Sensitivity Analysis Strategy to Assess the Salting-Out Problem during CO2 Geological Storage Process

The sensitivity analysis of the salting-out effect on well injectivity is a significant work in the research of geological storage of CO2 in deep saline aquifers, which is helpful in the selection of storage sites and the design of the injection strategy. We conduct a detailed sensitivity analysis about the salting-out process using the local sensitivity method and two global sensitivity methods. Sensitivity coefficients showed that brine salinity (XNaCl) has the highest sensitivity and interaction effect, the CO2 injection rate (QCO2) has a greater influence in the early stage of the salting-out process and a smaller influence in the end stage, and the other three parameters (empirical parameters related to the pore distribution m, the liquid residual saturation in the relative permeability function Splr, and the liquid residual saturation in the capillary pressure function Sclr) have a smaller sensitivity. This paper also analyzes the calculation amount of different sensitivity methods and suitable ways of obtaining the sensitivity coefficient and reveals the following. (1) The sensitivity coefficient changes dynamically with time, if only the sensitivity of the final state is taken into account on a long-time physical process, and some sensitive parameters during the process may be neglected. (2) The selection of the sample size should be based on the convergence of multiple calculations, and the results of the empirical calculation are uncertain. (3) The calculation of Sobol sensitivity is complicated, the results calculated by surrogate model depend on whether the sample is representative enough; on the other hand, it is feasible to use Sti-Si approximation to characterize the second-order sensitivity to reduce the computation. The research results not only reveal the sensitivity of the parameters related to the injection well salting-out problem during CO2 storage in deep saline aquifers but also guide the calculation of global sensitivity analysis with a similar physical process.

Relationship between Residual Saturations and Wettability using Pore-Network Modeling

The relationship between residual saturation and wettability is critical for modeling enhanced oil recovery (EOR) processes. The wetting state of a core is often quantified through Amott indices, which are estimated from the ratio of the saturation fraction that flows spontaneously to the total saturation change that occurs due to spontaneous flow and forced injection. Coreflooding experiments have shown that residual oil saturation trends against wettability indices typically show a minimum around mixed-wet conditions. Amott indices, however, provides an average measure of wettability (contact angle), which are intrinsically dependent on a variety of factors such as the initial oil saturation, aging conditions, etc. Thus, the use of Amott indices could potentially cloud the observed trends of residual saturation with wettability. Using pore network modeling (PNM), we show that residual oil saturation varies monotonically with the contact angle, which is a direct measure of wettability. That is, for fixed initial oil saturation, the residual oil saturation decreases monotonically as the reservoir becomes more water-wet (decreasing contact angle). Further, calculation of Amott indices for the PNM data sets show that a plot of the residual oil saturation versus Amott indices also shows this monotonic trend, but only if the initial oil saturation is kept fixed. Thus, for the cases presented here, we show that there is no minimum residual saturation at mixed-wet conditions as wettability changes. This can have important implications for low salinity waterflooding or other EOR processes where wettability is altered.

Study on the effect of pore-scale heterogeneity and flow rate during repetitive two-phase fluid flow in microfluidic porous media

Various energy recovery, storage, conversion, and environmental operations may involve repetitive fluid injection and, thus, cyclic drainage-imbibition processes. We conducted an experimental study for which polydimethylsiloxane (PDMS)-based micromodels were fabricated with three different levels of pore-space heterogeneity (coefficient of variation, where COV = 0, 0.25, and 0.5) to represent consolidated and/or partially consolidated sandstones. A total of ten injection-withdrawal cycles were applied to each micromodel at two different flow rates (0.01 and 0.1 mL/min). The experimental results were analyzed in terms of flow morphology, sweep efficiency, residual saturation, the connection of fluids, and the pressure gradient. The pattern of the invasion and displacement of nonwetting fluid converged more readily in the homogeneous model (COV = 0) as the repetitive drainage-imbibition process continued. The overall sweep efficiency converged between 0.4 and 0.6 at all tested flow rates, regardless of different flow rates and COV in this study. In contrast, the effective sweep efficiency was observed to increase with higher COV at the lower flow rate, while that trend became the opposite at the higher flow rate. Similarly, the residual saturation of the nonwetting fluid was largest at COV = 0 for the lower flow rate, but it was the opposite for the higher flow rate case. However, the Minkowski functionals for the boundary length and connectedness of the nonwetting fluid remained quite constant during repetitive fluid flow. Implications of the study results for porous media-compressed air energy storage (PM-CAES) are discussed as a complementary analysis at the end of this manuscript.Supplementary material: Figures S1 and S2 https://doi.org/10.6084/m9.figshare.c.5276814.Thematic collection: This article is part of the Energy Geoscience Series collection available at: https://www.lyellcollection.org/cc/energy-geoscience-series