Wettability Alteration Research Articles

Chemical Enhanced Oil Recovery and Viscose Flooding into Sandstone Reservoirs Using a Natural Polymer Extracted from Sucrose‐Rich Waste by Bacterial Activity

In this research, it was attempted to describe in vitro the efficiency of a natural polymer synthesized from sugarcane waste by bacteria for application in enhanced crude oil recovery. Necessary experiments were carried out with the main targets of extraction and description of the polymer and its effectiveness in enhanced oil recovery. It is shown that in the polymer concentrations of 1, 2, 5, and 8 wt%, the viscosity is equal to 26.08, 76.51, 100.94, and 168.36 mPa s. A shear‐thinning flow behavior is observed at initial shear rates. The sandstone wettability alteration is observed through the contact angles at concentrations of 1, 2, 5, and 8 wt% that are 85.93°, 72.19°, 76.51°, and 71.09°, respectively. Based on salinity compatibility, the polymer work up to a salinity of 90 000 ppm and based on viscosity tests, up to a salinity of 120 000 ppm. Regarding the performance of the polymer solution against temperature, it shows an acceptable performance in increasing the viscosity at the highest temperature of 75 °C. The water cut reaches its minimum of 8%, and then increases. By injecting 3.3 Pore volum (PV), the oil recovery reaches 81.4%. In a polymeric slug injection program, the oil recovery factor reaches 74.8%.Similarly, the water cut starts to decrease after the injection of polymer, and finally, after the injection of 0.9 PV including 0.5 PV of the polymer solution and 0.4 PV of water, reaches its minimum during the experiment, i.e., 22%.

Steady-state relative permeability measurements in rough-walled fractures: The effects of wettability and aperture

Tight subsurface geosystems provide significant prospects for the recovery and storage of mass and energy. Because of the tightness of these systems, natural and engineered fractures are the main conveyance conduits transporting the fluids from the tight rock matrix to the wellbore or vice versa. During the fracturing process, most of the newly induced fractures are considered water-wet, however during injection/production, the wettability of the fractures gradually changes. These changes are mainly due to the interactions between the resident and injected fluids, or the exposure of the virgin fracture surfaces to the resident fluids during production. This alteration in wettability can affect the trapping and flow dynamics, e.g., relative permeability, of the fluids flowing in the fracture. Furthermore, fluid injection and production into and from these systems impact the fractures pore pressure and hence the effective stress they are exposed to, resulting in variations in the fracture aperture. In this study, we present a comprehensive macro-scale experimental investigation focusing on the impact of wettability and aperture on steady-state two-phase relative permeability in rough-walled fractures. Using the stead-state measurement technique, we meticulously characterized oil-brine relative permeabilities and residual trapping in water-wet, oil-wet, and mixed-wet rough-walled fractures induced in Eagle Ford shale rock samples. Additionally, we assessed the influence of fracture aperture size on these properties during both drainage and imbibition flow processes. Our results indicate significant phase interference in oil-brine flow in non-water-wet rough-walled fractures, which renders the commonly used x-curve and Corey models inadequate to represent the steady-state oil-brine relative permeabilities measured in our study, leading to substantial overestimations. Mixed-wet fractures exhibited reduced relative permeabilities compared to oil-wet fractures, which in turn demonstrated lower relative permeabilities than water-wet counterparts. The observed trends stem from evolving fluid configuration and transport dynamics within the fractures as surface wettability transitions. Furthermore, an increase in fracture aperture corresponded with an increase in relative permeability. This was attributed to a broader flow area, diminished capillarity, attenuated impact of fracture wall roughness and tortuosity effects, and a reduction in bypassing and trapping events, all synergistically contributing to the mitigation of phase interference. Similarly, an increase in fracture aperture led to a marked decrease in post-waterflooding endpoint oil saturation and post-oil flooding endpoint brine saturation. Finally, we provided generalized correlation models based on experimental results from fractures with varying conductivities and wettability, yielding a more accurate representation of fracture relative permeabilities compared to traditional models. The data and correlation models produced in this study improve our understanding and prediction of multiphase flow in subsurface fractures and offer insights into rapid production decline in unconventional shale reservoirs.

