Yueliang Liu

Nanobubbles are promising displacement media for improving oil recovery of low-permeability reservoir, owing to high specific interfacial area, and pronounced interfacial effects. However, conventional nanobubbles are limited by large bubble sizes and low concentrations, making it difficult to effectively penetrate the micro pores of low-permeability reservoirs and further improve oil recovery. In this work, enhanced N2 NBs were generated in surfactant solutions by hydrodynamic cavitation. The size and number concentration were measured by nanoparticle size analyzer. A rotating interfacial tensiometer is used to measure interfacial tension. Core flooding experiments combined with nuclear magnetic resonance (NMR) techniques were employed to quantitatively characterize crude oil recovery from different pore. Microfluidic technology enables the monitoring of multiphase flow under reservoir temperature and pressure conditions, thereby elucidating the mechanisms of residual oil mobilization. Among the seven tested surfactants, NIS-Q exhibited the best performance. At 0.3 wt.%, NIS-Q reduced N2 NBs size from 450.0 to 176.3 nm and increased concentration from 1.77×106 to 2.33×108 bubbles/mL by forming a steric interfacial barrier against coalescence and gas diffusion. Enhanced N2 NBs reduced oil-water IFT from 28.0 to 0.95 mN/m. Oil recovery of enhanced N2 NBs reached 76%, representing an increase of 20.9% over water flooding and 53.1% over conventional N2 NBs, while lowering pressure differential from 4.9 to 0.8 MPa. Oil recovery of micro-pores was increased by 46%. Microfluidic analyses revealed improved micro-pore oil mobilization and multiphase transport regulation through phase redistribution and channeling suppression. This study provides technical and theoretical support for the application of nano-technology in the field of low-energy consumption tertiary oil recovery in low-permeability oil reservoirs.

Summary: The sequestration of CO2 in shale formations has dual benefits of reducing carbon emissions and enhanced oil recovery (EOR). CO2 purified from industrial waste gas is the main gas source for CO2 injection into oil reservoirs. Impurity gases in industrial waste gas, such as H2S, may impair carbon storage and gas recovery via competitive adsorption. Consequently, it is worthwhile to evaluate the competitive adsorption characteristics of CO2, CH4, and H2S, and their multicomponent mixtures within kaolinite nanopores, and the implications on carbon sequestration and CH4 recovery. Drawing upon the kaolinite nanopores model, the impact of various surfaces on the adsorption characteristics of CO2, CH4, H2S, and their mixes was examined using the grand canonical Monte Carlo (GCMC) method. Various factors, including temperature (293.15–383.15 K), pressure (0–20 MPa), pore width, and gas mole fraction, are investigated in the adsorption behaviors of the mixtures in the nano-confined space. The quantity of three molecules adsorbed enhances as the pressure grows and decreases with rising temperature. The rank of the absolute adsorbed amount is H2S > CO2 >CH4. The interaction energies of kaolinite with CO2, CH4, and H2S at 20 MPa and 293.15 K are –1,421.1138,–479.0825, and −2,528.245 kcal/mol, respectively, and the van der Waals energy is the main component of the interaction energy. Compared with hydrophobic pores, the loading of H2S, CO2, and CH4 in hydrophilic pores under 323.15 K and 20 MPa is 22.76%, 13.17%, and 11.57% greater, respectively. Three molecules show better adsorption stability on hydrophilic walls. The adsorption capacity of three molecules in binary/ternary mixtures is H2S>CO2>CH4. Gas components are crucial factors affecting the adsorption capacity of each component in multicomponent mixtures. In CO2/H2S and CH4/H2S binary mixtures, the adsorption of CO2 and CH4 is negatively impacted by H2S, and the adsorbed CO2 and CH4 are reduced by roughly 59.66% and 87.11%, respectively, at 25% (molar fraction) H2S. In CO2/H2S/CH4 ternary mixtures, CO2 and H2S exhibit strong competitive adsorption in the vicinity of the pore wall, whereas CH4 is predominantly distributed in the central region of the pore. An increase in H2S content leads to a transition of the three molecules toward lower energy states, facilitating their adsorption in a more stable configuration within the kaolinite nanopores. The nanoscale mechanism of gas adsorption in the clay mineral was disclosed from a molecular perspective, which theoretically supports the application of CO2 storage and EOR projects in shale reservoirs.

CO2 mineralization is currently the safest permanent carbon sequestration solution. However, under natural geological conditions, CO2 mineralization occurs at an extremely low rate, typically taking hundreds or even millions of years. Herein, CO2 nanobubbles are employed as a new possible alternative to accelerate carbon mineralization and simultaneously generate hydrogen in peridotite, and the acceleration mechanisms of CO2 nanobubbles are brought to light. The findings indicate that CO2 nanobubbles enhance the supersaturation of CO2 in the aqueous phase and promote the dissolution of peridotite particles. Mineralogical and spectroscopic analyses further confirmed accelerated silicate dissolution and carbonate precipitation in the nanobubble system. Notably, CO2 nanobubbles increase the macropore proportion by approximately 28% and enhance the product layer diffusion coefficient from 1.08×10-16 m2·s-1 to 11.89×10-16 m2·s-1. The ultimate mineralization degree and hydrogen yield of the CO2 nanobubble system are approximately 2.08-fold and 1.45-fold that of the carbonated water system, respectively, corresponding to an additional 53.7 kg of CO2 sequestered and 2.34 g of H2 generated per tonne of peridotite. Furthermore, the generation of H2 is related to changes in the interfacial water structure and the oxidation of Fe(II), in which Fe(II) may act as an electron donor for proton reduction. This research provides a pathway for efficient CO2 sequestration and hydrogen generation, which provides theoretical assistance for CO2 geological sequestration and energy transition.

