Abstract This study presents a comprehensive evaluation of two newly designed oleic acid–derived surfactants (SMP-02 and SMP-04) in combination with natural polymer (guar gum) for Enhanced Oil Recovery (EOR) applications. The surfactants possess very good thermodynamic and surface characteristics with Gibbs free energy of adsorption (ΔGads) higher than that of micellization (ΔGmic), favoring interfacial adsorption over bulk micellization. Evaluation of key EOR parameters, including interfacial tension, emulsification, and wettability alteration, revealed that the surfactants reduced crude oil–water IFT to 0.36 mN/m for SMP-02 and 0.11 mN/m for SMP-04 at their respective critical micelle concentrations and an optimal salinity of 1 wt %. Both surfactants formed stable emulsions at the optimal salinity and effectively converted oil-wet rock surfaces to water-wet. Microscopic and DLS analyses of SMP-04 emulsions revealed good colloidal stability and a reduced particle size, thereby enhancing pore-scale mobility. Rheological studies of emulsions revealed pseudoplastic shear-thinning behavior that increased reservoir injectivity. Lower adsorption of both surfactants onto the rock surface proved their economic viability for EOR application. The SMP-04-guar gum formulation delivered superior tertiary recovery, achieving 29.39% OOIP with a residual oil saturation of 14.35% in core-flooding tests, confirming that optimized surfactant–polymer systems markedly enhance sweep efficiency and oil recovery in heterogeneous sandstone reservoirs.

This investigation evaluates the suitability of treated lake water (LW) for injection and as a diluent for produced water (PW) in low-salinity enhanced oil recovery (EOR), revealing through comprehensive characterization that excessive TSS, turbidity, poor filterability, elevated dissolved oxygen, scaling and corrosion tendencies, and microbial activity in both waters induce adverse physico-chemical interactions in the crude oil–water system that could impair oil recovery efficiency. A treatment protocol was formulated, incorporating coagulation–flocculation with 80 ppm polyaluminum chloride (PAC) and 2 ppm polyacrylamide (PAM), two-stage filtration (20–25 μm followed by 5 μm), mechanical deaeration with sodium bisulfite scavenging, and PBTC-based corrosion/scale control. Microbial control was implemented through initial chlorination and alternating slug doses of THPS and glutaraldehyde. Filtration and core flood experiments validated superior injectivity, with permeability retention exceeding 88% when using 5 μm and 2.5 μm filters. Dilution experiments involving produced water and lake water mixtures demonstrated that an increased proportion of lake water corresponded with a more negative zeta potential. This observation suggests an expansion of the electrical double layer and enhanced colloidal stability, both of which are associated with decreased salinity. The PW (20%) + LW (80%) mixture exhibited the lowest interfacial tension (14.9 mN/m) and contact angle (61.6°), thereby indicating more water-wet conditions that are conducive to oil mobilization. Consequently, the optimum composition yielded an additional recovery of 6.3% OOIP in tertiary mode during coreflooding experiments. The findings indicate that appropriately treated lake water can fulfil injection quality standards and, when utilised to dilute produced water, improve wettability alteration and displacement efficiency, thereby underscoring its considerable potential for sustainable low-salinity EOR applications.

The present study focuses on the development of acid-based chemical slugs for enhanced oil recovery (EOR). These slugs interact with both the crude oil and the reservoir rock, resulting in favourable alterations to the reservoir properties. One of the key mechanisms involves a significant reduction in interfacial tension (IFT), which enhances oil mobilization and contributes to effective well stimulation. Notably, the interfacial tension between crude oil and the acidic solution decreases by more than 80% compared to that with water. This substantial IFT reduction is attributed to the acid's influence on the dissociation and behaviour of indigenous surfactants present in the crude oil. Additionally, acid-based slugs improve reservoir permeability by dissolving clays and minerals within the rock matrix. The slugs also alter the wettability of oil-wet rocks to water-wet, with a more pronounced effect observed in carbonate rocks compared to sandstone due to mineral dissolution. Moreover, the formation of stable emulsions with higher viscosity than crude oil mitigates viscous fingering, reduces the mobility ratio, and enhances sweep efficiency. To address corrosion risks associated with acidic solutions, acid inhibitor is employed. Core flooding experiments demonstrate an approximate 12% increase in oil recovery over conventional water flooding, underscoring the potential of acid-based slugs to improve displacement efficiency in EOR applications.