An efficient method for imbibition in asphaltene-adsorbed tight oil-wet reservoirs

Spontaneous imbibition (SI) has been proposed as a crucial approach to enhance oil recovery in unconventional reservoirs. Previous research suggests that wettability alteration rather than oil-water interfacial tension (IFT) reduction is the key mechanism for imbibition oil recovery enhancement. However, our experimental results indicate that for asphaltene-adsorbed oil-wet surfaces it's challenging to substantially modulate wettability. In such oil-wet pores, the negative capillary force cannot function as an imbibition driving force, and hence, the method of altering wettability and maintaining the oil-water IFT at relatively high values to enhance imbibition efficiency is insufficiently applicable. When the capillary cannot work, reducing the IFT to ultra-low levels to induce the transformation of the imbibition pattern may be more effective for imbibition efficiency enhancement. In this paper, low-field nuclear magnetic resonance (NMR) was employed to monitor the SI process. The results suggested that for the asphaltene-adsorbed oil-wet tight sandstone, the surfactants combined system with ultra-low oil-water IFT possessed the highest oil recovery, followed by the medium-IFT systems and high-IFT systems. The spontaneous formation of emulsion was observed when the IFT value was reduced to the ultra-low level. Oil droplets can pass through the small pores easily since the deformability of oil is greatly enhanced. The ultra-low IFT system transforms the imbibition pattern from capillary force-driven to gravity-driven, and exhibits the highest oil utilization rate in micropores, mesopores, and macropores among all imbibition agent systems, thereby having the highest total oil recovery. Consequently, the imbibition-enhancing potential of the ultra-low IFT system is considerable and deserves more attention, especially for the oil-wet pores that can hardly be altered to the water-wet state.

Sustainable potassium-doped graphene oxide from oak fruit agricultural waste for a synergistically improved nanofluid-surfactant slug for enhancing oil recovery

This study presents an eco-friendly solvothermal method for synthesizing potassium-doped graphene oxide (K-GO) from agricultural waste, specifically oak fruit. Various spectrographic analyses, including XRD, FTIR, Raman, and UV–Vis, confirmed the successful synthesis of graphene oxide. The synthesized K-GO was combined with different surfactants to create nanofluids to enhance oil recovery. Anionic sodium dodecyl sulfate (SDS) demonstrated the best performance among the surfactants tested. When 250 ppm of K-GO was added to a 2500 ppm SDS solution, the surface tension was reduced by over 10 %. The study of zeta potential experiments validated that the K-GO-SDS nanofluid is compatible with sandstone reservoirs. Furthermore, the interfacial tension between the K-GO-SDS nanofluid and crude oil decreased by approximately 40 %. Batch adsorption studies showed that the combination of SDS and K-GO significantly reduced surfactant loss to reservoir surfaces by up to 32 %. Additionally, incorporating K-GO resulted in a notable improvement in wettability alteration, with contact angle measurements showing an improvement of over 20°. The sustainable synthesis of potassium-doped graphene oxide (K-GO) facilitates synergistic interactions with sodium dodecyl sulfate (SDS), thereby optimizing the formulation of nanofluids for enhanced oil recovery applications. This combination demonstrates superior efficacy in accessing trapped oil compared to using surfactants alone, highlighting the significant potential of K-GO-SDS nanofluids in advancing oil recovery techniques.

Rapid Joule heating-induced welding of silicon and graphene for enhanced lithium-ion battery anodes

In the pursuit of enhanced energy storage solutions, the application of silicon-based anode materials faces significant hurdles, primarily stemming from the rapid capacity degradation during battery cycles. This study introduces a novel and efficient method for fabricating Si/graphene composites (F-Si@rGO), enhancing the performance and longevity of silicon-based anodes. Utilizing ultra-high-speed thermal treatment, this technique controls the thermal interaction between carbon and silicon phases, leading to the formation of silicon carbide “riveting points” that firmly anchor silicon nanoparticles within the graphene matrix. This novel method effectively minimizes the problems of phase segregation, which are caused by varying degrees of wettability alteration in the two phases during conventional heat treatments, and guarantees a robust integration of graphene and silicon. This integration results in homogeneous charging and outstanding structural stability of the composites, over extended cycles of use. The resulting Si/graphene composites exhibit exceptional electrochemical performance, achieving a high initial capacity of 1141.3 mAh g−1 at 1C and maintaining a capacity of 894.95 mAh g−1 after 1000 cycles with minimal degradation (0.0216 % per cycle). This synthesis method, notable for its speed and scalability, offers a potential advancement in battery material technology, suggesting a path towards more resilient and efficient energy storage solutions.

