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Fulltext Influence of Henna Extracts on Static and Dynamic Adsorption of Sodium Dodecyl Sulfate and Residual Oil Recovery from Quartz Sand

Mohd Musa MS, Gopalan PY, Yekeen N, Al-Yaseri A

ACS Omega, 2023 Apr 11;8(14):13118-13130.
PMID: 37065015 DOI: 10.1021/acsomega.3c00371

The application of surfactant flooding for enhanced oil recovery (EOR) promotes hydrocarbon recovery through reduction of oil-water interfacial tension and alteration of oil-wet rock wettability into the water-wet state. Unfortunately, surfactant depletion in porous media, due to surfactant molecule adsorption and retention, adversely affects oil recovery, thus increasing the cost of the surfactant flooding process. Chemical-based materials are normally used as inhibitors or sacrificial agents to minimize surfactant adsorption, but they are quite expensive and not environmentally friendly. Plant-based materials (henna extracts) are far more sustainable because they are obtained from natural sources. However, there is limited research on the application of henna extracts as inhibitors to reduce dynamic adsorption of the surfactant in porous media and improve oil recovery from such media. Thus, henna extracts were introduced as an eco-friendly and low-cost sacrificial agent for minimizing the static and dynamic adsorption of sodium dodecyl sulfate (SDS) onto quartz sand in this study. Results showed that the extent of surfactant adsorption was inversely proportional to the henna extract concentration, and the adsorption of the henna extract onto the quartz surface was a multilayer adsorption that followed the Freundlich isotherm model. Precisely, the henna extract adsorption on quartz sand is in the range of 3.12-4.48 mg/g (for static adsorption) and 5.49-6.73 mg/g (for dynamic adsorption), whereas the SDS adsorption on quartz sand was obtained as 2.11 and 4.79 mg/g at static and dynamic conditions, respectively. In the presence of 8000 mg/L henna extract, SDS static and dynamic adsorption was significantly reduced by 64 and 82%, respectively. At the same conditions, the residual oil recovery increased by 9.2% over normal surfactant flooding. The study suggests that the use of henna extracts as a sacrificial agent during SDS flooding could result in the reduction of static and dynamic adsorption of surfactant molecules on quartz sand, thus promoting hydrocarbon recovery from sandstone formations.
Fulltext Synergetic Effect of Surfactant Concentration, Salinity, and Pressure on Adsorbed Methane in Shale at Low Pressure: An Experimental and Modeling Study

Abdulelah H, Negash BM, Yekeen N, Al-Hajri S, Padmanabhan E, Al-Yaseri A

ACS Omega, 2020 Aug 18;5(32):20107-20121.
PMID: 32832765 DOI: 10.1021/acsomega.0c01738

The influence of an anionic surfactant, a cationic surfactant, and salinity on adsorbed methane (CH4) in shale was assessed and modeled in a series of systematically designed experiments. Two cases were investigated. In case 1, the crushed Marcellus shale samples were allowed to react with anionic sodium dodecyl sulfate (SDS) and brine. In case 2, another set of crushed Marcellus shale samples were treated with cetyltrimethylammonium bromide (CTAB) and brine. The surfactant concentration and salinity of brine were varied following the Box-Behnken experimental design. CH4 adsorption was then assessed volumetrically in the treated shale at varying pressures (1-50 bar) and a constant temperature of 30 °C using a pressure equilibrium cell. Mathematical analysis of the experimental data yielded two separate models, which expressed the amount of adsorbed CH4 as a function of SDS/CTAB concentration, salinity, and pressure. In case 1, the highest amount of adsorbed CH4 was about 1 mmol/g. Such an amount was achieved at 50 bar, provided that the SDS concentration is kept close to its critical micelle concentration (CMC), which is 0.2 wt %, and salinity is in the range of 0.1-20 ppt. However, in case 2, the maximum amount of adsorbed CH4 was just 0.3 mmol/g. This value was obtained at 50 bar and high salinity (∼75 ppt) when the CTAB concentration was above the CMC (>0.029 wt %). The findings provide researchers with insights that can help in optimizing the ratio of salinity and surfactant concentration used in shale gas fracturing fluid.
Fulltext Influence of organic molecules on wetting characteristics of mica/H2/brine systems: Implications for hydrogen structural trapping capacities

Ali M, Yekeen N, Pal N, Keshavarz A, Iglauer S, Hoteit H

J Colloid Interface Sci, 2022 Feb 15;608(Pt 2):1739-1749.
PMID: 34742087 DOI: 10.1016/j.jcis.2021.10.080

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 (θa= 106.2°) and receding (θr=97.3°) contact angles. The order of increasing θa and θr 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.
An experimental workflow to assess the applicability of microemulsions for conformance improvement in oil-bearing reservoir

