The design of a CO2 injection project mainly depends on the results of reservoir models. Nevertheless, it is recognized that these models generally lack physico-chemical data. This issue becomes more important for storage options, such as deep saline aquifers, for which economically driven data collection and archiving have not been performed. Among these physico-chemical data, fluid/fluid and rock/fluid interactions have been long recognized to govern fluid distribution and behavior in the porous media. This paper focuses on rock/fluid interactions with the host formation, by means of the wettability, which is one of the controlling parameters of the remaining fluid saturations, capillary pressure and relative permeability; hence conditioning the performance of any CO2 operation. The first part of this paper presents CO2 and N2 injection experiments in a carbonate core sample. Two different wettability conditions were investigated: water-wet and intermediate-wet. Thermodynamic conditions (pressure, temperature and water salinity) are representative of storage conditions and were the same for the entire core flooding experiments. Multirate experiments were conducted with in-situ saturation monitoring and enhanced interpretation workflow (heterogeneous approach) of the production curves in order to obtain relevant and complete sets of kr and Pc data. The second part is devoted to visualization experiments. CO2 injections were performed in glass micromodels, under the same conditions, in order to track the fluids distribution as a function of the thermodynamic and the wettability conditions. Using this approach, we showed, on the one hand, that at the core (carbonate) and pore (micromodels) scale the CO2 does not wet the solid surface when the porous media is water-wet. On the other hand, if the porous media presents an intermediate wettability, the CO2 partially wets the substrate having significant effect on water mobility (krw). In all cases the results at the core scale were consistent with those at the pore scale. Finally, we discuss the consequences of such CO2 wetting behavior in terms of fluids distribution in the porous media, injectivity level and seal efficiency of the caprock since all these mechanisms have a direct impact on CO2 storage capacity and sustainability of any prospect site. Introduction In CO2 geological storage projects, two critical issues must be addressed to make sure that this process is a secure and feasible strategy to stabilize carbon dioxide concentration in the atmosphere: the location and distribution of the injected CO2 in the reservoir, and the demonstration that it will remain stored in the long term; that has been defined by the IEA-GHG1 as a period ranging from several hundreds to several thousands years. The first issue refers to CO2 behavior in the reservoir rock and the second to its eventual invasion of the caprock, a low permeable and usually shaly porous material saturated with water. This paper addresses the effects of different wettability scenarios on both issues. Wettability is defined as the tendency of one fluid to spread on or adhere to a solid surface in the presence of other immiscible fluids.2 In the case of a CO2 flooding operation; it determines the fluid distribution in the reservoir because it affects the quantity displaced as well as how the displacement proceeds. When displaced, the wetting fluid will occupy the small pores and will be present in the largest pores as a film on the rock surface. The existence of such a film enhances the continuity of the wetting phase, affecting the petrophysical properties of the reservoir; among them the relative permeability and the capillary pressure curves, and therefore the injectivity level associated to a reservoir formation.3 * Now with Gaz de France (GdF)

The saturation profiles are routinely measured during Special Core Analysis (SCAL experiments). Several ways exist to use this information in the inversion procedure of the relative permeability data. To date, the local saturation profiles are either included in a global objective function that is minimized during the inversion process, or smoothed and used as input data in the simulation, which leads to non smoothed simulated pressure drop. None of these methods permit to reproduce the local saturation fluctuations that are measured during coreflooding experiments. Our approach has the advantage to take benefit from these fluctuations to characterize the petrophysical properties for a given rock-type. In this paper, the methodology is first recalled and illustrated on a synthetic case. It is based on upscaling techniques applied in reservoir simulation. Both the stabilized and transient saturation profiles are analyzed to evaluate the local properties. The quality of the history matching is significantly improved. In addition, both kr and Pc-curves are obtained from only one experiment and the variability of these parameters with the heterogeneity is also investigated. This estimated interval of confidence for kr and Pc can be very useful to perform uncertainty studies at the reservoir scale. The Pc-curve interval of confidence determined with this method on a carbonate sample, is in good agreement with the variability observed with several centrifuge experiments performed on sister plugs. Finally an alternative approach derived of the heterogeneous method is proposed, which allows a very quick acquisition of all the information relative to kr and Pc during a multi-rate flow experiments. Introduction Petrophysical