Developing advanced nanofluids with tailored rheological properties is crucial for optimizing enhanced oil recovery (EOR) techniques. This study investigates graphene oxide (GO) nanosheet-assisted polymeric nanofluids and evaluates their potential for EOR applications. GO nanosheets were synthesized using the modified Hummers method and characterized using FTIR, UV spectroscopy, XRD, and Raman spectroscopy analysis. Polymeric nanofluids were formulated by dispersing GO nanosheets into hydroxyethyl cellulose (HEC) solutions, and their rheological properties were evaluated at varying shear rates and temperatures to simulate reservoir conditions. The results showed that the addition of a low concentration of GO (50 ppm) significantly enhanced the rheological properties of HEC polymer solutions due to synergistic interactions between GO nanosheets and polymer chains that form three-dimensional networks via hydrogen bonding. These intermolecular interactions were further validated through FTIR and DSC analyses. Additionally, qualitative changes in the sandstone rock's wettability were evaluated using spectroscopic techniques, revealing a shift toward more water-wet conditions. Core flooding experiments demonstrated superior performance of the polymeric nanofluid, achieving a tertiary oil recovery of 24.76% OOIP compared to 17.93% for polymer flooding. Furthermore, preliminary industrial feasibility and economic analyses suggest the scalability and cost-effectiveness of the developed system. Overall, this study highlights the potential of GO-HEC nanofluids as efficient and viable EOR agents.

Mitigating excessive CO2 emissions is a significant challenge for avoiding global climate change, thereby directing researchers towards effective methods for CO2 utilisation and sequestration. The present study aims to investigate the efficacy of CO2 foams stabilised with surfactants, polymers, and nanoparticles for enhanced oil recovery (EOR) and CO2 storage in depleted reservoirs or saline aquifers. The combined use of surfactants, namely alpha-olefin sulfonate (AOS, anionic) and cocamidopropyl betaine (CAPB, zwitterionic), polymers (polyethene glycol, carboxymethyl cellulose, and partially hydrolysed polyacrylamide), and nanoparticles (Al2O3 and ZnO) shows pronounced synergistic effects on CO2 foam properties and performance. The half-life of CO2 foam stabilised by an AOS + CAPB blend increased from 460 s to 522 s with the addition of Al2O3 nanoparticles, which adsorb at the gas-liquid interface, forming a rigid barrier that prevents coalescence and film thinning. Polymer further enhances the stability by slowing down water drainage in the foam lamellae through the formation of interfacial and bulk surfactant-polymer complexes. The results highlight strong synergistic enhancements in AOS-CAPB-Al2O3-PHPA composite formulations, resulting in remarkably stable foams with smaller, uniform bubbles, a significantly reduced coarsening rate, and superior interfacial viscoelastic properties. Conversely, the presence of oil above 5% by volume led to rapid foam destabilisation due to its antifoaming properties, resulting in foam rupture and rapid bubble coalescence. The outcome of the studies will be useful in designing and implementing CO2-EOR and CO2 sequestration projects in the field.

The adsorption of surfactants onto reservoir rock surfaces significantly affects the efficiency of enhanced oil recovery (EOR), as high retention reduces the effective concentration of surfactants during flooding. In the present study, the adsorption behaviour of synthesized Gemini surfactants (GS) on sandstone and carbonate rocks was evaluated using UV-vis spectroscopy under static and dynamic conditions. Equilibrium isotherm and kinetic models were applied to interpret the adsorption trends and assess the governing adsorption pathways. FESEM-EDX was employed to assess surface morphology and elemental mapping, while zeta potential measurements indicated charge modification. The static adsorption results showed that surfactant retention systematically decreased with increasing spacer length, indicating reduced packing efficiency for longer spacer Gemini structures. Dynamic adsorption shows very low surfactant retention, with maximum adsorption capacities of 0.013 mg g-1 for sandstone and 0.0087 mg g-1 for carbonate using Hexamine GS. Excessive surfactant adsorption during flooding causes chemical loss, but controlled surface adsorption is necessary for wettability alteration, as it facilitates a shift from oil-wet to water-wet conditions, thereby enhancing oil recovery. In this study, wettability alteration was investigated by measuring contact angles. Hexamine GS reduced contact angles by approximately 81% within a few minutes, accompanied by an efficient transition from an oil-wet to a water-wet state. Overall, the findings provide model-supported insight into spacer-length-dependent adsorption behaviour and highlight the potential of these bio-derived Gemini surfactants to minimise surfactant loss and improve wettability control in chemical EOR applications.

