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Dissolution of CO 2 into brine causes the density of the mixture to increase. The density gradient induces natural convection in the liquid phase, which is a favorable process of practical interest for CO 2 storage. Correct estimation of the dissolution rate is important because the time scale for dissolution corresponds to the time scale over which free phase CO 2 has a chance to leak out. However, for this estimation, the challenging simulation on the basis of convection-diffusion equation must be done. In this study, pseudo-diffusion coefficient is introduced which accounts for the rate of mass transferring by both convection and diffusion mechanisms. Experimental tests in fluid continuum and porous media were performed to measure the real rate of dissolution of CO 2 into water during the time. The pseudo diffusion coefficient of CO 2 into water was evaluated by the theory of pressure decay and this coefficient is used as a key parameter to quantify the natural convection and its effect on mass transfer of CO 2 . For each experiment, fraction of ultimate dissolution is calculated from measured pressure data and the results are compared with predicted values from analytical solution. Measured CO 2 mass transfer rate from experiments are in reasonable agreement with values calculated from diffusion equation performed on the basis of pseudo-diffusion coefficient. It is suggested that solving diffusion equation with pseudo diffusion coefficient herein could be used as a simple and rapid tool to calculate the rate of mass transfer of CO 2 in CCS projects.

A number of forced gravity drainage experiments have been conducted using a wide range of the physical and operational parameters, wherein the type, length, and permeability of the porous medium as well as oil viscosity and injection rate were varied. Results indicate that an increase in the Bond number has a positive effect on oil recovery whereas the capillary number has an opposite effect. These trends were observed over a two-order of magnitude change in the value of the dimensionless groups. Furthermore, it was found that use of each number alone is insufficient to obtain a satisfactory correlation with recovery. A combined dimensionless group is proposed, which combines the effect of all the three forces. Recoveries from all the experiments conducted in this study show a very good correlation with the proposed group. The exponent of the Bond number in the proposed group is larger than the capillary number suggesting a larger importance for the former. We then show that the same group provides a good correlation for recovery from additional experiments conducted in this study (in the presence of connate water) with that of another set of experiments in the literature.

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A detailed investigation into the effect of dissolved amphiphilic compounds of crude oil in salt water on its surface tension/interfacial tension (ST/IFT) behavior has been conducted in this paper. To simulate water–oil contact during water injection into oil reservoirs, 16 single-salt aqueous solutions of NaCl, CaCl2, and Na2SO4 having ionic strengths of up to 2.0 M were mixed with a natural acidic–basic crude oil. The mixing was performed by a rocking mechanism in a visual pressure–volume–temperature cell at an elevated temperature. After the mixing process, two phases were completely separated from each other using a high-temperature centrifuge. Finally, in addition to pH measurements, the air–water ST and decane–water IFT of salt water were measured using the pendant-drop method. The results reveal that the dissolution of crude oil amphiphilic compounds, especially the acidic or basic compounds, in salt water can considerably decrease its ST/IFT. It seems that there is the same optimal ionic strength for the aqueous solutions of the three studied salts, in which both the air–water ST and the decane–water IFT of salt water are minimized after its contact with crude oil. It was observed that, among the three studied salts, the aqueous solutions of Na2SO4 had the lowest ST/IFT values for all ionic strengths after their contact with crude oil. This result can be because the crude oil used was more basic than acidic.

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We present the first experiments of dissolution-driven convection of carbon dioxide (CO2) in a confined brine-saturated porous medium at high pressures. We designed a novel Hele-Shaw cell that allows for both visual and quantitative analyses, and address the effects of free-phase CO2 and brine composition on convective dissolution. The visual examination of the gas volume combined with the measurement of pressure, which both evolve with dissolution, enable us to yield insights into the dynamics of convection in conditions that more closely reflect the geologic conditions. We find and analyze different dissolution events, including diffusive, early and late convection, and shutdown regimes. Our experiments reveal that in intermediate regime, a so-called "quasi-steady" state actually never happens. Dissolution flux continuously decreases in this regime, which is due to a negative feedback loop: the rapid reduction of pressure following convective dissolution, in turn, decreases the solubility of CO2 at the gas-brine interface and thus the instability strength. We introduce a new scaling factor that not only compensates the flux reduction but also the nonlinearities that arise from different salt types. We present robust scaling relations for the compensated flux and for the transition times between consecutive regimes in systems with NaCl (Ra ∼ 3271-4841) and NaCl+CaCl2 mixtures (Ra ∼ 2919-4283). We also find that NaCl+CaCl2 mixtures enjoy a longer intermediate period before the shut-down of dissolution, but with a lower dissolution flux, as compared to NaCl brines. The results provide a new perspective into how the presence of two separate phases in a closed system as well as different salt types may affect the predictive powers of our experiments and models for both the short-and long-term dynamics of convective dissolution in porous media. * brostami@ut.ac.ir

Although viability of low-salinity waterflooding (LSWF) at the laboratory scale has been proven, there are some challenges associated with its field application, which sheds uncertainties on its economic success. One of the challenges is the minimum required volume of low-salinity water, which should be injected to the reservoir due to the salt dispersion in porous media. Once the low-saline brine is injected into the reservoir, mixing of injected (low-salinity) and resident (high-salinity) brines occurs and the developed mixing zone grows continuously as the front moves from the injection well toward the production well. Increase in the salinity of the front reduces the efficiency of LSWF. In this paper, we demonstrate experimentally that if low-salinity brine is augmented with a small amount of a polymer (as a viscosifying and mobility control agent), salt dispersion can be significantly suppressed. In this regard, a systematic series of single-phase sandpack flooding experiments was designed and performed. The impacts of salinity of resident high-salinity brine, salinity of low-salinity brine, and polymer concentration on mixing (dispersion) control were investigated. Analytical and numerical simulation methods were implemented to analyze the experimental data and infer dispersivity. The results show that adding 200 ppm of partially hydrolyzed polyacrylamide (HPAM) to the injection brine reduces the dispersivity by more than 70%. Once the dispersivity is reduced, the salinity profile becomes sharper; thus, significantly less volume of low-salinity brine will be required to establish low-salinity conditions in the whole core. Additionally, the analysis of variance shows that polymer concentration and salinity of high-salinity brine are the main factors affecting the dispersivity. The total salinity of low-salinity brine was found to be comparatively less important.