Nanoparticles-surfactant foam and crude oil interaction in porous media

Nanoparticles and surfactant stabilized foams have versatile applications in enhanced oil recovery process. The synergistic advantages of surface tension reduction by surfactant and nanoparticles adsorption at the foam lamellae can be exploited for producing foam with high foamability and longtime stability in the oil producing reservoir. However, the influence of nanoparticles on the static and the dynamic stability of conventional foam is not yet explicit due to limited studies. Moreover, only few studies have considered the pore-scale mechanisms of the nanoparticles-surfactant foams flow process in porous media and the minimization of surfactant adsorption in presence of nanoparticles. Due to limited research in this area, this study was conducted to understand the influence of silicon dioxide (SiO2) and aluminum oxide (Al2O3) nanoparticles on the surfactant foam bulk and dynamic stability and surfactant adsorption on clay mineral. Four main experimental studies comprising the influence of the nanoparticles on surfactant adsorption on kaolinite, bulk and bubble-scale foam stability evaluation in presence of oil and salts, pore-scale visualization studies in etched glass micromodels, and fluid diversion process experiments were conducted. Results of this study showed that the adsorption of surfactant on clay mineral reduced drastically by 40% and 75% in presence of Al2O3 and SiO2 nanoparticles, respectively. The maximum adsorption of surfactant on the nanoparticles occurred at 0.3 wt % sodium dodecyl sulfate (SDS). The foam bulk and bubble scale stability results indicated that 1 wt % of SiO2 and Al2O3 nanoparticles enhanced the stability of the foam in presence of oil and salts. There was a transition salt concentration beyond which the foam stability increased with increasing salt concentrations. The presence of Al2O3 and SiO2 nanoparticles prevented the entering of emulsified oil into the foam lamellae and decreased the transition salt concentrations. From the results of the pore scale studies, the dominant mechanisms of foam propagation in water-wet system were lamellae division and bubble-to-multiple bubble lamellae division. The dominant mechanisms of residual oil mobilization and displacement by the foam in water-wet media were found to be direct displacement and emulsification of oil. The dominant mechanism of foam propagation and residual oil mobilization in oil-wet system was identified as the generation of pore spanning continuous gas foam. Inter-bubble trapping of oil and water, lamellae detaching and collapsing of SDS-foam were observed in presence of oil in both water-wet and oil-wet systems. Generally, the SiO2- SDS and Al2O3-SDS foams propagated successfully in oil-filled water-wet and oil-wet systems. Bubble coalescence was prevented during film stretching. The results of the fluid diversion process indicated an effective diversion of fluid in layered macroscopic model with permeability ratio of 8:1 in presence of SiO2 and Al2O3 nanoparticles. The outcomes of this research is a major breakthrough in prospective field applications of nanoparticles-surfactant foams in oil-filled water-wet and oil-wet porous media

Geochemical interactions in geological hydrogen Storage: The role of sandstone clay content

Hydrogen holds promise as a clean energy alternative, crucial for achieving global decarbonization goals and net-zero carbon emissions. Its low volumetric energy density necessitates underground storage in sandstone formations to maintain year-round supply. The efficacy of such storage hinges on the geochemical interplay between hydrogen and the host sandstone. Despite the slow reaction rates in sandstone, the influence of its clay composition on hydrogen interaction remains underexplored. In this study, we specifically investigate the geochemical interactions of hydrogen with clay-bearing sandstone formations under controlled conditions, simulating storage scenarios. This study evaluates the impact of clay on hydrogen-sandstone geochemistry after 75 days of injection at 1500 psi and 75 °C into Berea and Bandera gray sandstone cores, utilizing microcomputed tomography to assess changes in pore structure. Our results reveal that, even in sandstones with high clay content, there is negligible alteration in porosity and mineral content, as well as minimal clay and quartz dissolution or expansion over storage time, indicating stability in these formations. These findings provide crucial insights for selecting suitable geological formations for hydrogen storage, supporting the global shift towards sustainable energy systems Our study contributes to the global efforts in decarbonization by providing essential guidance on the feasibility of using clay-bearing sandstone formations for efficient and sustainable hydrogen storage

Evaluation of cubic, PC-SAFT, and GERG2008 equations of state for accurate calculations of thermophysical properties of hydrogen-blend mixtures