Surface charge change in carbonates during low-salinity imbibition

Optimizing the injection water salinity could present a cost-effective strategy for improving oil recovery. Although the literature generally acknowledges that low-salinity improves oil recovery in laboratory-scale experiments, the physical mechanisms behind it are controversial. While most experimental low-salinity studies focus on brine composition, this study investigated the influence of carbonate rock material on surface charge change, wettability alteration, and spontaneous imbibition behavior. Zeta potential measurements showed that each tested carbonate rock material exhibits characteristic surface charge responses when exposed to Formation-water, Seawater, and Diluted-seawater. Moreover, the surface charge change sensitivity to calcium, magnesium, and sulfate ions varied for the tested carbonate materials. Spontaneous imbibition tests led to high oil recovery and, thus, wettability alteration towards water-wet conditions if the carbonate-imbibing brine system’s surface charge decreased compared to the initial zeta potential of the carbonate Formation-water system. In the numerical part of the presented study, we find that it is essential to account for the location of the shear plane and thus distinguish between the numerically computed surface charge and experimentally determined zeta potential. The resulting model numerically reproduced the experimentally measured calcium, magnesium, and sulfate ion impacts on zeta potential. The spontaneous imbibition tests were history-matched by linking surface charge change to capillary pressure alteration. As the numerical simulation of the laboratory-scale spontaneous imbibition tests is governed by molecular diffusion (with a time scale of weeks), we conclude that molecular diffusion-driven field scale wettability alteration requires several hundred years.

Enhancing Injectivity in Lithuanian Hydrocarbon Reservoirs through Wettability-Altering Surfactant Injection

Improved and efficient recovery methods are investigated as possible candidates to arrest the production decline and to improve the injection capacity in hydrocarbon fields in Lithuania. The data show that the Cambrian reservoirs in Lithuania are mixed to oil-wet in nature, which results in poor water-flooding efficiency. Wettability alteration could help in improved water injection and, at the same time, it could help recover additional oil from the residual oil saturation zone of the reservoir. In this paper, a screening exercise is conducted to help alter reservoir wettability, improve water injection efficiency, and to improve oil recovery. Analytical and machine-learning supported methods are used for screening. Based on the screening results, dilute surfactant-based injection techniques are suggested as a potential method to improve injectivity and, thereby, recovery from the field. An initial experimental analysis targets the wettability of the rock from the field, followed by testing for wettability-altering surfactants. Based on the findings of the screening study and experimental analysis, it is recommended that we initiate a core flooding experimental program to investigate wettability changes and enhance injection and recovery from the field.

More Biosurfactants and Fewer Synthetic Surfactants to Improve Alkali-Surfactant-Polymer Flooding: Feasibility Study and Large-Scale Field Application