Background The application of surfactants in enhanced oil recovery (EOR) has gained significant attention due to their ability to reduce interfacial tension (IFT), alter rock wettability, and improve oil displacement efficiency. However, conventional surfactants often suffer from limited stability under harsh reservoir conditions, such as high salinity and elevated temperatures. To address this, the present study focuses on the development and evaluation of environmentally friendly Gemini surfactants synthesized from Brassica Juncea (mustard oil), tailored for use in high-temperature (120 degrees C) and high-salinity (20 wt% brine) reservoir environments. Methods Gemini surfactants with varying spacer lengths were synthesized and systematically evaluated for key EOR-relevant properties. Laboratory tests included determination of critical micelle concentration (CMC), interfacial tension (IFT) measurements under reservoir conditions, thermal and ionic stability tests, and wettability alteration using contact angle measurements on sandstone and carbonate rock samples. Surface modification was further examined through Atomic Force Microscopy (AFM). Emulsion stability, static adsorption, and oil displacement efficiency were also analyzed. Core flooding experiments were conducted using the hexamine-based Gemini surfactant to assess actual EOR performance in both sandstone and carbonate cores. Significant Findings The synthesized Gemini surfactants exhibited excellent surface activity, significantly reducing IFT to the order of 10(-)(3) mN/m and retaining stability after 5 days at 120 degrees C in 20 wt% brine. Wettability tests showed rapid alteration from oil-wet to water-wet states, with contact angles decreasing from similar to 130 degrees to similar to 10 degrees within 1000 s. AFM analysis confirmed changes in surface roughness post-treatment. Adsorption values were low (0.07-0.23 mg/g for sandstone and 0.06-0.13 mg/g for carbonate), ensuring effective surfactant utilization within the porous medium. The emulsification capability contributed to enhanced mobilization of trapped oil. Core flooding experiments demonstrated substantial incremental oil recovery, achieving 29.89 % and 30.32 % of the original oil in place (OOIP) in sandstone and carbonate cores, respectively, confirming the potential of these bio-derived Gemini surfactants for EOR under extreme reservoir conditions.

Global climate change, driven by rising CO2 emissions, is a critical environmental concern. As a mitigation measure and to counteract its effects, CO2 foam injection has emerged as a promising method for enhanced oil recovery (EOR) and storage in depleted oil reservoirs or saline aquifers. The present study focuses on the foamability and characterization of CO2 foam, as well as the effects of salinity, oil components, pressure, and porous media on its stability. An amphoteric surfactant, cocamidopropyl hydroxysultaine (CAHS), and a cationic surfactant, cetyltrimethylammonium bromide (CTAB), were used as foam stabilizers. The 25:75 v/v CTAB (1500 ppm):CAHS (500 ppm) blend at a total concentration of 750 ppm exhibits strong synergy with CO2, markedly reducing interfacial tension while significantly enhancing both foamability and stability compared to individual surfactants at equivalent total loading. Further, the half-life time (t 1/2) of the CO2 foam first increases with salinity due to the salt-out effect of CO2 solubility in water, but reaches a maximum at 1 wt % (2-fold increase in t 1/2 vs salt-free) salinity because of optimum IFT (22.1 mN/m), and then further decreases as salt ions reduce electrostatic repulsion between surfactant head groups. It is observed that the presence of oil destabilizes the foam as it disrupts the thin liquid films and interfaces that support foam, leading to bubble coalescence. An increase in pressure compresses CO2 gas, causing lamella thinning, reduced coalescence, and Ostwald ripening, while strengthening the surfactant films, resulting in higher stability of the CO2 foam. The rheological studies of CO2 foam stabilized by the designed surfactant blend show enhanced apparent viscosity with shear-thinning behavior, demonstrating its potential to improve the sweep efficiency and storage performance. Considering the injection of the CO2 foam into the porous media for its application either in EOR or CO2 storage, visualizations in glass bead packs revealed prolonged foam lifetime via capillary lamella pinning, reduced drainage, and gas diffusion, while separate coreflood experiments confirmed superior in situ stability and mobility control for the CAHS+CTAB blend, ideal for EOR/CO2 storage.