Hydrogen (H2) is a clean fuel and key enabler of energy transition into green renewable sources and a method of achieving net-zero emissions by 2050. Underground H2 storage (UHS) is a prominent method offering a permanent solution for a low-carbon economy to meet the global energy demand. However, UHS is a complex procedure where containment security, pore-scale scattering, and large-scale storage capacity can be influenced by H2 contamination due to mixing with cushion gases and reservoir fluids. The literature lacks comprehensive investigations of existing thermodynamic models in calculating the accurate transport properties of H2-blend mixtures essential to the efficient design of various H2 storage processes. This work benchmarks cubic equations of state (EoSs), namely Peng–Robinson (PR) and Soave Redlich–Kwong (SRK) and their modifications by Boston–Mathias (PR-BM) and Schwartzentruber–Renon (SR-RK), for their reliability in predicting the thermophysical properties of binary and ternary H2-blend mixtures, including CH4, C2H6, C3H8, H2S, H2O, CO2, CO, and N2, in addition to Helmholtz-energy-based EoSs (i.e., PC-SAFT and GERG2008). The benchmarked models are regressed against the experimental data for vapor–liquid equilibrium (VLE) that covers a wide range of pressures (0.01 to 101 MPa), temperatures (92 K to 367 K), and mole fractions (0.001 to 0.90) of H2. The novelty of this work is in benchmarking and optimizing the parameters of the mentioned EoSs to study VLE envelopes, densities, and other critical transport properties, such as heat capacity and the Joule–Thomson coefficient of H2 mixtures in a wide range of associated conditions. The results highlight the significant effect of the temperature-dependent binary interaction parameters on the calculations of thermophysical properties. The SR-RK EoS demonstrated the highest agreement with VLE data among the cubic EoSs with a low root mean square error and absolute average deviation. The PC-SAFT VLE models demonstrated results comparable to the SR-RK. The sensitivity analysis highlighted the high influence of impurity on changing the thermophysical behavior of H2-blend streams during the H2 storage process

Influence of organic molecules on wetting characteristics of mica/H2/brine systems: Implications for hydrogen structural trapping capacities

Hypothesis: Actualization of the hydrogen (H2) economy and decarbonization goals can be achieved with feasible large-scale H2 geo-storage. Geological formations are heterogeneous, and their wetting characteristics play a crucial role in the presence of H2, which controls the pore-scale distribution of the fluids and sealing capacities of caprocks. Organic acids are readily available in geo-storage formations in minute quantities, but they highly tend to increase the hydrophobicity of storage formations. However, there is a paucity of data on the effects of organic acid concentrations and types on the H2-wettability of caprock-representative minerals and their attendant structural trapping capacities. Experiment: Geological formations contain organic acids in minute concentrations, with the alkyl chain length ranging from C4 to C26. To fully understand the wetting characteristics of H2 in a natural geological picture, we aged mica mineral surfaces as a representative of the caprock in varying concentrations of organic molecules (with varying numbers of carbon atoms, lignoceric acid C24, lauric acid C12, and hexanoic acid C6) for 7 days. To comprehend the wettability of the mica/H2/brine system, we employed a contact-angle procedure similar to that in natural geo-storage environments (25, 15, and 0.1 MPa and 323 K). Findings: At the highest investigated pressure (25 MPa) and the highest concentration of lignoceric acid (10−2 mol/L), the mica surface became completely H2 wet with advancing (θa= 106.2°) and receding (θr=97.3°) contact angles. The order of increasing θa and θr with increasing organic acid contaminations is as follows: lignoceric acid \u3e lauric acid \u3e hexanoic acid. The results suggest that H2 gas leakage through the caprock is possible in the presence of organic acids at higher physio-thermal conditions. The influence of organic contamination inherent at realistic geo-storage conditions should be considered to avoid the overprediction of structural trapping capacities and H2 containment security

Influence of pressure, temperature and organic surface concentration on hydrogen wettability of caprock, implications for hydrogen geo-storage

Hydrogen (H2) as a cleaner fuel has been suggested as a viable method of achieving the de-carbonization objectives and meeting increasing global energy demand. However, successful implementation of a full-scale hydrogen economy requires large-scale hydrogen storage (as hydrogen is highly compressible). A potential solution to this challenge is injecting hydrogen into geologic formations from where it can be withdrawn again at later stages for utilization purposes. The geo-storage capacity of a porous formation is a function of its wetting characteristics, which strongly influence residual saturations, fluid flow, rate of injection, rate of withdrawal, and containment security. However, literature severely lacks information on hydrogen wettability in realistic geological and caprock formations, which contain organic matter (due to the prevailing reducing atmosphere). We, therefore, measured advancing (θa) and receding (θr) contact angles of mica substrates at various representative thermo-physical conditions (pressures 0.1-25 MPa, temperatures 308–343 K, and stearic acid concentrations of 10−9 - 10−2 mol/L). The mica exhibited an increasing tendency to become weakly water-wet at higher temperatures, lower pressures, and very low stearic acid concentration. However, it turned intermediate-wet at higher pressures, lower temperatures, and increasing stearic acid concentrations. The study suggests that the structural H2 trapping capacities in geological formations and sealing potentials of caprock highly depend on the specific thermo-physical condition. Thus, this novel data provides a significant advancement in literature and will aid in the implementation of hydrogen geo-storage at an industrial scale