Summary Alkali-surfactant-polymer (ASP) flooding has achieved highly enhanced oil recovery (EOR) in the Daqing Oil Field; however, there are concerns about synthetic surfactants owing to their high cost and difficulty in biodegradation. Cheap biosurfactants conform to human concepts of green circular economy; however, known biosurfactants, as well as their mixtures with alkali, cannot reduce water/oil interfacial tension (IFT) to ultralow values below 0.01 mN/m, which is necessary for ASP flooding to effectively mobilize residual oil. Therefore, we investigate the feasibility of partially replacing synthetic surfactants with biosurfactants rather than completely replacing them to improve ASP flooding. First, through a series of IFT tests, a blend of rhamnolipids (RLs) and alkylbenzene sulfonate (ABS) in a 1:1 mass ratio is determined to be the optimal mixed surfactant and labeled RL/ABS-opt. Second, the interfacial activities, phase behaviors, and wettability alteration capabilities of ASP solutions with RL/ABS-opt are studied. Then, 1.0 wt% NaOH and 0.2 wt% RL/ABS-opt are determined to construct a new ASP system. Subsequently, the waterflooded cores are displaced using the new and the classical ASP systems. Based on the promising experimental results, the new ASP system floods a test block of 56 wells for 3 years. The EOR and surfactant costs are calculated to determine the technical and economic effects. Finally, the concentrations of surfactants before and after activated sludge treatment (AST) are tested by spectrophotometry to verify the biodegradability of RLs better than that of ABS. The laboratory and field results indicate that more biosurfactants and fewer synthetic surfactants could improve ASP flooding to be more environmentally friendly and cost-effective with a higher EOR.

Experimental Evaluation of CO2-Soluble Nonionic Surfactants for Wettability Alteration to Intermediate CO2-Oil Wet during Immiscible Gas Injection

Summary The change in wettability of limestone reservoirs from oil-wet toward gas-wet can enhance crude oil production during immiscible CO2 injection. Therefore, in this research, we investigated the impact of wettability alteration to CO2-wet on oil recovery factor via dissolution of fluorine-free, CO2-philic, nonionic surfactants such as C4(PO)6 and C41H83O19 in CO2. Based on the cloudpoint measurements, the dissolution pressures of nonionic surfactants in supercritical CO2 ranged between 2,100 psi and 2,700 psi (below the reservoir pressure, i.e., 3,000 psi) at reservoir temperature, 65°C; these pressures are commensurate with CO2-enhanced oil recovery (EOR) pressures. Also, the C4(PO)6 and C41H83O19 can reduce the CO2-oil interfacial tension (IFT). Moreover, the CO2/C4(PO)6 and C41H83O19 solutions can change the limestone wettability from strongly oil-wet (Θ ~ 20o) to intermediate CO2/oil-wet (Θ = 95o and 110o) at reservoir conditions. The relative permeability curves also confirmed it by changing the curvature to the left and decreasing the residual oil saturation in both cases of CO2/C4(PO)6 and C41H83O19 solutions. The 20.8% and 13.1% additional oil recoveries were achieved during the 30,000 ppm CO2/C4(PO)6 and C41H83O19 solution scenarios, respectively, relative to the pure CO2 injection scenario. These nonionic surfactants are not able to make CO2-in-oil foam; therefore, wettability alteration and perhaps IFT reduction are the dominant mechanisms of EOR induced by the dissolution of nonionic surfactants in CO2, instead of CO2 mobility control. Consequently, the dissolution of fluorine-free, oxygenated, CO2-philic, nonionic surfactants (such as C4(PO)6 and C41H83O19) in CO2 at 30,000 ppm concentration can be a well-qualified candidate for altering the limestone wettability to intermediate CO2-oil-wet during the immiscible CO2 injection.

Experimental Investigation of the Impact of CO2 Injection Strategies on Rock Wettability Alteration for CCS Applications

Carbon capture and storage (CCS) has been recognized as a pivotal technology for mitigating climate change by reducing CO2 emissions. Storing CO2 in deep saline aquifers requires preserving the water-wet nature of the formation throughout the storage period, which is crucial for maintaining rock integrity and storage efficiency. However, the wettability of formations can change upon exposure to supercritical CO2 (scCO2), potentially compromising storage efficiency. Despite extensive studies on various factors influencing wettability alteration, a significant research gap remains in understanding the effects of different CO2 injection strategies on wettability in deep saline formations (DSFs). This study addresses this gap by investigating how three distinct CO2 injection strategies—continuous scCO2 injection (CCI), water alternating with scCO2 injection (WAG), and simultaneous water and scCO2 injection (SAI)—affect the wettability of gray Berea sandstone and Indiana limestone, both selected for their homogeneous properties relevant to CCS. Using a standardized sessile drop contact angle method before and after CO2 injection, along with core flooding to model the injection process at an injection pressure of 1500 psi and temperature of 100 °F with a confining pressure of 2500 psi, the results indicate a shift in wettability towards more CO2-wet conditions for both rock types under all strategies with changes in CA of 61.6–83.4° and 77.6–87.9° and 81.5–124.2° and 94.6–128.0° for sandstone and limestone, respectively. However, the degree of change varies depending on the injection strategy: sandstone exhibits a pronounced response to the CCI strategy, with up to a 77% increase in contact angle (CA), particularly after extended exposure. At the same time, WAG shows the least change, suggesting that water introduction slows surface modification. For limestone, the changes in CA ranged from 9% to 49% across strategies, with WAG and SAI being more effective in altering its wettability. This study underscores the importance of selecting suitable CO2 injection strategies based on rock type and wettability characteristics to maximize carbon storage efficiency. The findings offer valuable insights into the complex interactions of fluid–rock systems and a guide for enhancing the design and implementation of CCS technologies in various geological settings.

