Diffusion of CO2 in single-step silica nanofluid for subsurface utilization: an experimental study.

This study investigates the role of single-step silica nanofluids as additives to increase CO2 absorption in polymeric solutions for proposed oilfield applications. Using pressure decay approach, the study investigates the applicability of single-step silica nanofluids for CO2 absorption in a high pressure-high temperature (HPHT) cell. Various parameters like nanoparticle size (30-120 nm) and concentration (0.1-1 wt%) were investigated to ascertain the absorption performance of the nanofluids and optimization their application in subsurface applications as carrier fluids for CO2. The solutions under observation (deionized water and silica nanofluids) were pressurized under the desired pressure and temperature inside a stirring pot and the decline in pressure was continuously noted. To comprehensively cover the near-reservoir field conditions, the CO2 absorption was investigated in the pressure range of 5-10 MPa and at temperatures of 30-90 °C. While increasing the nanoparticle concentration (from 0.1 to 1 wt%) increased the CO2 absorption (evident by the sharper decline in pressure), increasing the nanoparticle size reduced the absorption capacity of the nanofluids as a lesser volume of decline in pressure was noted. Furthermore, increasing the temperature of the experimental investigation caused a major reduction (12-19%) in the pressure decay. However, it was also observed that higher pressure (> 7.5 MPa) was detrimental for CO2 absorption (due to its supercritical nature). Adding salt (sodium chloride, NaCl) was found to massively lower (up to 33%) while adding surfactant (sodium dodecyl sulfate, SDS) slightly increased the amount of CO2 absorption (in presence of salinity). Based on the observations of this study, the use of single-step silica nanofluids as CO2 carrier fluids is recommended for oilfield conditions where salinity is less than 4 wt%.

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.

Effect of nanoparticle on rheological properties of surfactant-based nanofluid for effective carbon utilization: capturing and storage prospects.

Previous studies have shown insufficient dispersion and thermal stability of nanofluids for high-temperature carbon capture and storage applications. Compared to the other NPs, TiO2 nanofluids exhibit superior stability due to their high zeta potential. In previous studies, TiO2 nanofluids have shown superior performance in heat transfer and cooling applications along with importing the stability of other nanofluids like SiO2 in form of nanocomposites. Therefore, in this study, a nanofluid formulation consisting of titania nanofluid in a base solution of ethylene glycol (EG) with different co-stabilizers such as surfactants was synthesized for better dispersion stability, enhanced electrical, and rheological properties especially for the use in high-temperature industrial applications which include carbon capture and storage along with enhanced oil recovery. The formulated nanofluid was investigated for stability using dynamic light scattering (DLS) study and electrical conductivity. Additionally, the formulated nanofluid was also examined for thermal stability at high temperatures using an electrical conductivity study followed by rheological measurements at 30 and 90 °C. At a high temperature, the shear-thinning behavior of EG was found highly affected by shear rate; however, this deformation was controlled using TiO2 nanoparticles (NPs). Furthermore, the role of surfactant was also investigated on dispersion stability, electrical conductivity followed by viscosity results, and it was found that the nanofluid is superior in presence of anionic surfactant sodium dodecyl sulfate (SDS) as compared to nonionic surfactant Triton X-100 (TX-100). The inclusion of ionic surfactant provides a charged layer of micelles surrounding the core of a NP and it produced additional surface potential. Consequently, it increases the repulsive force between two adjacent NPs and renders a greater stability to nanofluid while nonionic surfactant allowed monomers to adsorb on the surface of NP via hydrophobic interaction and enhances the short-range interparticle repulsion, to stabilize nanofluid. This makes titania nanofluid suitable for widespread high-temperature applications where conventional nanofluids face limitations. Finally, the application of the synthesized titania nanofluids was explored for the capture and transport of CO2 where the inclusion of the anionic surfactant was found to increase the CO2 capturing ability of titania nanofluids by 140-220% (over the conventional nanofluid) while also showing superior retention at both investigated temperatures. Thus, the study promotes the role of novel surfactant-treated titania nanofluids for carbon removal and storage and recommends their applications involving carbonated fluid injection (CFI) to carbon utilization in oilfield applications.