Effect of humic acid on CO2-wettability in sandstone formation

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.

Impact of injection temperature and formation slope on CO2 storage capacity and form in the Ordos Basin, China

Carbon dioxide (CO2) storage capacity is the main criterion for assessing CO2 geological storage. Based on actual data from the Shiqianfeng formation in the Ordos Basin, three-dimensional (3D) models were built using the TOUGHVISUAL visualization software and simulated using the TOUGH2 integral finite difference modeling code with the ECO2N fluid property module to explore the impact of formation attributes (formation slope) and controllable factors (injection temperature) on CO2 storage capacity. A total of 16 schemes were designed, with four injection temperatures (24 ℃, 31 ℃, 38 ℃, and 45 ℃) and four formation slopes (0°, 5°, 10°, and 15°). Simulation results showed that the injection temperature and formation slope both had a significant influence on CO2 storage capacity. The impact of injection temperature on the total storage amount was more obvious than that of the impact of formation slope. A higher injection temperature resulted in a greater total storage amount. Increasing the formation slope and injection temperature increased the gas-phase, dissolved-phase, and total CO2 storage amounts in the upper left section of the injection well, but decreased them in the lower right part of the injection well. The impact of formation slope on the conversion rate from gas-phase CO2 to dissolved-phase CO2 was more obvious than the impact of injection temperature. A steeper formation slope resulted in a higher conversion rate. A smaller formation slope and a higher injection temperature should be selected to store CO2.

Coal fines migration: A holistic review of influencing factors

Coal fines can substantially influence coal seam gas reservoir permeability, thus impeding the flow of gas in coal microstructure. The coal fines generation and migration are influenced by several factors, wherein coal fines are generally hydrophobic and aggregate in natural coal seam gas (CSG) under prevailing conditions of pH, salinity, temperature and pressure. This aggregation behaviour can damage the coal matrix and cleat system permeabilities, leading to a considerable reduction of proppant pack conductivity (i.e. fracture conductivity). Several datasets have been reported within the literature on this subject in the last decade. However, a more up-to-date discussion of this area is key to understanding coal fines migration and associated knowledge. Thus, in this review, we conduct a systematic investigation of coal fines and their influencing factors. Here, coal fines are introduced, followed by an initial holistic investigation of their generation, plugging, movement, redistribution and production. Then, in order to enhance current understandings of the subject matter, a parametric evaluation of the factors noted earlier is conducted, based on recently published literature. Subsequently, the published mathematical and analytical models for fines generation are reviewed. Finally, the implications and challenges associated with coal fines mitigation are discussed.

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 (θ_a= 106.2°) and receding (θ_r=97.3°) contact angles. The order of increasing θ_a and θ_r with increasing organic acid contaminations is as follows: lignoceric acid > lauric acid > 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 mineralogy and surfactant concentration on zeta potential in intact sandstone at high pressure

HYPOTHESIS

Zeta-potential in the presence of brine has been studied for its application within hydrocarbon reservoirs. These studies have shown that sandstone's zeta-potential remains negatively charged, non-zero, and levels-off at salinities > 0.4 mol.dm^-3, thus becoming independent of salinity when ionic strength is increased further. However, research conducted to date has not yet considered clay-rich (i.e. clay ≥ 5 wt%) sandstones.

EXPERIMENTS

Firstly, streaming potential measurements were conducted on Bandera Gray sandstones (clay-rich and clay-poor) with 0.6 and 2 mol.dm^-3 NaCl brine-saturated in pressurised environments (6.895 MPa overburden and 3.447 MPa back-pressure). Secondly, the streaming potential was determined at identical conditions for the effect of two surfactants, SDBS and CTAB, at concentrations of 0.01 and 0.1 wt% on the clay-poor sample in 0.6 mol.dm^-3 NaCl. Thirdly, a comparison of zeta potentials determined via electrophoretic and streaming potential was conducted. Accordingly, this work analyses the effects of mineralogy and surfactants within this process.

FINDINGS

Clay-rich sandstone possessed lower zeta-potentials than clay-poor sandstone at the two tested salinities. SDBS reduced zeta-potential and yielded higher repulsive forces rendering the rock more hydrophilic. Additionally, electrophoretic zeta-potentials were higher when compared to streaming zeta-potentials. Mechanisms for the observed phenomena are also provided.

Western Australia basalt-CO2-brine wettability at geo-storage conditions

HYPOTHESIS

CO₂ geo-storage is a technique, where millions of tonnes of CO₂ are stored in underground formations every year for permanent immobilization to reduce greenhouse gas emissions. Among promising geo-storage formations, basalt is attracting keen interest from researchers and industry. However, the literature severely lacks information on the wetting behaviour of basaltic rocks at geo-storage conditions.

EXPERIMENTS

To enable a more general statement of basalt-scCO₂-brine contact angles, the wettability of a basalt from Western Australia was compared with a similar rock type from Iceland. This study reports the advancing and receding contact angles for a basalt-scCO₂-brine system at pressures ranging from 0.1 to 20 MPa and temperatures of 298 and 323 K, respectively. Based on the experimental data, the amount of CO₂, expressed by the column height, which could be safely trapped beneath the basalt was then calculated.

FINDINGS

The basalt was initially water-wet but with increasing pressure, it was converted sequentially from a water-wet to an intermediate-wet and then finally into a completely CO₂-wet template at pressures exceeding 15 MPa and 323 K. Under those experimental conditions, found in the field at depths below 1500 m, injected supercritical CO₂ into a porous basalt reservoir is assumed to flow freely in lateral and vertical directions and is less impeded by capillary/residual trapping, potentially leading to CO₂ leakage. It is suggested that the injection depth should not be chosen too deep to avoid increased free CO₂ plume mobility. It is found from CO₂ column height calculations that at 800 m depth (a minimum requirement to keep CO₂ supercritical), the height of the CO₂ column that can be safely trapped below the cap rock, was still 100 m but shrank to nil at ≥1500 m.