Lattice Boltzmann Simulations of Supercritical CO 2 −Water Drainage Displacement in Porous Media: CO 2 Saturation and Displacement Mechanism Hirotatsu Yamabe,* ,† Takeshi Tsuji, ‡ Yunfeng Liang, † and Toshifumi Matsuoka † † Environment and Resource System Engineering, Kyoto University, Kyoto, Kyoto 615-8540, Japan ‡ International Institute for Carbon-Neutral Energy Research (WPI-I2CNER), Kyushu University, Fukuoka, Fukuoka 819-0395, Japan * S Supporting Information ABSTRACT: CO 2 geosequestration in deep aquifers requires the displacement of water (wetting phase) from the porous media by supercritical CO 2 (nonwetting phase). However, the interfacial instabilities, such as viscous and capillary fingerings, develop during the drainage displacement. Moreover, the burstlike Haines jump often occurs under conditions of low capillary number. To study these interfacial instabilities, we performed lattice Boltzmann simulations of CO 2 −water drainage displacement in a 3D synthetic granular rock model at a fixed viscosity ratio and at various capillary numbers. The capillary numbers are varied by changing injection pressure, which induces changes in flow velocity. It was observed that the viscous fingering was dominant at high injection pressures, whereas the crossover of viscous and capillary fingerings was observed, accompanied by Haines jumps, at low injection pressures. The Haines jumps flowing forward caused a significant drop of CO 2 saturation, whereas Haines jumps flowing backward caused an increase of CO 2 saturation (per injection depth). We demonstrated that the pore-scale Haines jumps remarkably influenced the flow path and therefore equilibrium CO 2 saturation in crossover domain, which is in turn related to the storage efficiency in the field-scale geosequestration. The results can improve our understandings of the storage efficiency by the effects of pore-scale displacement phenomena. ■ INTRODUCTION CO 2 geosequestration is one of the promising solutions for reducing carbon emissions and global warming. 1−3 The estimation of geological CO 2 storage capacity, evaluation of leakage risk, and enhancement of storage efficiency are current focuses and require understanding of microscopic CO 2 flow in porous media, such as the fingering phenomenon. To examine CO 2 flow in porous media, a number of experimental studies have been conducted. The preceding experiments can be divided into two approaches: core-flooding experiments using magnetic resonance imaging (MRI) or X-ray computed tomography (CT) 4−9 and the observation of fluid displacement in fabricated micromodels. 10−14 With X-ray CT scanners or MRI, we can measure the saturation and fluid distribution changes during core flood experiments with CO 2 . 4−8 However, the microscopic fluid state cannot be detected with medical CT scanners due to not high resolution (millimeter scale) compared with pore sizes. The resolution of microfuocus CTs are high, but it takes a long time to take one image unless fast synchrotron-based sources are used. 9 Recent advances in microfabrication have enabled us to create arbitrary micropore network models. The experimental studies with two- dimensional microporous media have been conducted to reveal the mechanisms of immiscible fluid displacement. Despite the use of simple two-dimensional porous media, the contributions of these experimental studies to knowledge of fluid dynamics are considerable. 10−14 In general, understanding the flow of multiphase fluids in porous media has been a subject of great interest over a wide range of scientific and engineering disciplines. 11,14−20 Lenor- mand et al. have discussed the pore-scale displacement mechanism of the drainage process from the standpoint of viscous and capillary forces. 21 The effects of these forces on drainage displacement processes can be characterized by two dimensionless numbers: the capillary number (Ca), which is defined as Ca = μ in U in /σ, where μ in , U in , and σ are the viscosity of injected fluid, velocity of the injected fluid, and interfacial tension, respectively; and the viscosity ratio (M), defined as the ratio of viscosities of the nonwetting and wetting fluids. In subsurface rocks, the CO 2 phase usually behaves as a nonwetting phase, thus the displacement process in CO 2 Received: September 15, 2014 Revised: November 25, 2014 Accepted: November 26, 2014 Published: November 26, 2014 Article pubs.acs.org/est © 2014 American Chemical Society 537 dx.doi.org/10.1021/es504510y | Environ. Sci. Technol. 2015, 49, 537−543