parameters assessment Both relative permeability (kr) and capillary pressure (Pc) curves are key factors for assessment and prediction of the hydrocarbon recovery of a field. Representative curves are routinely obtained through SCAL (Special Core Analysis Laboratory) studies, in operating conditions as close as possible of reservoir conditions. These conditions mainly concern the thermodynamic conditions (pressure, temperature), the reservoir stress (overburden pressure), the nature of the fluids (synthetic reservoir brine, live oil), the initial saturation state (low Swi value) and the in-situ wettability (preserved samples or restored wettability through an aging process at Swi). Relative permeabilities are usually determined from flow experiments performed on core samples using either the UnSteady-State (USS) or the Steady-State (SS) method, where either one or two fluids respectively are injected. The centrifuge technique can also be used but not at full reservoir conditions (Ruth, 1997; Chardaire et al., 1992). Whatever the method used, the experimental results must be interpreted using capillary pressure curves. Virnovsky et al. (1998) proposed an analytical method to correct the SS data for capillary pressure. However, numerical simulations are needed for both USS and SS because a complete analytical solution does not exist. The kr curves can either be optimized in order to history match the experimental data knowing the Pc curve (from another experiment) or both kr and Pc curves can be optimized simultaneously (Chardaire et al., 1992; Helset et al., 1998). More recently, it has been shown that both kr and Pc curves can be determined at reservoir conditions using the semi-dynamic approach (Lombard et al., 2002). The main advantage of this method is to establish several equilibrium states between the viscous and the capillary forces within the sample by injecting one fluid while the other circulates at the outlet face. These equilibrium states enable the determination ofboth the kr of the injected phase and the Pc curve. The kr of the displaced phase can also be obtained by history matching of transient evolution of the pressure drop.

Summary Secondary- and tertiary-recovery processes based on gas injection can extend the life of waterflooded reservoirs by maximizing the oil recovery. However, the injection strategy needs to be studied carefully to optimize the overall sweep efficiency. In particular, the impact of possible water blocking on the recovery has to be addressed. For that purpose, a series of experiments was performed under reservoir conditions on a carbonate rock type to compare the displacement efficiencies of a secondary gas injection, a tertiary gas injection, and a simultaneous water-alternating-gas (SWAG) injection. The experiments were carried out on composite cores consisting of several carefully selected reservoir core plugs of the chosen rock type. The operating pressure was lower than the minimum miscible pressure (MMP) and reflected the current reservoir pressure. Phase exchanges were monitored continually during the hydrocarbon recovery, including the chromatographic analysis of the produced gas. The final oil recovery resulting from the three types of experiments was very good [approximately 90% original oil in place (OOIP) at surface conditions after 6 pore-volume (PV) injection] and quite similar within the expected experimental error, regardless of the sequence of gas injection. The low remaining oil saturation (ROS) values observed were consistent with competing processes of both viscous displacement of oil by gas and phase exchanges occurring between oil and gas. Because of the nature of the injected gas (rich gas from the first separation stage), a condensing/vaporizing process had to be considered. The SWAG injection speeds up the oil recovery by mobility control of the water phase. This enhances the sweep efficiency by viscous drive. A water-blocking effect was found to be negligible because it could be anticipated due to wettability consideration. The influence of the fluid description (equation of state, or EOS) and the three-phase relative permeability model on the simulation results was studied. An excellent agreement between simulation and production data was obtained with both gas/oil relative permeability data measured at ambient conditions on a restored composite core and an appropriate EOS (with seven pseudos). The condensing/vaporizing process that strips the intermediate compounds from the oil phase to the gas phase was properly taken into account with this appropriate EOS. The influence of the three-phase permeability model (either "geometrical construction" or Stone1) on the results was found to be small. Introduction For enhanced oil recovery (EOR) purposes, miscible or immiscible hydrocarbon gas injections have been applied successfully in many oil reservoirs throughout the world (Thomas et al. 1994; Lee et al. 1988). Compared to water injection, gas injection is associated with higher microscopic displacement efficiency due to the low value of the interfacial tension (IFT) between the oil and gas phases. IFT tends toward zero when miscibility is reached, which means that the oil recovery can be total in the swept area. Even when miscibility is not reached, the mass-transfer mechanisms that occur between oil and gas phases lead to low IFT values when compared to waterflooding. Even under those conditions, regarding remaining oil-saturation values, gas injection appears to be an interesting recovery process.