Summary: Carbon dioxide (CO2) mineralization sequestration is one of the stable methods used to safely store CO2 in underground rock formations. However, the formation of a dense carbonate product layer during the mineralization process will seriously hinder the mass transfer efficiency at the reaction interface, resulting in mineralization kinetic hysteresis, and decreased sequestration efficiency. For this study, we prepared CO2 nanobubbles using the hydrodynamic cavitation method and conducted mineralization and hydrogen production experiments of basalt in a system containing nanobubbles and carbonated water, revealing the mechanism of action of CO2 nanobubbles. The results reveal that the CO2 content in the nanobubble water reaches 1.65 ± 0.006 mg/L, approximately 1.2-fold that of the carbonated water system, which provides a richer carbon source for the mineralization reaction. The CO2 nanobubbles prepared with 0.1 wt% nonylphenol ethoxylate (NPE) as solvent have an average diameter of 187.5 nm, a zeta potential of −40.54 mV, and a concentration of 6.3×108 nanobubbles/mL. Compared with the carbonated water system, the CO2 nanobubble system promotes basalt dissolution and enhances the release of calcium ion (Ca2+), magnesium ion (Mg2+), and total iron (TFe). The proportion of macropores (>50 nm) increases by 19%, which improves the diffusion coefficient of the product layer by one to two orders of magnitude. After 25 days of reaction, the degree of mineralization and hydrogen production reaches 0.15 mmol/kgBS and 1.82 mmol/kgBS, respectively, representing increases of 1.67-fold and 1.26-fold compared with the carbonated water system. This study proposes a novel approach for improving mineralization and hydrogen production efficiency using CO2 nanobubbles, which provides technical guidance for CO2 geological sequestration.

CO2 flooding and CO2/N2 mixed flooding have demonstrated great potential in enhancing oil and gas recovery. However, the molecular-level mechanistic details, especially within complex systems involving specific mineral surfaces like calcite, require further clarification. To clarify these processes, we employed molecular dynamics simulations to examine oil phase adsorption on calcite and the microscopic interactions among gas, oil, and calcite walls. The findings reveal that the highly polar compounds, like benzoic acid and n-heptanoic acid, exhibit stronger and more stable adsorption to the calcite surface, making them less prone to removal by pure CO2. In contrast, less polar hydrocarbons like n-heptane and n-dodecane form oil films that are more easily stripped. Additionally, during the mixed oil phase adsorption, polar compounds tend to localize closer to the wall. The gas phase (CO2, CO2/N2) displaces oil molecules primarily through competitive adsorption on calcite and dissolution of oil molecules. The interaction between gas and oil is stronger than that between oil and calcite, highlighting a key condition for effective oil detachment. CO2 exhibits stronger adsorption on calcite and greater oil solubility than N2. Accordingly, the interaction between the gas and oil phases, along with the oil stripping efficiency, increases with the CO2 content. van der Waals energy dominates interactions between CO2/N2 and hydrocarbons, as well as between calcite and these hydrocarbons. In contrast, electrostatic energy governs interactions between calcite and polar compounds. These findings offer molecular-level insights to guide gas injection strategies for enhanced oil recovery in carbonate formation.

Summary: Carbon dioxide (CO2) flooding provides a promising approach to enhance oil recovery and achieve carbon sequestration in low-permeability reservoirs. Nevertheless, the storage capacity and longevity of CO2 flooding are significantly influenced by the states of CO2 within the porous media. We conducted a series of experiments to characterize the mixing of the CO2-oil system and elucidate the underlying mechanisms influenced by injection pressure. n-Alkanes were positioned on the T1-T2 maps through T1/T2 values calculated using the Stokes-Einstein equation and the Bloembergen-Purcell-Pound (BPP) model. CO2 flooding experiments were conducted at varying backpressure values, and the T1-T2 maps of n-alkanes were obtained. By applying two-phase mass-transfer theory, “pseudo T1-T2 maps” of CO2 were derived. The maps of dissolved and independent CO2 were acquired according to the solubility of CO2 in n-alkanes. The correlation of oil recovery and the ratio of trapped CO2 in different states were finally obtained, and the trapping mechanisms were revealed. The result of n-alkane zoning indicates that pressure variation will cause component shifting in the T1-T2 maps. The comparison with oil composition tested by gas chromatograph (GC) proves high reliability and accuracy of low-field nuclear magnetic resonance (LF-NMR) to analyze the fluid components variation in the CO2 flooding. A detailed analysis on T1-T2 maps of hydrocarbon in CO2 flooding shows stronger extraction effect of CO2 on oil components in the miscible flooding. Moreover, the “pseudo T1-T2 maps” of CO2 provide valuable insights into the mass-transfer process between the displacing and displaced phases. By dividing the 2D map into distinct regions, CO2 was effectively differentiated into independent and dissolved states based on its interaction with hydrocarbon components. Subsequently, key metrics such as oil recovery factor, storage mass, storage efficiency, and solubility trapping ratio were computed, revealing that the oil recovery and solubility ratio show consistency in the immiscible flooding and display contradictoriness in the miscible flooding. Notably, this study reveals complex correlations among storage capacity, stability, and adjustable injection pressure. The increase in injection pressure has a positive effect on CO2 storage capacity and stability in the immiscible flooding, and this effect is negative for CO2 storage stability in the miscible flooding. These findings offer valuable insights for optimizing large-volume and long-term CO2 sequestration strategies.