CO2 trapping dynamics in tight sandstone: Insights into trapping mechanisms in Mae Moh's reservoir.

The reliance on fossil fuels is a major contributor to increased anthropogenic CO2 emissions, driving global challenges such as climate change through the greenhouse effect. Carbon capture and storage (CCS) is a promising interdisciplinary technology aimed at mitigating these emissions by securely sequestering gigatons of CO2. This study focuses on the feasibility of storing point-source CO2 emissions in saline formations, with a particular emphasis on the Mae Moh coal-fired power plant in Lampang, Thailand, which is located near its associated coal mine. The region presents challenges due to tight sandstone reservoirs buried over 2000 m deep. With reservoir simulation, this study evaluates the impact of various factors on CO2 containment and trapping in these geological settings. Results show that elevated temperatures decrease structural trapping of 43.0%-28.9% and increase solubility trapping of 28.55%-46.5%, at 40 °C and 80 °C respectively. Hysteresis is found to enhance residual trapping by immobilizing up to 31.1% of CO2 within pore spaces at 0.5. Permeability heterogeneity has a minimal impact on overall trapping efficiency due to the less heterogeneity of the tight sandstone. However, the kV/kH ratio significantly influences vertical CO2 migration which resulted in residual trapping at its highest at the ratio of 0.1, while lower ratios support lateral dispersion. Moderate rock compressibility values are identified as optimal for structural and residual trapping, while extreme compressibility enhances solubility trapping by up to 30%. These findings emphasize the complexity of CO2 trapping mechanisms in tight sandstone formations, emphasizing the need for careful consideration of key factors in CCS projects.

Competitive Adsorption of Interfacially Active Nanoparticles and Anionic Surfactant at the Crude Oil-Water Interface.

The interfacial activity of poly(N-isopropylacrylamide) (pNIPAM) nanoparticles in the absence and presence of an anionic surfactant (sodium dodecyl sulfate, SDS) was studied at a crude oil-water interface. Both species are interfacially active and can lower the interfacial tension, but when mixed together, the interfacial composition was found to depend on the aging time and total component concentration. With the total component concentration less than 0.005 wt %, the reduced interfacial tension by pNIPAM was greater than SDS; thus, pNIPAM has a greater affinity to partition at the crude oil-water interface. However, the lower molecular weight (smaller molecule) of SDS compared to pNIPAM meant that it rapidly partitioned at the oil-water interface. When mixed, the interfacial composition was more SDS-like for low total component concentrations (≤ 0.001 wt %), while above, the interfacial composition was more pNIPAM-like, similar to the single component response. Applying a weighted arithmetic mean approach, the surface-active contribution (%) could be approximated for each component, pNIPAM and SDS. Even though SDS rapidly partitioned at the oil-water interface, it was shown to be displaced by the pNIPAM nanoparticles, and for the highest total component concentration, pNIPAM nanoparticles were predominantly contributing to the reduced oil-water interfacial tension. These findings have implications for the design and performance of fluids that are used to enhance crude oil production from reservoirs, particularly highlighting the aging time and component concentration effects to modify interfacial tensions.

Geomechanics contribution to CO2 storage containment and trapping mechanisms in tight sandstone complexes: A case study on Mae Moh Basin.

Recognized as a not-an-option approach to mitigate the climate crisis, carbon dioxide capture and storage (CCS) has a potential as much as gigaton of CO2 to sequestrate permanently and securely. Recent attention has been paid to store highly concentrated point-source CO2 into saline formation, of which Thailand considers one onshore case in the north located in Lampang - the Mae Moh coal-fired power plant matched with its own coal mine of Mae Moh Basin. Despite a large basin and short transport route from the source, target sandstone reservoir buried at deeper than 1000 m is of tight nature and limited data, while question on storing possibility has thereafter risen. The current study is thus aimed to examine the influence of reservoir geomechanics on CO2 storage containment and trapping mechanisms, with co-contributions from geochemistry and reservoir heterogeneity, using reservoir simulator - CMG-GEM. With the injection rate designed for 30-year injection, reservoir pressure build-ups were ∼77 % of fracture pressure but increased to ∼80 % when geomechanics excluded. Such pressure responses imply that storage security is associated with the geomechanics. Dominated by viscous force, CO2 plume migrated more laterally while geomechanics clearly contributed to lesser migration due to reservoir rock strength constraint. Reservoir geomechanics contributed to less plume traveling into more constrained spaces while leakage was secured, highlighting a significant and neglected influence of geomechanical factor. Spatiotemporal development of CO2 plume also confirms the geomechanics-dominant storage containment. Reservoir geomechanics as attributed to its respective reservoir fluid pressure controls development of trapping mechanisms, especially into residual and solubility traps. More secured storage containment after the injection was found with higher pressure, while less development into solubility trap was observed with lower pressure. The findings reveal the possibility of CO2 storage in tight sandstone formations, where geomechanics govern greatly the plume migration and the development of trapping mechanisms.

Discontinuous dewetting dynamics of highly viscous droplets on chemically heterogeneous substrates.

HYPOTHESIS: Droplet spreading on heterogeneous (chemical/structural) surfaces has revealed local disturbances that affect the advancing contact line. With droplet dewetting being less studied, we hypothesize that a receding droplet can be perturbed by localized heterogeneity which leads to irregular and discontinuous dewetting of the substrate. EXPERIMENTS: The sessile drop method was used to study droplet dewetting at a wettability boundary. One-half of a hydrophilic surface was hydrophobically modified with either i) methyloctyldichlorosilane or ii) clustered macromolecules. A Lattice Boltzmann method (LBM) simulation was also developed to determine the effect of contact angle hysteresis and boundary conditions on the droplet dynamics. FINDINGS: The two surface treatments were optimized to produce comparable water wetting characteristics. With a negative Gibbs free energy on the hydrophilic-half, the oil droplet receded to the hydrophobic-half. On the silanized surface, the droplet was pinned and the resultant droplet shape was a distorted spherical cap, having receded uniformly on the unmodified surface. Modifying the surface with clustered macromolecules, the droplet receded slightly to form a spherical cap. However, droplet recession was non-uniform and daughter droplets formed near the wettability boundary. The LBM simulation revealed that daughter droplets formed when θR > 164°, with the final droplet shape accurately described by imposing a diffuse wettability boundary condition.

