The two-phase flow characterization (CO 2 /water) of a Triassic sandstone core from the Paris Basin, France, is reported in this paper. Absolute properties (porosity and water permeability), capillary pressure, relative permeability with hysteresis between drainage and imbibition, and residual trapping capacities have been assessed at 9 MPa pore pressure and 28 C (CO 2 in liquid state) using a single core-flooding apparatus associated with magnetic resonance imaging. Different methodologies have been followed to obtain a data set of flow properties to be upscaled and used in large-scale CO 2 geological storage evolution modeling tools. The measurements are consistent with the properties of well-sorted water-wet porous systems. As the mineralogical investigations showed a nonnegligible proportion of carbonates in the core, the experimental protocol was designed to observe potential impacts on flow properties of mineralogical changes. The magnetic resonance scanning and mineralogical observations indicate mineral dissolution during the experimental campaign, and the core-flooding results show an increase in porosity and water absolute permeability. The changes in two-phase flow properties appear coherent with the pore structure modifications induced by the carbonates dissolution but the changes in relative permeability could also be explained by a potential increase of the water-wet character of the core. Further investigations on the impacts of mineral changes are required with other reactive formation rocks, especially carbonate-rich ones, because the implications can be significant both for the validity of laboratory measurements and for the outcomes of in situ operations modeling.

Enhanced oil recovery (EOR) using nanofluids has been proposed in recent years, but the mechanism of oil recovery enhancement through nanofluid injection still needs further study. In this study, the pore-scale performance and mechanism of nanofluid EOR were investigated based on a micromodel experiment. The micromodel sample was designed to compare the silica-based homogeneous water-wet sandstone reservoirs. The behavior of 0.1% wt water-base silica nanofluid-displacing oil (dodecane) was compared to the deionized (DI) water-displacing case. Residual oil saturation gradually decreases from 50% to 43% as the DI water injection flow rate increases from 0.5 to 5.0 μL/min. In the nanofluid-injection case, residual oil saturation decreases from 24% to 20% as the flow rate varies in the same range. About 25% saturation of incremental oil recovery is obtained by nanofluid injection compared to DI water injection. This implies significant improvement in oil recovery performance from nanofluid injection. Through investigation of detailed pore-scale fluid distribution, the wettability alteration of the oil-bearing pore wall from a strongly water-wet condition to the neutrally wet condition is observed in the presence of nanoparticles. The wettability alteration behavior in a natural sandstone sample was investigated via a spontaneous imbibition test. The imbibition rate slows down significantly in the presence of nanoparticles indicating that the wettability alteration mechanism observed in the micromodel experiment is also valid in the case of natural water-wet sandstones and consequently can enhance the oil recovery. The analysis based on Wenzel’s model indicates that the nanoparticle adsorption-induced nonuniform pore wall roughness change is the possible mechanism for wettability alteration.

Geological carbon sequestration (GCS) in deep saline aquifers is an effective means for storing carbon dioxide to address global climate change. As the time after injection increases, the safety of storage increases as the CO transforms from a separate phase to CO(aq) and HCO by dissolution and then to carbonates by mineral dissolution. However, subsequent depressurization could lead to dissolved CO(aq) escaping from the formation water and creating a new separate phase which may reduce the GCS system safety. The mineral dissolution and the CO exsolution and mineral precipitation during depressurization change the morphology, porosity, and permeability of the porous rock medium, which then affects the two-phase flow of the CO and formation water. A better understanding of these effects on the CO-water two-phase flow will improve predictions of the long-term CO storage reliability, especially the impact of depressurization on the long-term stability. In this Account, we summarize our recent work on the effect of CO exsolution and mineral dissolution/precipitation on CO transport in GCS reservoirs. We place emphasis on understanding the behavior and transformation of the carbon components in the reservoir, including CO(sc/g), CO(aq), HCO, and carbonate minerals (calcite and dolomite), highlight their transport and mobility by coupled geochemical and two-phase flow processes, and consider the implications of these transport mechanisms on estimates of the long-term safety of GCS. We describe experimental and numerical pore- and core-scale methods used in our lab in conjunction with industrial and international partners to investigate these effects. Experimental results show how mineral dissolution affects permeability, capillary pressure, and relative permeability, which are important phenomena affecting the input parameters for reservoir flow modeling. The porosity and the absolute permeability increase when CO dissolved water is continuously injected through the core. The MRI results indicate dissolution of the carbonates during the experiments since the porosity has been increased after the core-flooding experiments. The mineral dissolution changes the pore structure by enlarging the throat diameters and decreasing the pore specific surface areas, resulting in lower CO/water capillary pressures and changes in the relative permeability. When the reservoir pressure decreases, the CO exsolution occurs due to the reduction of solubility. The CO bubbles preferentially grow toward the larger pores instead of toward the throats or the finer pores during the depressurization. After exsolution, the exsolved CO phase shows low mobility due to the highly dispersed pore-scale morphology, and the well dispersed small bubbles tend to merge without interface contact driven by the Ostwald ripening mechanism. During depressurization, the dissolved carbonate could also precipitate as a result of increasing pH. There is increasing formation water flow resistance and low mobility of the CO in the presence of CO exsolution and carbona...

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For CO2 sequestration and utilization in the shallow reservoirs, reservoir pressure changes are due to the injection rate changing, a leakage event, and brine withdrawal for reservoir pressure balance. The amounts of exsolved CO2 which are influenced by the pressure reduction and the subsequent secondary imbibition process have a significant effect on the stability and capacity of CO2 sequestration and utilization. In this study, exsolution behavior of the CO2 has been studied experimentally using a core flooding system in combination with NMR/MRI equipment. Three series of pressure variation profiles, including depletion followed by imbibitions without or with repressurization and repetitive depletion and repressurization/imbibition cycles, were designed to investigate the exsolution responses for these complex pressure variation profiles. We found that the exsolved CO2 phase preferentially occupies the larger pores and exhibits a uniform spatial distribution. The mobility of CO2 is low during the imbibition process, and the residual trapping ratio is extraordinarily high. During the cyclic pressure variation process, the first cycle has the largest contribution to the amount of exsolved CO2. The low CO2 mobility implies a certain degree of self-sealing during a possible reservoir depletion.