Abstract CO 2 geosequestration in oil reservoirs is an economically attractive solution as it can be combined with enhanced oil recovery (CO 2 ‐EOR). However, the effectiveness of the associated three‐phase displacement processes has not been tested at the micrometer pore scale, which determines the overall reservoir‐scale fluid dynamics and thus CO 2 ‐EOR project success. We thus imaged such displacement processes in situ in 3‐D with X‐ray microcomputed tomography at high resolution at reservoir conditions and found that oil extraction was enhanced substantially, while a significant residual CO 2 saturation (13.5%) could be achieved in oil‐wet rock. Statistics of the residual CO 2 and oil clusters are also provided; they are similar to what is found in analogue two‐phase systems although some details are different, and displacement processes are significantly more complex.
Abstract We quantify the influence of the initial non-wetting phase saturation and porosity on the residual non-wetting phase saturation based on data in the literature and our own experimental results from sandpacks and consolidated rocks. The principal application of this work is for carbon capture and storage (CCS) where capillary trapping is a rapid and effective way to render the injected CO2 immobile, guaranteeing safe storage. We introduce the concept of capillary trapping capacity (Ctrap) which is the product of residual saturation and porosity that represents the fraction of the rock volume that can be occupied by a trapped non-wetting phase. We propose empirical fits to the data to correlate trapping capacity and residual saturation to porosity and initial saturation. We show that trapping capacity reaches a maximum of approximately 7% for rock porosities of 20%, which suggests an optimal porosity for CO2 storage.
Abstract During an imbibition process in two‐phase subsurface flow the imbibing phase can displace the nonwetting phase up to an endpoint at which a residual saturation is reached (which cannot be reduced further by additional wetting phase flow due to the complex pore network of the rock and associated strong capillary forces which trap the nonwetting phase). The residual nonwetting phase is split into many disconnected clusters of different sizes. This size distribution is of key importance, for instance, in the context of hydrocarbon recovery, contaminant transport, or CO 2 geostorage; and it is well established that this size distribution follows a power law. However, there is significant uncertainty associated with the exact value of the distribution exponent τ , which mathematically describes the size distribution. To reduce this uncertainty and to better constrain τ , we analyzed a representative experimental data set with mathematically rigorous methods, and we demonstrate that τ is substantially smaller (≈1.1) than previously suggested. This raises increasing doubt that simple percolation models can accurately predict subsurface fluid flow behavior; and this has serious consequences for subsurface flow processes: hydrocarbon recovery is easier than predicted, but CO 2 geostorage dissolution trapping capacities are significantly reduced and potential remobilization of residual CO 2 is more likely than previously believed.
Predicting the wetting behavior of shale rocks is important for understanding fluid flow in shales for CO2 geo-storage and enhanced oil recovery applications. However, shale rocks tend to demonstrate a much wider wettability variation compared to conventional rocks. Here, we present a new model for predicting advancing and receding contact angles for shale/CO2/brine systems. The model presented here considers shale wettability variation as a function of key influencing parameters including (a) operating conditions (i.e., pressure, temperature, and salinity), (b) shale total organic carbon (TOC), (c) thermal maturity, and (d) mineralogy of shale (including quartz, calcite, dolomite, clay, and pyrite content). The developed model shows that pressure and salinity are the most influencing parameters for both the advancing and receding contact angles. These are followed by temperature, TOC, and thermal maturity. The results of this study contribute toward predicting the wetting behavior of shale with known operating and functional properties and thus serve as an essential input in simulation models pertinent to flow behavior in shale rocks and therefore enhance hydrocarbon production from shales and CO2 storage in shale formations.
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