Low salinity water flooding has established itself as potential candidate for improved oil recovery in carbonate reservoirs without any extra investment in the surface production facilities. Thus, establishing itself as a cost-effective technique. Impact of potential determining ions (PDIs) has been studied in detail by various authors for enhance oil recovery. Proper tuning of potential determining ions (PDIs) can significantly improve the oil recovery. Out of which SO42- ions plays an important role in oil recovery. However, literature also shows that sometimes SO42- ions have detrimental effects on oil recovery and search is going on to identify different ions having potential to enhance the recovery form the reservoirs. In this study, a comprehensive investigation has been performed to study the effect of PO43- ions on the oil recovery at different concentrations and was compared to SO42- ions. This study provides an in-depth knowledge of PO43- ion role and its mechanism on oil recovery. A series of experiments were conducted to thoroughly examine the fluid/fluid and rock/fluid interactions using methods such as interfacial tension, interfacial rheology, zeta potential, and contact angle studies. At last, core flooding was performed to quantify the oil recovery potential of low salinity optimized PO43- brine as compared to SO42- brines and results are explained elaborately correlating the physico-chemical properties of the designed injection water and mechanisms responsible for improved oil recovery were proposed. Overall PO43- ions optimum tuned brines showed the highest incremental recovery of 28 % over plain sea water injection and almost a 7 % of incremental recovery from low salinity optimized SO42- brines. Calcite dissolution, increased interfacial elasticity, ionic interaction and in-situ surfactant generation due to high pH, all jointly led to the wettability alteration of rock surfaces. Result of this study also shows that type of ions present in the injected brines significantly influences the oil recovery due to low salinity water flooding.

Nanofluids have shown significant potential for enhanced oil recovery (EOR) through mechanisms such as wettability alteration, interfacial tension (IFT) reduction, and viscosity modification under dynamic shear conditions. This study characterizes and evaluates a nanofluid system comprising alumina (Al2O3) nanoparticles, sodium dodecyl sulfate (SDS) surfactant, and polyethylene glycol (PEG 1500) polymer for EOR applications. Structural analysis of Al2O3 nanoparticles using X-ray diffraction (XRD) and scanning electron microscopy (SEM) revealed spherical α-Al2O3 aggregates with a crystalline diameter of 20.28 nm. The dispersion of nanoparticles within the base fluid was confirmed by UV–Vis spectroscopy and dynamic light scattering (DLS), while thermogravimetric analysis (TGA) demonstrated thermal stability up to high temperatures in the presence of PEG 1500. Pendant drop tensiometry indicated a significant reduction in oil-aqueous IFT, with the nanofluid achieving values as low as 4 mN/m. Further IFT reduction was observed with the addition of PEG 1500 to the SDS-nanoparticle system, although excessive polymer concentration caused chain entanglements, leading to a slight increase in IFT. Sessile drop analyses on oil-saturated sandstone demonstrated dynamic contact angle reductions from 120° to approximately 40° over time, promoting a water-wet surface favorable for oil displacement. Rheological evaluations showed pseudoplastic behavior (flow index n < 1) under shear conditions typical of reservoirs, with viscosity values in the range of 2–13 cP. Core-flooding investigations revealed a marked enhanced in the tertiary oil recovery of surfactant-based nanofluids by nearly 8–10 % in the presence of Al2O3 nanoparticle / PE 1500 polymer. This ensures effective oil displacement at low shear rates and favorable injectivity at higher shear rates. This study highlights the efficacy of Al2O3 nanoparticles combined with SDS and low-molecular-weight PEG in optimizing injection fluid compositions. By enhancing fluid-rock interactions and improving oil recovery mechanisms, this work contributes to advancing nanotechnology applications in petroleum reservoirs.