Synergistic collaborations between surfactant and polymer for in-situ emulsification and mobility control to enhance heavy oil recovery

Surfactant-polymer (SP) combined systems is an effective nonthermal method to enhance the heavy oil recovery, through in-situ emulsification and mobility control mechanisms. In this study, a novel SP system was developed using 0.2 wt% anionic surfactant (alkyl naphthol polyoxyethylene ether sulfonate, ANES) and 0.1 wt% polymer (partially hydrolyzed polyacrylamide, HPAM). The SP system had viscosity reduction rate of ∼ 98 %, viscosity ratio of oil to displaced water (μo/μd) of ∼ 3.95 and IFT of ∼ 0.29 mN/m, beneficial for decreasing the mobility ratio of water to heavy oil. Then, the applied performances including emulsion morphologies and stability, wettability alteration ability were systematically characterized. The results showed that the freshly O/W emulsions formed by SP system displayed uniform droplet size distribution, as well as high stability with tight interfacial film. In addition, the SP system exhibited excellent wettability alteration property with low contact angle of 18.3°. The synergistic collaboration mechanisms of surfactant and polymer include heavy oil–water interfacial tension reduction, in-situ emulsification, oil-viscosity reduction and water-viscosity increase. Finally, the static oil washing and dynamic sand-pack flooding experiments showed that the SP system exhibited high oil washing efficiency (62.89 %) and enhanced oil recovery efficiency (56.9 %) with improving the mobility controllability after the primary water-flooding process. This study indicated that the synergistic collaborations between surfactant and polymer had great potential to enhance the heavy oil recovery.

Effects of nano-smart water on enhanced oil recovery in carbonate reservoirs: Interfacial tension reduction and wettability alteration

Several studies have revealed that nanofluid and smart water flooding are cost-effective methods, considering the effect of nanoparticles and potential determining ions (PDIs) for enhanced oil recovery in carbonated reservoirs. This study presents the performance of nano-smart water synthesized with surface-modified SiO2 nanoparticles dispersed in PDI-controlled seawater (SW), ensuring dispersion stability in high-temperature and high-salinity reservoirs. The interfacial tension (IFT) and contact angle of the oil/nano-smart water/carbonate rock system were measured using kerosene as an oil phase. At this time, nanoparticle concentrations ranged from 0.5 to 3 wt% and PDI concentrations ranged from 1,000 to 5,000 ppm, such as KCl, MgCl2, MgSO4, and K2SO4. In addition, the IFT and contact angle of SW, low salinity water (LSW), and nanofluid were measured for comparison. It was observed that at nanoparticle concentrations higher than 1 wt%, the IFT values of nano-smart water remained constant or decreased slightly to below 31.91 mN/m compared with nanofluids at 32.18 mN/m, regardless of PDI type and concentration. This indicates that using nano-smart water instead of LSW and SW is expected to reduce the IFT in the oil/water system. The contact angle measurements revealed that the wettability index is 2.57–5.07 times higher in nano-smart water than in nanofluids. This implies that wettability alteration is accelerated by the synergistic effect of PDIs and nanoparticles. Specifically, PDI control with MgSO4 or K2SO4 is highly effective in changing the contact angle of carbonate from strongly oil-wet to strongly water-wet due to the ion exchange reaction of SO42- in oil/water/carbonate rock system. The nano-smart water used in this study is expected to be utilized as an injection fluid under harsh conditions for enhanced oil recovery.

