Comp. Part. Mech. (2016) 3:277–289 DOI 10.1007/s40571-015-0098-8 Effect of wettability alteration on long-term behavior of fluids in subsurface Uditha C. Bandara 1 · Bruce J. Palmer 2 · Alexandre M. Tartakovsky 2 Received: 30 March 2015 / Revised: 7 December 2015 / Accepted: 17 December 2015 / Published online: 13 January 2016 © OWZ (outside the USA) 2016 Abstract Wettability is an important factor affecting fluid behavior in the subsurface, including oil, gas, and super- critical CO 2 in deep geological reservoirs. For example, CO 2 is generally assumed to behave as a non-wetting fluid, which favors safe storage. However, because of chemical heterogeneity of the reservoirs, mixed wettability conditions can exist. Furthermore, recent experiments suggest that with time, the wettability of super-critical CO 2 may change from non-wetting to partially wetting due to changes in electro- static interactions. These changes are caused by chemical reactions between dissolved CO 2 and its environment. To date, the effect of wettability alteration and mixed wettabil- ity on the long-term fate of injected CO 2 has not well been studied. Here, we use the multiphase pairwise force smoothed particle hydrodynamics model to study complex pore-scale processes involved in geological CO 2 sequestration, includ- ing the effect of spatial and temporal wettability variations on long-term distribution of CO 2 in porous media. Results reveal that in the absence of dissolution of supercritical CO 2 and precipitation of carbonate minerals (mineral trapping), the amount of trapped supercritical CO 2 significantly decreases as the wettability of the porous media changes from brine-wet to partial-wet or CO 2 -wet. Keywords Smoothed particle hydrodynamics · Lagrangian particle method · Multiphase flow · Pore- scale flow · CO 2 sequestration wettability alteration B Alexandre M. Tartakovsky Alexandre.Tartakovsky@pnnl.gov 1 South Florida Water Management District, West Palm Beach, FL, USA 2 Pacific Northwest National Laboratory, Richland, WA, USA 1 Introduction Geological CO 2 sequestration is a process of injecting and storing CO 2 in permeable geological formations. Ensuring that long-term safety is crucial for CO 2 sequestration to become a practical tool for reducing the amount of green- house gases in the atmosphere. Here, the long term is defined as the period ranging from several hundred years to several thousand years [1]. Injection sites are typically selected to be more than 800 m deep, where temperatures exceed 31 ◦ C and pressures are greater than 7.4 MPa (i.e., critical point of CO 2 ). At these depths, CO 2 behaves as a supercritical fluid (sc-CO 2 ) with density and viscosity smaller than those of an ambient fluid (e.g., brine). Because of positive buoyancy, sc-CO 2 may rise upward— unless it is stopped by the low-permeability cap rock (a phenomenon known as structural trapping). The sc-CO 2 also can be trapped within a geological for- mation by capillary forces as disconnected blobs (residual trapping). Over longer periods of time, sc-CO 2 dissolves in the ambient fluid and produces a weak acid, which can react with the minerals in the porous matrix to form carbon- ate minerals. This trapping mechanism is known as mineral trapping. Together with the mineral trapping capacity, the cap rock’s capillary sealing potential and residual trapping capacity play a major role in the long-term effective storage of CO 2 . The capillary entry pressure of sc-CO 2 is controlled by the brine/sc-CO 2 interfacial tension in saline aquifers. The entry pressure, wettability of the porous media, and pore size dis- tribution all determine the capillary sealing potential and residual trapping capacity of the aquifer [2–5]. Although it is generally assumed that sc-CO 2 is the non-wetting phase, in most hydrocarbon-bearing aquifers, sc-CO 2 behaves as a partially wetting phase (contact angle ≈ 90) [4, 6]. Chemi- cal heterogeneity of the reservoir soil may lead to spatially 123