One of the critical factors that control the efficiency of CO 2 geological storage process in aquifers and hydrocarbon reservoirs is the capillary-sealing potential of the caprock. This potential can be expressed in terms of the maximum reservoir overpressure that the brine-saturated caprock can sustain, i.e. of the CO 2 capillary entry pressure. It is controlled by the brine/CO 2 interfacial tension, the water-wettability of caprock minerals, and the pore size distribution within the caprock.By means of contact angle measurements, experimental evidence was obtained showing that the water-wettability of mica and quartz is altered in the presence of CO 2 under pressures typical of geological storage conditions. The alteration is more pronounced in the case of mica. Both minerals are representative of shaly caprocks and are strongly water-wet in the presence of hydrocarbons.A careful analysis of the available literature data on breakthrough pressure measurements in caprock samples confirms the existence of a wettability alteration by dense CO 2 , both in shaly and in evaporitic caprocks. The consequences of this effect on the maximum CO 2 storage pressure and on CO 2 storage capacity in the underground reservoir are discussed. For hydrocarbon reservoirs that were initially close to capillary leakage, the maximum allowable CO 2 storage pressure is only a fraction of the initial reservoir pressure.

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Summary The properties and limitations of different dynamic pseudorelative permeability methods are summarized. Severe difficulties common to all methods are discussed: choosing the number and locations of the coarse-grid rock types, defining the simulations from which the pseudos are generated, and the dependence of the pseudos on well rates and positions. It is concluded that, in practice, pseudos cannot be used reliably to scale up from a "fine-grid" geological model to a "coarse-grid" fluid-flow model except for cases where capillary or gravity equilibrium can be assumed at the coarse-gridblock scale. Scaling up from the core scale to the geological model is more likely to be possible because capillary forces are more important at smaller scales. A practical approach to the dynamic upscaling problem is outlined, but one should not expect that the effects of the detail in the geological model will be captured more than qualitatively. Introduction Multiphase fluid-flow simulations of oil reservoirs are computationally very intensive. With currently available computers, most oil companies cannot afford to run routine fluid-flow simulations with more than about 10 5 gridblocks. This implies an average gridblock size on the order of 100m areally and perhaps 1 to 10 m vertically. Each gridblock thus represents a part of the reservoir that is heterogeneous. Historically, little information on the structure of the reservoir at this scale was available, so there was little motivation to do anything but ignore the heterogeneity not explicitly represented in the model. Nowadays, modern reservoir imaging techniques and advances in geological modeling are providing more detailed reservoir descriptions. Geological reservoir models are being built with up to 10 7 gridblocks (the size of these models is also limited by computational constraints). These models may be used directly for fluid-in-place and connectivity calculations with little computational difficulty. Single-phase flows, such as well tests or depletion of dry gas reservoirs with no aquifer influx, may possibly be simulated on grids of this size. But for multiphase flows, which occur in the majority of hydrocarbon reservoirs, the detailed geological information must be incorporated into a coarser, fluid-flow simulation model by means of some upscaling technique.

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe efficiency of the CO 2 geological storage process in aquifers and hydrocarbon reservoirs is controlled by several factors. In the case of reservoirs with a shaly caprock, one critical factor is the capillary-sealing potential of the caprock. This potential can be expressed in terms of a maximum storage pressure, equal to the hydrostatic pressure in the caprock plus the CO 2 capillary entry pressure in the brinesaturated caprock. It is therefore controlled by the CO 2 -brine interfacial tension, the water-wettability of shale minerals, and the pore size distribution within the shaly rock.By means of contact angle measurements, we provide experimental evidence that the water-wettability of minerals representative of shales, such as mica and quartz, is significantly altered in the presence of CO 2 under pressures typical of geological storage conditions. Those minerals, known to be strongly water-wet in the presence of oil, turn out to be intermediate-wet in the presence of dense CO 2 .We discuss the consequences of such wettability alteration on the maximum CO 2 storage pressure, which can be converted into a maximum CO 2 height stored in the reservoir. In the case of hydrocarbon reservoirs initially close to capillary leakage, the maximum CO 2 storage pressure should be only a fraction of the initial virgin pressure.