Interfacial tension and wettability alteration during hydrogen and carbon dioxide storage in depleted gas reservoirs

The storage of CO2 and hydrogen within depleted gas and oil reservoirs holds immense potential for mitigating greenhouse gas emissions and advancing renewable energy initiatives. However, achieving effective storage necessitates a thorough comprehension of the dynamic interplay between interfacial tension and wettability alteration under varying conditions. This comprehensive review investigates the multifaceted influence of several critical parameters on the alterations of IFT and wettability during the injection and storage of CO2 and hydrogen. Through a meticulous analysis of pressure, temperature, treatment duration, pH levels, the presence of nanoparticles, organic acids, anionic surfactants, and rock characteristics, this review elucidates the intricate mechanisms governing the changes in IFT and wettability within reservoir environments. By synthesizing recent experimental and theoretical advancements, this review aims to provide a holistic understanding of the processes underlying IFT and wettability alteration, thereby facilitating the optimization of storage efficiency and the long-term viability of depleted reservoirs as carbon capture and storage or hydrogen storage solutions. The insights gleaned from this analysis offer invaluable guidance for researchers, engineers, and policymakers engaged in harnessing the potential of depleted reservoirs for sustainable energy solutions and environmental conservation. This synthesis of knowledge serves as a foundational resource for future research endeavors aimed at enhancing the efficacy and reliability of CO2 and hydrogen storage in depleted reservoirs.

Microbial impact on basalt‐water‐hydrogen system: Insights into wettability, capillary pressure, and interfacial tension for subsurface hydrogen storage

AbstractHydrogen (H2) fuel is assessed to be a major component of sustainable energy systems in the net‐zero world. However, hydrogen storage is challenging and requires safe and environmentally friendly solutions like H2 geo‐sequestration. This study evaluates the effects of sulphate‐reducing bacteria (SRB) on H2 geological storage potential in the basalt rock. Fourier‐transform infrared spectroscopy (FTIR) findings show the presence of significant components, that is, O‐Si‐O and organic functional groups, that is, aromatics, amine salts, alkane, and cyclohexane in the basalt rock immersed in the nutrient solution without SRB. However, we found that C‐H stretching modes of organics with peaks at 1,465 cm−1 were observed. Consequently, amine salt (N‐H) (850–750 cm−1), solvent impurities (C‐H), and alkane spectrums are components of nutrient solutions and can be results of metabolic microbial activity that can influence on the surface of the basalt rock. Hence, these changes indicate the presence of microbial activity which might affect the surface chemistry of the rock leading to wettability alteration. We observed that the contact angle (θ) of brine‐H2 on the rock surface slightly changed from 500 to 4,000 psi pressure after the effect of bacteria at 50 °C. The wettability changed the surface of the rock from strong water‐wet to weak or intermediate water‐wet condition (i.e., θ < 75°) at 4,000 psi and temperatures 25 and 50 °C after the bacteria effect. The affiliation of brine water reduces on the rock surface with increasing temperatures and pressures, even without microbial influence. Additionally, we investigated interfacial tension and capillary pressure on SRB bacteria treated basalt which is not yet reported in the published work. Interfacial tension (IFT) and Pc of H2 were reduced by 19% and 65%, respectively at 50 °C and 4,000 psi after the bacteria effect. Hence, the above findings could help to answer the key factors of the reservoir rock including wettability, capillary pressure, and interfacial tension to plan a field‐scale H2 geo‐sequestration strategy under the influence of biotic life. © 2024 Society of Chemical Industry and John Wiley & Sons, Ltd.