This study explores the synergistic effects of Tween 80 surfactant combined with monoethanolamine (MEA) and sodium carbonate (Na2CO3) alkalis to reduce interfacial tension, alter wettability, and enhance emulsification for improved enhanced oil recovery under optimal salinity conditions. Experimental results reveal that MEA and Na2CO3 comparably improve the interfacial tension (IFT) reduction and wettability alteration capabilities of surfactant solutions. However, MEA demonstrates a superior performance in stabilizing oil-water emulsions with smaller droplet sizes and lower corrosion potential. The IFT of crude oil in water was significantly reduced from 29.8 to 0.222 mN/m using Tween 80 at CMC, and further decreased to 0.0075 mN/m with the addition of 0.75 wt % MEA at an optimal salinity of 1.5 wt % NaCl. This pronounced reduction confirms the synergistic effect between the surfactant and organic alkali, providing a favorable balance of hydrophilic and lipophilic interactions at the oil-water interface. Microscopic analysis revealed that the MEA-surfactant system produced emulsion droplets with an average radius of 5.8 mu m, significantly smaller than the 10.4 mu m droplets observed with Na2CO3, contributing to greater emulsion stability. Additionally, MEA was found to exhibit 57.5% lower corrosiveness on mild steel compared with Na2CO3, highlighting its operational advantages for long-term field applications. Core flooding experiments revealed that a surfactant-alkali slug containing MEA and Tween 80 at optimal salinity achieved a 32.37% OOIP recovery, surpassing the 29.40% OOIP recovery from a Na2CO3 and surfactant slug. The higher viscosity of MEA-based surfactant-stabilized emulsions improves both macroscopic sweep efficiency and displacement efficiency, leading to improved oil recovery. The combination of Tween 80 and MEA optimizes enhanced oil recovery (EOR) efficiency, reduces equipment corrosion, and enhances sustainability, offering a cost-effective, ecofriendly solution for long-term oil recovery operations.

This study explores the application of Alkaline-Surfactant-Polymer (ASP) flooding in “Reservoir-S,” a relatively new and small reservoir located in the Upper Assam Basin. With five years of production history and an estimated Stock Tank Oil Initially in Place (STOIIP) of 1.946 MMsm³, “Reservoir-S” exhibits a recovery factor of approximately 8.2

The paper focusses on the synthesis and characterization of choline chloride: urea (molar ratio 1:2) DES. The influence of the varying DES concentration on the surface and interfacial behavior of low-concentration commercial surfactant (cetyl trimethyl ammonium bromide) was examined. The incorporation of DES into the surfactant solution resulted in an augmentation of electrophoretic mobility and absolute zeta potential values, indicative of enhanced surfactant adsorption at the interface. Sessile drop measurements demonstrated the capacity of binary mixture to modify the wettability of sandstone from intermediate-wet state to water-wet condition. In summary, physicochemical evaluation revealed the capability of DES to augment the self-assembly and wetting behavior of surfactant at low concentrations (below critical micelle concentration). The observed phenomenon in these solvents primarily finds utility in nanoscience, drug delivery systems, colloids, catalysis, and applications in many other fields.