Pal N, Alzahid Y, AlSofi AM, Ali M, Yekeen N, Hoteit H

Heliyon, 2023 Jul;9(7):e17667.
PMID: 37539136 DOI: 10.1016/j.heliyon.2023.e17667

A comprehensive workflow approach is necessary to link multiple experimental tasks and identify microemulsion (ME) formulations with 'optimal' stability, displacement behavior and technical feasibility in the petroleum industry. In this paper, a systematic approach is described with the aid of a case study which involves the formulation of an anionic sodium dodecyl sulfate-based microemulsion. The design of such ME systems requires a proper methodology, substantial laboratory work, and functional assessment from research/industrial viewpoints. The surfactant has been screened in terms of its micellization potential, followed by phase behavior analysis and Winsor classification of prepared microemulsions. The desired composition(s) are characterized via several tools to determine droplet size, morphology, oil/water solubilization potentials and salinity scan results. The suitability of the microemulsion system for conformance improvement technology (CIT) is proposed to be assessed via physicochemical evaluation studies encompassing two attributes: rheology and stability. For a favorable 'conforming' drive, the microemulsion must exhibit phase stability, sufficient injectivity, and moderate-to-high viscosity under shear. Technical assessment by the industry and research team must also include factors related to cost, availability of chemicals, environmental degradation, and reservoir considerations. The article demonstrates a comprehensive all-inclusive workflow methodology to design and formulate surfactant-stabilized microemulsions via case study analysis for application in CIT. This represents a sound approach to identifying efficient, cost-effective injection fluid systems and provides a framework to identify useful parameters for ME formulation design and employ the proposed (effective) strategy for conformance control.
Application of foam assisted water-alternating-gas flooding and quantification of resistivity and water saturation by experiment and simulation to determine foam propagation in sandstone

Khan JA, Kim J, Irawan S, Permatasar KA, Verdin PG, Cai B, et al.

Heliyon, 2024 Feb 15;10(3):e25435.
PMID: 38333865 DOI: 10.1016/j.heliyon.2024.e25435

Foam flooding by Foam Assisted Water-Alternating-Gas (FAWAG) is an important enhanced oil recovery method that has proven successful in experimental and pilot studies. The present study is carried out to monitor the movement of the foam front once injected into the porous medium. This study aims to investigate applications of resistivity waves to monitor foam propagation in a sandstone formation. In the present lab-scale experiments and simulations, resistivity measurements were carried out to monitor the progression of foam in a sand pack, and the relationships between foam injection time and resistivity, as well as brine saturation, were studied. The brine saturation from foam simulation using CMG STAR is exported to COMSOL and calculated true formation resistivity. A diagram was produced summarizing the progression of foam through the sand pack in the function of time, which enabled us to establish how foam progressed through a porous medium. A surfactant and brine mixture was injected into the sand pack, followed by nitrogen gas to generate the foam in situ. As foam progressed through the sand pack, resistance measurements were taken in three zones of the sand pack. The resistance was then converted into resistivity and finally into brine saturation. As foam travels through the sand pack, it is predicted to displace the brine initially in place. This gradually increases each zone's resistivity (decreases the brine saturation) by displacing the brine. Also, an increase in the surfactant concentration results in higher resistivity. Finally, a comparison of three different surfactant concentrations was evaluated in terms of resistivity results, water saturation, and foam propagation monitoring to obtain the optimum surfactant concentration involved in foam flooding.
Fulltext Foaming properties, wettability alteration and interfacial tension reduction by saponin extracted from soapnut (Sapindus Mukorossi) at room and reservoir conditions

Yekeen N, Malik AA, Idris AK, Reepei NI, Ganie K

J Pet Sci Eng, 2020 Dec;195:107591.
PMID: 32834477 DOI: 10.1016/j.petrol.2020.107591

In this study, a natural surfactant, saponin was isolated from soapnut (Sapindus Mukorossi). The extracted surfactant was characterized by Fourier-transform infrared spectroscopy (FTIR) analysis. The effectiveness of the isolated surfactant as EOR agent was evaluated from foam generation/stabilization properties, wettability alteration of the rock surfaces, as well as oil-water interfacial tension (IFT) reduction characteristics. The performance of the extracted saponin was compared with that of a commercial saponin and sodium dodecyl sulfate (SDS). The foaming properties of the saponin with carbon dioxide (CO2) was characterized using Teclis Foamscan instrument at room condition and 60 °C. The IFT and contact angles at room conditions and reservoir conditions were measured using KRŰSS Drop Shape Analyzer (DSA 25 and DSA 100) via pendant drop and sessile drop techniques respectively. The foamability of the saponin-stabilized foam was good at ambient condition and 60 °C. Moreover, the time taken for almost 100% liquid drainage was higher in saponin-stabilized foam than the SDS-stabilized foam. The optimum concentration for attaining maximum foam stability decreased from 0.4 wt% at room temperature to 0.1 wt% at 60 °C. Signifying that the quantity of the surfactant to be used in foam generation could reduce at high temperature. The isolated saponin exhibited relatively good interfacial activities individually and in synergistic interaction with silicon dioxide (SiO2) nanoparticles at reservoir conditions. Precisely, at 8 MPa and 80 °C, the crude-oil water IFT was reduced from 23.24 mN/m to 1.59 mN/m (about 93.2%) by 0.2 wt% saponin concentration. The IFT was further reduced to 0.87 mN/m (about 96.3%) by a mixed system of 0.5 wt% saponin and 0.05 wt% SiO2 nanoparticles concentration. Increasing IFT with increasing temperature were observed at very high temperature due to phase separation resulting from clouding phenomenon. However, the clouding temperature increased with 0.1 wt% saponin concentration, and in presence of SiO2 nanoparticles (0.05 wt% and 0.1 wt%). The study suggests that the extracted saponin could be considered as supplementary alternative to conventional EOR surfactants.