CO2 capturing evaluation of single-step silica nanofluid through rheological investigation for nanofluid use in carbon utilization applications

Modified smart water flooding for promoting carbon dioxide utilization in shale enriched heterogeneous sandstone under surface conditions for oil recovery and storage prospects

Modern oil reservoirs exhibit high macro-scale heterogeneity, i.e., presence of shales and clays, which complicate the implementation of conventional enhanced oil recovery (EOR) practices. Hence, there is a need to investigate new class of EOR methods which not only improve recovery of oil from reservoir but also reduce formation damage. Thus, in this study, synthetic smart brines of varying salinity were formulated to investigate carbon utilization in shaly-sandstone for oil recovery and sequestration applications. To prepare shaly-sandstone samples, shale content in sand varied between 0 and 25 wt%. The addition of shale reduced porosity and permeability of sand-packs, and porosity ~ 25 and permeability < 10 md were measured for a combination of 75% sand + 25% shale which were originally 38% and 692 md for 100% sand + 0% shale. The oil recovery experiments were performed at temperature ≈ 40 °C and ambient pressure. The impact of shale content was insignificant on CO₂-based oil recovery resulting its value remained nearly constant (5-7%). Smart saline water (SSW) solutions were prepared through the dilution of formation water (FW) of typical oilfield salinity and used these SSW solutions in investigating shale swelling and interfacial tension with CO₂. Compared to other SSW solutions, SSW-2 (1 part FW/9 part water: 1/10th of FW) demonstrated superior control on mitigating shale swelling (by 67%) and reduce interfacial tension (by 30%) when compared to FW. Moreover, it helped to mobilize higher amount of oil (50% OOIP) from sand-pack (80% sand + 20% shale) in which conventional water flood failed to perform, indicating its viability for EOR from heterogeneous reservoir. In addition, SSW solutions promoted use of carbonated (CO₂-enriched) water injection for oil recovery from sandstone exhibiting high shale content of 20% as over 5-8% higher oil recovery was obtained compared to conventional water flooding. Comparative performance of water flooding, salinity water-alternating CO₂ flooding and carbonated smart water injection in heterogeneous sandstone.

Investigation of SiO2 Nanoparticle Retention in Flow Channels, Its Remediation Using Surfactants and Relevance of Artificial Intelligence in the Future

In this study, the effect of these variables on commercial silica NP retention was presented in a fabricated flow model considering only the physical adsorption aspects of silica NP retention. From our observations, it was established that while silica NP concentration, flow rate and salt are key variables in influencing silica NP agglomeration and retention, the effect of temperature was highly subdued. The effect of salt-induced agglomeration was particularly severe at moderate salinity (≈4 wt% NaCl). To mitigate the effect of salt-induced agglomeration, a commonly used anionic surfactant, sodium dodecyl sulfate (SDS) was added to the solution and the silica NP retention was tabulated. An amount of 0.3 wt% SDS was found to negate salt-induced agglomeration significantly, paving the way for use of silica NP solutions, even in the presence of saline conditions. A section on the prospective use of artificial intelligence for this purpose has been included. This study is useful for understanding NP retention behaviour, especially in the presence of salinity and its mitigation using surfactants, in flow applications.