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

Chemical and Physical Architecture of Macromolecular Gels for Fracturing Fluid Applications in the Oil and Gas Industry; Current Status, Challenges, and Prospects

Hydraulic fracturing is vital in recovering hydrocarbons from oil and gas reservoirs. It involves injecting a fluid under high pressure into reservoir rock. A significant part of fracturing fluids is the addition of polymers that become gels or gel-like under reservoir conditions. Polymers are employed as viscosifiers and friction reducers to provide proppants in fracturing fluids as a transport medium. There are numerous systems for fracturing fluids based on macromolecules. The employment of natural and man-made linear polymers, and also, to a lesser extent, synthetic hyperbranched polymers, as additives in fracturing fluids in the past one to two decades has shown great promise in enhancing the stability of fracturing fluids under various challenging reservoir conditions. Modern innovations demonstrate the importance of developing chemical structures and properties to improve performance. Key challenges include maintaining viscosity under reservoir conditions and achieving suitable shear-thinning behavior. The physical architecture of macromolecules and novel crosslinking processes are essential in addressing these issues. The effect of macromolecule interactions on reservoir conditions is very critical in regard to efficient fluid qualities and successful fracturing operations. In future, there is the potential for ongoing studies to produce specialized macromolecular solutions for increased efficiency and sustainability in oil and gas applications.

Impact of Methylene Blue on Enhancing the Hydrocarbon Potential of Early Cambrian Khewra Sandstone Formation from the Potwar Basin, Pakistan

Significant amounts of hydrocarbon resources are left behind after primary and secondary recovery processes, necessitating the application of enhanced oil recovery (EOR) techniques for improving the recovery of trapped oil from subsurface formations. In this respect, the wettability of the rock is crucial in assessing the recovery and sweep efficiency of trapped oil. The subsurface reservoirs are inherently contaminated with organic acids, which renders them hydrophobic. Recent research has revealed the significant impacts of nanofluids, surfactants, and methyl orange on altering the wettability of organic-acid-contaminated subsurface formations into the water-wet state. This suggests that the toxic dye methylene blue (MB), which is presently disposed of in huge quantities and contaminates subsurface waters, could be used in EOR. However, the mechanisms behind hydrocarbon recovery using MB solution for attaining hydrophilic conditions are not fully understood. Therefore, the present work examines the impacts of MB on the wettability reversal of organic-acid-contaminated Khewra sandstone samples (obtained from the outcrop in the Potwar Basin, Pakistan) under the downhole temperature and pressure conditions. The sandstone samples are prepared by aging with 10-2 mol/L stearic acid and subsequently treated with various amounts of aqueous MB (10-100 mg/L) for 1 week. Contact angle measurements are then conducted under various physio-thermal conditions (0.1-20 MPa, 25-50 °C, and salinities of 0.1-0.3 M). The results indicate that the Khewra sandstone samples become hydrophobic in the presence of organic acid and under increased pressure, temperature, and salinity. However, the wettability changes from oil-wet to preferentially water-wet in the presence of various MB solutions, thus highlighting the favorable effects of MB on EOR from the Khewra sandstone formation. Moreover, the most significant change in wettability is observed for the Khewra sandstone sample that was aged using 100 mg/L MB. These results suggest that injecting MB into deep underground Khewra sandstone reservoirs may produce more residual hydrocarbons.

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.

Influence of stearic acid and alumina nanofluid on CO2 wettability of calcite substrates: Implications for CO2 geological storage in carbonate reservoirs

HYPOTHESIS

Atmospheric CO₂ emissions trigger global warming and climate change challenges. Thus, geological CO₂ storage appears to be the most viable choice to mitigate CO₂ emissions in the atmosphere. However, the adsorption capacity of reservoir rock in the presence of diverse geological conditions, including organic acids, temperature, and pressure, can cause reduced certainty for CO₂ storage and injection problems. Wettability is critical in measuring the adsorption behavior of rock in various reservoir fluids and conditions.

EXPERIMENT

We systematically evaluated the CO₂-wettability of calcite substrates at geological conditions (323 K and 0.1, 10, and 25 MPa) in the presence of stearic acid (a replicate realistic reservoir organic material contamination). Similarly, to reverse the effects of organics on wettability, we treated calcite substrates with various alumina nanofluid concentrations (0.05, 0.1, 0.25, and 0.75 wt%) and evaluated the CO₂-wettability of calcite substrates at similar geological conditions.

FINDINGS

Stearic acid profoundly affects the contact angle of calcite substrates where wettability shifts from intermediate to CO₂-wet conditions, reducing the CO₂ geological storage potential. The treatment of organic acid-aged calcite substrates with alumina nanofluid reversed the wettability to a more hydrophilic state, increasing CO₂ storage certainty. Further, the optimum concentration displaying the optimum potential for changing the wettability in organic acid-aged calcite substrates was 0.25 wt%. The effect of organics and nanofluids should be augmented to improve the feasibility of CO₂ geological projects at the industrial scale for reduced containment security.