Carbon Capture and Storage (CCS) is essential for reducing CO2 emissions by capturing atmospheric or industrial emissions and storing them underground. Saline aquifers are ideal storage options due to their abundance and geological suitability. When CO2 is injected into these aquifers in supercritical state it attains gas-like mobility and liquid-like density that helps it move efficiently through the porous rock. A combination of structural alongside residual, solubility and mineral trapping mechanisms enables CO2 to stay contained underground for long periods while preventing its release into the atmosphere. The evaluation of CCS effectiveness and safety in India depends upon thorough knowledge of CO2 behaviour within saline aquifers. The Upper Assam and Jaisalmer Basins were analysed by studying injection rate, duration and pressure evolution while assessing CO2 dissolution and the influence of temperature, capillary pressure, pH and brine salinity on convection, mineralisation and halite precipitation. A field-scale mechanistic model was developed using actual mineralogical and reservoir data from the Upper Assam Basin. CO2 was injected for 10 years, and the system was simulated for 100 years to assess long-term storage behaviour. Simulation results showed lower injection rates, simultaneous water injection and reduced salinity conditions result in enhanced CO2 dissolution and stable plume migration along with improved storage efficiency. Capillary pressure and high vertical permeability enhance trapping mechanisms, while high salinity and impurities can reduce storage potential. Heterogeneous models provide a more realistic representation of CO2 movement and storage performance. These findings support the feasibility and strategic planning of CCS in Indian subcontinent.

This paper presents a novel concept of using ester as a hydrophobic phase for the preparation of environmentally friendly and biodegradable nanoemulsions. This study comprehensively evaluates the efficacy of formulated environmentally friendly nanoemulsions designed for enhanced oil recovery. The formulations involve nonionic surfactants, namely Tween 40 and Tween 80, coupled with a biodegradable oleic phase (methyl ester) derived from edible oil. Nanoemulsions were meticulously prepared through a combination of low- and high-energy methods, and their stability was rigorously examined on macroscopic and mesoscopic scales at varied temperatures. The results indicate that the formulated nanoemulsions exhibit high kinetic stability with a zeta potential of around -33 mV and droplet sizes ranging between 59 and 150 nm. Interfacial tension (IFT) measurements demonstrated a significant decrease of IFT with increasing surfactant concentration (17 and 1.97 mN/m at 303 K for Tween 40 and Tween 80, respectively). Additionally, a phase behavior study established the critical parameters for optimal salinity, determining concentrations of 0.5 wt % for Tween 40-based formulations and 2 wt % for Tween 80-based formulations. Nanoemulsions showed remarkable results in enhancing oil recovery by transforming the wettability of sandstone rocks from oil-wet to water-wet. Further, the emulsions exhibited good miscibility with heavy crude oil and significantly reduced its viscosity, which improved the mobility of the oil. Injection of one pore volume of nanoemulsion slug, followed by a chase water flooding, exhibited a commendable 24.29% enhanced oil recovery over conventional water flooding.

Microemulsions encompass a viable injection fluid candidate in enhanced oil recovery (EOR) due to their exceptional ability to extract residual oil from natural oil reservoirs via several mechanistic approaches. However, challenges exist in the field during the interface-rheology relationship, fluid handling, and limitations in terms of microemulsion composition. In the present paper, the favorability of a novel, cost-effective microemulsion stabilized by an olefin sulfonate surfactant (ENORDET) and/or silica nanoparticles has been investigated intricately for application in EOR. The critical micelle concentration of the surfactant was identified by surface tensiometry using the du Nouy ring technique. Microemulsions with suitable ENORDET concentration(s) were prepared via a high-energy technique and characterized by turbidity analysis. Droplet distribution/stability was analyzed by dynamic light scattering and zeta potential studies. The microemulsion initially exhibited Winsor I behavior, which transitioned to the Winsor III phase and then to Winsor II (with gradually increasing salt concentration). Pendant drop analyses revealed a significantly low interfacial tension at the oil-microemulsion interface in comparison to water (as injection fluid). Sessile drop analyses predicted the alteration of oil-saturated rock to a strongly water-wet state with an elapse of time. Though oil displacement experiments revealed favorable recovery factors for both surfactant and surfactant-nanoparticle microemulsions, the presence of nanoparticles exhibited enhanced flooding performance in the sandstone (core) model. Core-flood studies showed similar to 20% and similar to 29% recovery of original oil in place (OOIP) for ENORDET microemulsion and {ENORDET + SiO2} microemulsion respectively, after secondary water flooding. The novelty of the research lies in the development of a microemulsion system stabilized by a novel olefin sulfonate surfactant with unique molecular properties and cost-effective silica nanoparticles for a sustainable EOR implementation. In summary, the research includes extensive laboratory testing and mechanistic analyses, which are strong evidence of the formulation's effectiveness and practical applicability in EOR.

