative permeability hysteresis on both CO₂ storage and oil recovery has been studied using a compositional simulator. The effects of process parameters such as water-alternating-gas (WAG) ratio and CO₂ slug size, and reservoir heterogeneity characteristics such as Dykstra-Parson coefficient and correlation lengths on CO₂ storage and tertiary oil recovery were simulated using hysteresis based upon existing correlations. Three different relative permeability and capillary pressure models for three different rock types in the reservoir were carefully constructed. Reservoir fluid PVT data were used to develop the Equation-of-State (EOS) model. A grid refinement study was performed to evaluate the numerical convergence behavior of the simulation model with the hysteresis option included. In the refined cases, it was necessary to apply a higher-order approximation scheme to reduce the numerical dispersion of the simulations. In addition, due to the application of very small gridblock sizes, physical dispersion was also taken into account. Experimental design and statistical analysis were used to understand the most influential factors on oil recovery, project net cash flow, and CO₂ storage. Optimization was carried out and response surfaces were constructed to quantify the effect of each parameter.

Introduction

The effect of relative permeability hysteresis on the geological storage of CO₂ in saline aquifers has been studied in recent years (Kumar et al., 2004; Ozah et al., 2005; Spiteri et al., 2005). Only two fluid phases (gas and brine) are needed to describe the injection of CO₂ in aquifers. In coupled CO₂ sequestration and Enhanced Oil Recovery (EOR) processes, the degree of complexity is higher due to the nature of multiphase flow of a multi-contact miscible displacement in an oil reservoir. Depending on temperature and pressure, three or more fluid phases (Guler et al. 2001) are present in the reservoir during CO₂ injection. Compositional simulation is needed  to account for the phase behavior effects that occur when CO₂ is injected into the oil reservoir. Compositional simulation of WAG injection for EOR purposes, with and without hysteresis-included, has been shown to predict different results in 2-D and 3-D cases (Christensen et al. 2000). In addition, Christensen et al. (1998) have shown that simulations of this process can have considerable compositional effects, therefore applying compositional simulation will give more accurate results than using black oil simulations.

Moreover, when the fluid saturations experience cyclic changes, relative permeabilities and capillary pressure data show hysteresis behavior. Hysteresis is defined as path-dependent relative permeability and capillary pressure curves during drainage and imbibition cycles. The imbibition oil and gas relative permeability curves are generally lower than the drainage curves at the same saturation. But the imbibition water relative permeability curve is slightly greater than the drainage curve. Hysteresis is greatest for the gas phase and most important for WAG processes.

For coupled EOR and geological storage of CO₂, one of the key issues is the effect and importance of the trapping and hysteresis on the amount of CO₂ remaining (stored) in the reservoir. If gas remains in the reservoir in the form of trapped gas, the risk of gas migration and its escape from the reservoir will be minimized. Some studies have been performed to investigate the effect of residual gas saturation on the amount of stored CO₂ in saline aquifers using compositional simulators (Kumar et al., 2004; Ozah et al., 2005) and black oil simulators (Spiteri et al., 2005). It should be noted that the degree of complexity of fluid flow in porous media in the studies which are involved in the coupled CO₂-EOR and sequestration is much higher than in the aquifer storage cases; therefore careful selection of relative permeability models and their associated parameters have an important role in the final results.