Saudi Arabian basalt/CO2/brine wettability: Implications for CO2 geo-storage

The geological sequestration of carbon dioxide, including mineralization in basaltic formations, has been identified as a promising method of attaining a low-carbon economy. However, successful CO2 storage depends on both the CO2 wettability of the basaltic rocks and the basalt rock-fluid interfacial interactions. The contact angles of brine/CO2 systems for Western Australian (WA) and Iceland basalts have been recently reported in the literature. However, contact angle datasets for evaluating the CO2 wettability of Saudi Arabian (SA) basalt have not been previously reported. Moreover, there is limited information on the impact of organic acids on the wettability of the basalt/CO2/brine system. In the present study, the contact angles of supercritical CO2/brine systems on SA basalt are measured at temperatures of 298 and 323 K, and at various pressures of 0.1 – 20 MPa in the absence and presence of organic acid (10 − 2 mol/L stearic acid). Various analytical methods are used to characterize the SA basalt surface, and the wetting behavior of the SA basalt is compared with that of the WA and Iceland basalts. The quantity of CO2 that can be safely trapped underneath the SA basalt (in terms of CO2 column height) is then computed from the experimental data. At the highest tested temperature and pressure (20 MPa and 323 K), the pure SA basalt is found to remain strongly water-wet, with advancing (θa) and receding (θr) contact angles of 46.7° and 43.2°, respectively, whereas the Iceland basalt becomes moderately water-wet (θa = 85.1° and θr = 81.8°), and the WA basalt becomes CO2-wet (θa = 103.6° and θr = 96.1°). However, the organic-aged SA basalt attains a CO2-wet state (θa = 106.8° and θr = 95.2°). In addition, the CO2 column height of the pure SA basalt is higher than that reported for the WA and Iceland basalts. Further, at 323 K, the CO2 column height decreases from 835 m at 5 MPa to −957 m at 20 MPa. These results suggest that there could be both freer plumb and lateral movement of CO2 into the SA basalt in the presence of organic acid, thus resulting in lower residual and mineral trapping capacities, and fewer eventual leakages of CO2, across the geological formation

Enhancing wettability prediction in the presence of organics for hydrogen geo-storage through data-driven machine learning modeling of rock/H2/brine systems

The success of geological H2 storage relies significantly on rock–H2–brine interactions and wettability. Experimentally assessing the H2 wettability of storage/caprocks as a function of thermos-physical conditions is arduous because of high H2 reactivity and embrittlement damages. Data-driven machine learning (ML) modeling predictions of rock–H2–brine wettability are less strenuous and more precise. They can be conducted at geo-storage conditions that are impossible or hazardous to attain in the laboratory. Thus, ML models were utilized in this research to accurately model the wettability behavior of a ternary system consisting of H2, rock minerals (quartz and mica), and brine at different operating geological conditions. The results revealed that the ML models accurately captured the wettability behavior at different geo-storage conditions by yielding less than 5% mean absolute percent error and above 0.95 coefficient of determination values. The partial dependency or sensitivity plots were generated to evaluate the impact of individual features on the trained models. These plots revealed that the models accurately captured the physics behind the problem. Furthermore, a mathematical equation is derived from the trained ML model to predict the wettability behavior without using any ML software. The accuracy of the predictions of the ML model can be beneficial for exactly predicting the H2 geo-storage capacities and assessing of H2 containment security of storage and caprocks for large-scale geo-storage projects

Effect of methylene blue on wetting characteristics of quartz/H2/brine systems: Implication for hydrogen geological storage