The decline in the exploration of new oil sites necessitates the development of efficient strategies to maximize recovery from existing reservoirs. This study employs a molecular dynamics (MD) approach to investigate oil detachment from silica surfaces of varying hydrophobicity using a combination of bis-cationic gemini surfactants (GS) and functionalized silica nanoparticles (SNPs). Density profiles and radial distribution function (rdf) plots revealed a multilayered oil adsorption model. A reduction in oil-silica interaction energy was observed with an increase in surface hydrophobicity, highlighting the importance of polar interactions. Standard waterflooding studies, involving oil detachment solely with water, were conducted to assess baseline recovery efficiency. All the GS-SNP combinations outperformed standard waterflooding methods. SNPs significantly mitigated GS adsorption on reservoir beds, as evidenced by center-of-mass measurements. However, the effectiveness of the added injectants (GS-SNP) went downhill with increasing surface hydrophobicity, further validating the existence of a potential barrier for oil detachment, as known previously. Finally, supervised machine learning (ML) models were generated to predict the GS-SNP combination for a given silica surface, with MD generated descriptors. In most cases, boosting models, viz., XGBoost and AdaBoost yielded the best correlation with the observed data. However, for the complex oil model, ridge regression and support vector regression (SVR) outperformed other ML models in SNP prediction, pointing to the existence of a simpler correlation between the descriptors and the output variable. With these findings, the study attempts to streamline the data-driven design of chemical injectants for enhanced oil recovery purposes.

Accurate determination of the minimum miscibility pressure (MMP) is critical for the design and optimization of CO2-enhanced oil recovery processes, which also play a pivotal role in large-scale CO2 capture and utilization strategies. Conventional experimental techniques, such as slim-tube tests and vanishing interfacial tension (VIT) measurements, provide reliable MMP estimates but are often constrained by high cost, long duration, and operational complexity. To address these limitations, numerous empirical correlations have been proposed to predict MMP from crude oil properties and reservoir conditions, although their predictive accuracy remains highly dependent on compositional and thermal effects. In this study, eight widely cited empirical correlations were systematically evaluated under varying crude oil compositions and temperature regimes and benchmarked against 27 experimental MMP values obtained via the VIT method. A series of laboratory experiments was conducted to systematically examine the effects of crude oil composition and reservoir temperature on MMP using the VIT technique, followed by a detailed comparison with empirical correlations to identify models most sensitive to compositional and thermal variations. In addition, VIT-derived MMP values were cross-validated against slim-tube experiments and mixing-cell simulations. The results indicate that VIT consistently underestimates slim-tube MMP by an average absolute deviation of similar to 4%, a discrepancy attributable to the differing miscibility criteria inherent to the two methods. Overall, the study demonstrates the effectiveness of empirical correlations in reproducing VIT-derived MMP values and highlights the VIT method as a rapid and robust experimental framework for reliable MMP estimation.

This study investigates the synergistic effect of an anionic surfactant, nanoparticles, and polymer on enhancing foam properties for enhanced oil recovery (EOR). We screened various nanoparticles and found that silica, CaCO3, and boron nitride exhibit synergistic interactions with the surfactant alpha-olefin sulfonate (AOS). Among them, CaCO3 showed the highest foam stabilization at an optimal concentration of 500 ppm. The addition of nanoparticles increased electrostatic repulsion and altered ionic strength, reducing surface tension and leading to smaller, more stable foam bubbles. The nanoparticles formed networks within the foam lamellae, slowing liquid drainage and preventing bubble coalescence, particularly in the presence of oil. Incorporating the polymer polyacrylamide (PHPA) further enhanced foam stability and apparent viscosity, resulting in the most stable and oil-tolerant foam. The combined AOS, PHPA, and nanoparticle formulation achieved up to 27% incremental oil recovery over secondary methods, highlighting significant synergistic effects. This formulation effectively addresses the limitations of traditional surfactant-stabilized foams, offering a promising solution for EOR applications by improving foam stability and oil recovery efficiency.