Development of New Polyimide/Spirulina Hybrid Materials: Preparation and Characterization

This study presents the synthesis and characterization of polyimide (PI-2) films incorporated with spirulina powder for potential biomedical applications. The synthesis of PI-2 was achieved through a two-step polycondensation reaction using N-methyl-2-pyrrolidone (NMP) as the solvent. The incorporation of spirulina was systematically varied to investigate its effects on the structural and surface properties of the hybrid materials. Scanning electron microscopy revealed a tightly bound interface between spirulina and the PI-2 matrix, indicating effective dispersion and strong interfacial adhesion. Profilometry and Raman spectroscopy confirmed the homogeneous integration of spirulina within the polymer matrix, with resulting variations in surface roughness and chemistry. Contact angle measurements demonstrated altered wettability characteristics, with increased hydrophilicity observed with spirulina incorporation. Furthermore, blood component interaction studies indicated the variations in adhesion behavior observed for red blood cells, platelets, and plasma proteins. Water uptake studies revealed enhanced absorption capacity in PI-2 films loaded with spirulina, highlighting their potential suitability for applications requiring controlled hydration. Overall, this comprehensive characterization elucidates the potential of PI-2/spirulina hybrid materials for diverse biomedical applications, offering tunable properties that can be tailored to specific requirements.

Experimental investigation and machine learning modeling of diethylenetriaminepentaacetic acid agents in sandstone rock wettability alteration: Implications for enhanced oil recovery processes

Chelating agents have garnered increasing attention due to their unique capabilities in addressing challenges associated with chemical enhanced oil recovery (CEOR) materials. This research investigates the transformative potential of diethylenetriaminepentaacetic acid (DTPA) chelating agent in altering sandstone rock wettability. Wettability and zeta potential measurements were used to assess the impact of crucial factors including DTPA concentration, salinity, and potential determining ions (PDIs) on contact angle and rock surface charges. The findings revealed that there is an optimal level for DTPA concentration and salinity that can shift rock wettability from an oil-wet to strongly water-wet state. Moreover, while PDIs in their natural concentrations had no significant impact on DTPA performance, a threefold increase in their concentration was found to adversely affect DTPA efficacy. After conducting rock wettability tests, two advanced machine learning (ML) techniques, namely Random Forest (RF) and Boosted Regression Tree (BRT), were employed to assess rock/oil contact angle based on the aforementioned factors. Data were collected from 240 experimental datasets of contact angles. The findings indicated that both models performed well, but BRT exhibited exceptional performance. Sensitivity analysis, conducted using the Jackknife method, revealed the order of importance for parameters affecting wettability as follows: PDIs > salinity > time > DTPA concentration.

RETRACTED ARTICLE: Microwave-ultrasonic assisted extraction of lignin to synthesize new nano micellar organometallic surfactants for refining oily wastewater

In this work, a beneficial approach for efficient depolymerization of lignin and controllable product distribution is provided. Lignin, an abundant aromatic biopolymer, has the potential to produce various biofuels and chemical adsorption agents and is expected to benefit the future circular economy. Microwave-ultrasonic (MW/US) assisted efficient depolymerization of lignin affords some aromatic materials used in manufacturing the starting material to be investigated. Some nano organometallic surfactants (NOMS) based on Ni2+, Cu2+, Co2+, Fe3+, and Mn2+ besides 2-hydroxynaphth-sulphanilamide are synthesized to enhance oil recovery (EOR). In this work, the assessment of the NOMS’s efficiency was improving the heavy oil recovery via the study of the dynamic interfacial tension (IFT), contact angle, and chemical flooding scenarios. The NOMS-Ni2+ exhibited the maximum reduction of viscosity and yield values. Dropping the viscosity to 819.9, 659.89, and 499.9 Pa s from blank crude oil viscosity of 9978.8, 8005.6, and 5008.6 Pa s respectively at temperatures of 40, 60, and 80 °C was investigated. The reduction of τB values was obtained also by OMS-Ni2+. The minimum IFT was recorded against the Ni2+ derivatives (0.1 × 10–1 mN m−1). The complete wettability alteration was achieved with the NOMS-Ni2+ surfactant (ɵ ≅6.01).\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$$\\cong 6.01).$$\\end{document} The flooding test has been steered in 3 sets using the sand-packed model as a porous media at surfactant concentrations (1, 1.5, 2 and 2.5%) at 50 °C and 499 psi as injection pressure. The best value (ORs) formed for NOMS-Ni2+ were 62, 81, 85.2, and 89% respectively as compared with other NOMS-M2+ at the same concentrations. The mechanism of alternating wettability was described in the text. The rheology of the used heavy crude oil was investigated under temperatures of 40, 60, and 80 °C.Graphical