Hydrogen (H2) is considered a promising replacement for fossil fuels due to its enormous potential as an environmentally friendly and sustainable option compared to carbon-based fossil fuels. However, storing the vast quantity of H2 required to satisfy the global energy demand on the earth\u27s surface can be difficult due to its compressibility and volatility. The best option for large-scale storage is underground H2 storage (UHS), which can be retrieved when needed. Rock wettability is vital in UHS because it determines the H2 storage capacity, containment security, and potential withdrawal and injection rates. Organic acid inherent in storage formations could make the storage rock H2-wet and reduce the residually trapped H2; thus, recent research efforts have concentrated on modifying sandstone formations contaminated with organic acid through chemical injections, such as nanofluids and methyl orange. However, previous research has not considered applying methylene blue (MB) as a rock wettability modifier to promote successful UHS. In addition, MB is a toxic constituent of wastewater, causing pollution. This research aims to dispose of MB in underground reservoirs to alter the wettability and increase the H2 storage capacity, mitigating anthropogenic carbon dioxide emissions. We assess the application of MB as a chemical agent for altering the wettability of quartz contaminated with stearic acid to promote H2 geological storage. Based on the contact-angle measurements, quartz aged with the optimum concentration of MB (100 mg/L) has the least advancing ( a= 35°), and receding ( r= 32°) angles at 13 MPa and 50 °C, changing the wettability to strongly water-wet. We demonstrate that an injection of MB into geological formations could make the rock water-wet, promoting H2 containment security and assisting in the large-scale implementation of UHS

Effects of various solvents on adsorption of organics for porous and nonporous quartz CO2 brine systems: Implications for CO2 geo-storage

The underground geo-storage of carbon dioxide (CO2) is an essential component of the carbon capture and sequestration value chain. The success of CO2 containment depends on the wetting state of the rock, which controls the mechanism of fluid flow and distribution. The presence of organic acids in the storage formation introduces a considerable effect on the wettability of the rock / CO2 / brine system under various temperature and pressure conditions. Despite the previous studies on this topic, the impact of the substrate pores, the rock surface roughness, and the solvents used to prepare the organic acid solution under various temperatures and pressures has not yet been elucidated. In the present study, the contact angles of non-porous quartz and porous Fontainebleau quartz are measured in CO2 / brine systems at various pressures of 0.1-20 MPa and temperatures of 298 and 323 K. In addition, various solvents are used to prepare the stearic acid solution in order to assess their influence on the adsorption of organics for porous and non-porous quartz / CO2 / brine systems. The results clearly indicate that n-decane is the most effective solvent for solubilizing the stearic acid to attain full wettability of the substrate by CO2 due to its polar compatibility with the stearic acid. Generally, the porous aged Fontainebleau quartz exhibits higher contact angles than the aged non-porous quartz at higher pressures, and the unaged Fontainebleau surfaces demonstrate water wettability, with a wide range of advancing and receding contact angles of less than 90°. However, when the pressure is increased to 15 and 20 MPa in the CO2 / brine system, the contact angles of the Fontainebleau quartz are higher than those of pure quartz. These results suggest that the surface roughness of the rock merely amplifies the inherent surface chemistry and original wettability of the rock if surface conditions are hydrophobic

Enhancing the CO2 trapping capacity of Saudi Arabian basalt via nanofluid treatment: Implications for CO2 geo-storage

Mineralization reactions in basaltic formations have gained recent interest as an effective method for CO2 geo-storage in order to mitigate anthropogenic greenhouse gas emissions. The CO2/rock interactions, including interfacial tension and wettability, are crucial factors in determining the CO2 trapping capacity and the feasibility of CO2 geological storage in these formations. The Red Sea geological coast in Saudi Arabia has many basaltic formations, and their wetting characteristics are rarely reported in the literature. Moreover, organic acid contamination is inherent in geo-storage formations and significantly impacts their CO2 geo-storage capacities. Hence, to reverse the organic effect, the influence of various SiO2 nanofluid concentrations (0.05–0.75 wt%) on the CO2-wettability of organic-acid aged Saudi Arabian (SA) basalt is evaluated herein at 323 K and various pressures (0.1–20 MPa) via contact angle measurements. The SA basalt substrates are characterized via various techniques, including atomic force microscopy, energy dispersive spectroscopy, scanning electron microscopy, and others. In addition, the CO2 column heights that correspond to the capillary entry pressure before and after nanofluid treatment are calculated. The results show that the organic acid-aged SA basalt substrates become intermediate-wet to CO2-wet under reservoir pressure and temperature conditions. When treated with SiO2 nanofluids, however, the SA basalt substrates become weakly water-wet, and the optimum performance is observed at an SiO2 nanofluid concentration of 0.1 wt%. At 323 K and 20 MPa, the CO2 column height corresponding to the capillary entry pressure increases from −957 m for the organic-aged SA basalt to 6253 m for the 0.1 wt% nano-treated SA basalt. The results suggest that the CO2 containment security of organic-acid-contaminated SA basalt can be enhanced by SiO2 nanofluid treatment. Thus, the results of this study may play a significant role in assessing the trapping of CO2 in SA basaltic formations