Pengfei Lv

In Situ Local Contact Angle Measurement in a CO2–Brine–Sand System Using Microfocused X-ray CT

The wettability of porous media is of major interest in a broad range of natural and engineering applications. The wettability of a fluid on a solid surface is usually evaluated by the contact angle between them. While in situ local contact angle measurements are complicated by the topology of porous media, which can make it difficult to use traditional methods, recent advances in microfocused X-ray computed tomography (micro-CT) and image processing techniques have made it possible to measure contact angles on the scale of the pore sizes in such media. However, the effects of ionic strength, CO2 phase, and flow pattern (drainage or imbibition) on pore-scale contact angle distribution are still not clear and have not been reported in detail in previous studies. In this study, we employed a micro-CT scanner for in situ investigation of local contact angles in a CO2-brine-sand system under various conditions. The effects of ionic strength, CO2 phase, and flow pattern on the local contact-angle distribution were examined in detail. The results showed that the local contact angles vary over a wide range as a result of the interaction of surface contaminants, roughness, pore topology, and capillarity. The wettability of a porous surface could thus slowly weaken with increasing ionic strength, and the average contact angle could significantly increase when gaseous CO2 (gCO2) turns into supercritical CO2 (scCO2). Contact angle hysteresis also occurred between drainage and imbibition procedures, and the hysteresis was more significant under gCO2 condition.

Experimental study of two-phase flow properties of CO2 containing N2 in porous media

In preliminary analyses, the co-injection of CO2 with H2S, SO2 and N2 impurities has been shown to reduce total carbon capture and storage (CCS) cost. The multiphase flow properties of impurities in the CO2–brine system in porous media are the key to understanding the mechanisms and nature of geological CO2 sequestration projects. In this study experiments were performed on the multiphase flow process of CO2/N2/brine system at conditions similar to aquifer pressure and temperature using the X-ray CT technique. Experiments at various rates of CO2 injection that affect saturation and spatial distribution of injected gas were conducted in this experiment. The results indicate an strong relationship between gas saturation and porosity distribution in porous media, and the increasing capillary number leads to lower saturation in downward injection. Small capillary numbers and higher fractional flows in the gas phase both result in uniform saturation maps in the core. The CO2 clusters seem larger at high capillary numbers and the high CO2 collection regions extend based on the saturation distribution in the lower CO2 fraction as the flow pattern stays similar as the same capillary number. CO2 containing N2 tends to retain more correlative relationships at different gas injection rates compared with the pure CO2 stream. Even though both distribution and saturation are storage concerns, the N2 component has little effect on gas distribution, whereas it brings about an overall increase in the saturation for most experiments. Thus the N2 enhanced the storage performance of CO2.

CO2/water two-phase flow in a two-dimensional micromodel of heterogeneous pores and throats

Gas–liquid two-phase flow in porous media is highly relevant to numerous geological engineering processes. Pore network micromodeling is able to provide an effective way to experimentally observe the gas–liquid displacement phenomena. However, micromodel experiments were rarely conducted in heterogeneous conditions, which may significantly affect the displacement process. In this study, CO2/water displacement experiments were conducted at 25 °C and ambient pressure conditions in an etched glass micromodel with heterogeneous pores and throats. The experiments were performed in both vertical and horizontal directions with the CO2 injection rates ranging from 0.2 ml h−1 to 6.0 ml h−1. Dynamic displacements were detected in real time by a digital single lens reflex camera. Based on the experimental results, a detailed discussion about the instability of CO2 front and CO2 saturation variation was conducted. It is found that the displacements become more and more unstable with an advancing CO2 front. Small fingerings can be collapsed by capillary pressure. Micro-scale heterogeneity significantly influenced the flow pattern at both the microscale and macroscale. Moreover, we created a new evaluation parameter Seval to characterise CO2 saturation variations and the transformation of Seval agrees well with our experimental results of CO2 saturation.

Pore‐Scale Imaging and Analysis of Phase Topologies and Displacement Mechanisms for CO2‐Brine Two‐Phase Flow in Unconsolidated Sand Packs

CO2 storage in saline aquifers is considered a potential solution for CO2 mitigation, owing to its significant capacity and worldwide distribution capability. It is therefore becoming more important to understand the underground CO2/brine flow mechanisms. CO2 migration is primarily controlled by the pore-scale subsurface flows in different saline aquifer sites with variable reservoir formation compositions and reservoir conditions. Variations occur in the state of CO2 phase (gas versus supercritical), brine salinity, and rock wettability, under different reservoir conditions, and may result in different subsurface CO2/brine migration phenomena. In this study, we investigate the drainage and imbibition procedures of CO2 and brine by injecting fluids into unconsolidated sand packs under different conditions of CO2 phase states, brine salinity, and wettability of sand packs. The pore-scale fluid distribution is visualized using micro X-ray computed tomography (micro-CT). It is found that the phase states of CO2, brine salinity, and wettability have low impacts on CO2 distribution during drainage. However, the increase in brine salinity significantly damages the connectedness of the water phase in pore structures and further decreases the CO2-brine interfacial areas. In addition, a pore-scale event called the droplet fragmentation of nonwetting phase is found to occur in the imbibition procedure, which is considered to be beneficial to the dissolution trapping in CO2 geological storages. It is experimentally demonstrated that the pore structure of rock cores is a factor that significantly contributes to droplet fragmentation.