Channel width-dependent viscosity and slip length in nanoslits and effect of surface wettability

The channel width-dependent behaviors of viscosity (μ) and slip length (ls) in nanoslits are investigated using many-body dissipative particle dynamics simulation in both Poiseuille and Couette flow systems. In both systems, the viscosity and slip length increase as the channel width (w) grows in smaller channels, while they reach bulk values in larger channels. Moreover, as the surface wettability decreases, the slip length is found to increase, while the viscosity remains the same. The channel width-dependent behavior in nanoslits can be explained by the unique structure of the confined fluid. As the channel width narrows, the uniform density profile in the central region diminishes, and an oscillation pattern appears throughout the system. The change in the microstructure with the channel width alters friction between layers of fluid in laminar flow and fluid-solid friction, leading to a w-dependent μ and ls. Nonetheless, the alteration of surface wettability influences only fluid–solid interactions but not the friction between layers of fluid.

Experimental and Molecular Dynamics Simulation to Investigate Oil Adsorption and Detachment from Sandstone/Quartz Surface by Low-Salinity Surfactant Brines.

In this study, we explore the impact of monovalent (NaCl) and divalent (CaCl2) brines, coupled with sodium dodecyl sulfate (SDS) surfactant at varying low concentrations, on the detachment and displacement of oil from sandstone rock surfaces. Employing the sessile drop method and molecular dynamics simulations, we scrutinize the behavior of the brine solutions. Our findings reveal that both low salinity and low-salinity surfactant solutions induce a gradual shift in rock wettability toward a more water-wet state. This wettability transformation is not instantaneous but evolves over time, as observed through meticulous molecular motion analyses. Through contact angle measurements and molecular dynamics simulations, we delve into the molecular motion at subpore and micropore scales on sandstone/quartz surfaces. The adsorption of surface-active agents from the oil to the oil-brine interface results in a reduced interfacial tension, significantly contributing to oil displacement. Notably, low salinity concentrations ranging from 1000 to 10,000 ppm exhibit the lowest contact angles within 30 min across all solutions. However, higher concentrations deviate from this declining trend, especially with divalent ions like Ca2+, which bridge polar molecules onto the rock surface, resulting in an increased oil-wetting state. This research unveils the intricate molecular motions involved in employing low-salinity surfactant solutions for oil detachment from surfaces. Furthermore, it provides valuable insights into the underlying forces driving oil detachment and wettability alteration.

Heavy oil removal using modified polyacrylamide and SDS

Composite systems of surfactants have been extensively applied in the recovery and removal of heavy oil. In this work, the characteristics and mechanisms of heavy oil removal in surfactant-polymer systems (SP) were investigated. The effects of the main factors, including the oil-to-water ratio, washing temperature, washing time, and shear rate, on the oil washing rate (OWR) were analyzed through the response surface methodology (RSM). The results demonstrated the ratio of oil to water had the most significant impact on the OWR compared to other factors. Based on the experimental data and the analysis of variances, a high-precision model was established, and the predicted OWR value was 42.0 % at the formation temperature (50 °C). In addition, the adsorption process of the SP molecules onto quartz silica was well represented by the pseudo-second-order kinetic model and the Freundlich isotherm. This indicates that the SP system has the characteristics of multilayer rebinding and heterogeneous adsorption. On the other hand, the adsorption thermodynamics identified that the adsorption was endothermic and unspontaneous. The dynamic experiments showed that the removal of heavy oil was clean and efficient without secondary adsorption and contamination on the solid surface. Furthermore, the oil removal of the SP system was determined by the mechanism of wettability alteration, utilizing the adsorption of SP molecules onto the solid surface to displace the adsorbed heavy oil molecules. The findings enhance the understanding of heavy oil removal by the surfactant-polymer composite system, which is frequently overlooked in conventional methodologies.