Improving predictions of shale wettability using advanced machine learning techniques and nature-inspired methods: Implications for carbon capture utilization and storage.

The utilization of carbon capture utilization and storage (CCUS) in unconventional formations is a promising way for improving hydrocarbon production and combating climate change. Shale wettability plays a crucial factor for successful CCUS projects. In this study, multiple machine learning (ML) techniques, including multilayer perceptron (MLP) and radial basis function neural networks (RBFNN), were used to evaluate shale wettability based on five key features, including formation pressure, temperature, salinity, total organic carbon (TOC), and theta zero. The data were collected from 229 datasets of contact angle in three states of shale/oil/brine, shale/CO2/brine, and shale/CH4/brine systems. Five algorithms were used to tune MLP, while three optimization algorithms were used to optimize the RBFNN computing framework. The results indicate that the RBFNN-MVO model achieved the best predictive accuracy, with a root mean square error (RMSE) value of 0.113 and an R2 of 0.999993. The sensitivity analysis showed that theta zero, TOC, pressure, temperature, and salinity were the most sensitive features. This research demonstrates the effectiveness of RBFNN-MVO model in evaluating shale wettability for CCUS initiatives and cleaner production.

Interfacial behavior of core-shell composite nanoparticles under compression and shear: Influence of polymer shell thickness.

HYPOTHESIS: The mobility of core-shell nanoparticles partitioned at an air-water interface is strongly governed by the compliance of the polymer shell. EXPERIMENTS: The compressional, relaxation and shear responses of two polymer-coated silica nanoparticles (CPs) were studied using a Langmuir trough and needle interfacial shear rheometer, and the corresponding structures of the particle-laden interfaces were visualized using Brewster angle and scanning electron microscopy. FINDINGS: The mobility of CPs partitioned at an air-water interface correlates to the polymer MW. In compression, the CPs40-laden interface (silica nanoparticles coated with 40 kDa PVP) showed distinct gas-liquid-solid phase transitions and when the surface pressure was reduced, the compressed particle-laden interface relaxed to its original state. The compressed-state of the CPs8-laden interface did not relax, and wrinkles in the particle-laden film that had formed in compression remained due to greater adhesion between the compressed particles. The increased mobility of the CPs40-laden interface translated to lower surface shear moduli, with the viscoelastic moduli an order of magnitude or more lower in the CPs40-laden interface than the CPs8-laden interface. Ultimately this contributed to changing the stability of particle-stabilized foams, with less mobile interfaces providing improved foam stability.

The effect of cationic surfactants on improving natural clinoptilolite for the flotation of cesium.

Flotation using cationic surfactants has been investigated as a rapid separation technique to dewater clinoptilolite ion exchange resins, for the decontamination of radioactive cesium ions (Cs+) from nuclear waste effluent. Initial kinetic and equilibrium adsorption studies of cesium, suggested the large surface area to volume ratio of the fine zeolite contributed to fast adsorption kinetics and high capacities (qc = 158.3 mg/g). Adsorption of ethylhexadecyldimethylammonium bromide (EHDa-Br) and cetylpyridinium chloride (CPC) surfactant collectors onto both clean and 5 ppm Cs+ contaminated clinoptilolite was then measured, where distribution coefficients (Kd) as high as 10,000 mL/g were evident with moderate concentrations CPC. Measurements of particle sizes confirmed that adsorption of surfactant monolayers did not lead to significant aggregation of the clinoptilolite, while < 8% of the 5 ppm contaminated cesium was remobilised. Importantly for flotation, both the recovery efficiency and dewatering ratios were measured across various surfactant concentrations. Optimum conditions were found with 0.5 mM of CPC and addition of 30 µL of MIBC frother, giving a recovery of ∼90% and a water reduction ratio > 4, highlighting the great viability of flotation to separate and concentrate the contaminated powder in the froth phase.

Dewetting dynamics of heavy crude oil droplet in low-salinity fluids at elevated pressures and temperatures.

HYPOTHESIS: Improved oil recovery by low-salinity injection correlates to the optimal brine concentration to achieve maximum dewetting of oil droplets on rock surfaces. While interfacial tension and electrical double layer forces are often cited as being determinant properties, we hypothesize that other structural/interfacial forces are more prominent in governing the system behavior. EXPERIMENTS: The sessile droplet technique was used to study the receding dynamics of oil droplets from flat hydrophilic substrates in brines of different salt type (NaCl and CaCl2) and concentration, and were studied at both low and elevated temperatures (60 and 140 °C) and pressures (1, 10, 100 and 200 bar). FINDINGS: At 1 bar and 60 °C, the minimum oil droplet-substrate adhesion force (FA) was determined at 34 mM NaCl and 225 mM CaCl2. For NaCl this strongly correlated to strengthening hydration forces, which for CaCl2 were diminished by long-range hydrophobic forces. These results highlight the importance of other non-DLVO forces governing the dewetting dynamics of heavy crude oil droplets. At 140 °C and 200 bar, the optimal brine concentrations were found to be much higher (1027 mM NaCl and 541 mM CaCl2), with higher concentrations likely attributed to weakening hydration forces at elevated temperatures.