Surface modification of nanoparticles for enhanced applicability of nanofluids in harsh reservoir conditions: A comprehensive review for improved oil recovery.

Nanoparticles improve traditional Enhanced Oil Recovery (EOR) methods but face instability issues. Surface modification resolves these, making it vital to understand its impact on EOR effectiveness. This paper examines how surface-modified nanoparticles can increase oil recovery rates. We discuss post-synthesis modifications like chemical functionalization, surfactant and polymer coatings, surface etching, and oxidation, and during-synthesis modifications like core-shell formation, in-situ ligand exchange, and surface passivation. Oil displacement studies show surface-engineered nanoparticles outperform conventional EOR methods. Coatings or functionalizations alter nanoparticle size by 1-5 nm, ensuring colloidal stability for 7 to 30 days at 25 to 65 °C and 30,000 to 150,000 ppm NaCl. This stability ensures uniform distribution and enhanced penetration through low-permeability (1-10 md) rocks, improving oil recovery by 5 to 50 %. Enhanced recovery is achieved through 1-25 µm oil-in-water emulsions, increased viscosity by ≥30 %, wettability changes from 170° to <10°, and interfacial tension reductions of up to 95 %. Surface oxidation is suitable for carbon-based nanoparticles in high-permeability (≥500 md) reservoirs, leading to 80 % oil recovery in micromodel studies. Surface etching is efficient for all nanoparticle types, and combining it with chemical functionalization enhances resistance to harsh conditions (≥40,000 ppm salinity and ≥ 50 °C). Modifying nanoparticle surfaces with a silane coupling agent before using polymers and surfactants improves EOR parameters and reduces polymer thermal degradation (e.g., only 10 % viscosity decrease after 90 days). Economically, 500 ppm of nanoparticles requires 56.25 kg in a 112,500 m3 reservoir, averaging $200/kg, and 2000 ppm of surface modifiers require 4 kg at $3.39/kg. This results in 188,694.30 barrels, or $16,039,015.50 at $85 per barrel for a 20 % increase in oil recovery. The economic benefits justify the initial costs, highlighting the importance of cost-effective nanoparticles for EOR applications.

Maximizing oil recovery: Innovative chemical EOR solutions for residual oil mobilization in Kazakhstan's waterflooded sandstone oilfield.

The results of an experimental study to design a chemical flood scheme for a massive Kazakhstani oilfield with high water cut are presented in this paper. A meticulously formulated chemical flooding procedure entails injecting a blend comprising interfacial tension (IFT) reducing agents, alkaline/nanoparticles to control chemical adsorption, and polymer to facilitate mobility control. Overall, this well-conceived approach leads to a significant enhancement in the mobilization and production of residual oil. Experiments were conducted in Kazakhstan's Field A, one of the country's oldest oilfields with over 90% water cut and substantial remaining oil, to assess the efficiency of various hydrolyzed polyacrylamide (HPAM) derived polymers and surfactant solutions. Additionally, the effectiveness of alkaline and nanoparticles in minimizing chemical adsorption for the screened surfactant and polymer was investigated. These assessments were conducted under reservoir conditions, with a temperature of 63 °C, and using 13,000 ppm Caspian seawater as makeup brine. The performance assessment of the selected chemicals was carried out through a set of oil displacement tests on reservoir cores. Critical parameters, including chemical adsorption, interfacial tension, resistance factor, and oil recovery factor, were compared to determine the most effective chemical flooding approach for Field A. Both the surfactant-polymer (SP) and alkali-surfactant-polymer (ASP) approaches were more successful in recovering residual oil by efficiently generating and delivering microemulsion, producing more than 90% of the remaining oil after waterflooding. Due to the low increase in recovery compared to SP and the complexity of applying ASP at the field scale, SP was recommended for the pilot test studies. This investigation underscores that the choice of chemicals is contingent upon the interplay between the specific characteristics of the oil, the geological formation, the injection water, and the reservoir rock. Consequently, assessing all potential configurations on reservoir cores is imperative to identify the most optimal chemical combination. The practical challenges at the field scale should also be considered for the final decision. The results of this study contribute to the successful design and implementation of tailored chemical flooding to challenging oilfields with excessive water cut and high residual oil.

Enhanced oil recovery by using modified ZnO nanocomposites in sandstone oil reservoirs.

Recently, nanocomposites were employed to improve the extraction of oil in different reservoirs. Due to the unique characteristics of nanoparticles such as small size, efficient altering main mechanisms such as IFT, CA, and viscosity reduction, have received wide attention among researchers. This study investigated the application of a newly designed ZnO-cerium N-composite for EOR at reservoir conditions, and the performance was compared to the standalone ZnO nanoparticles. After performing the morphology of the N-composite, the effect of the N-composites on the wettability alteration, interfacial tension, viscosity, Zeta potential, pH, and density was studied at different N-composites concentrations at reservoir conditions. Based on the results of rock/fluid interactions at the static phase, an optimum concentration was chosen for performing dynamic core flooding experiments. At 100 ppm, the highest stability and the highest reduction in capillary force were observed. The presence of Ce in the structure of the N-composite changes the pore volume of ZnO-Ce compared to ZnO nanoparticles, which affects the surface charge. IFT (mN/m), CA (°), and zeta potential (mV) were (22.51, 40.83, and - 44.36), and (30.50, 50.21, and - 31.05) for ZnO-Ce and ZnO, respectively at 100 ppm. By application of the optimized nanofluid in an oil displacement study, RF in the presence of ZnO-Ce, and ZnO were 37.11% and 71.40%, respectively.

Modeling crude oil pyrolysis process using advanced white-box and black-box machine learning techniques.

Accurate prediction of fuel deposition during crude oil pyrolysis is pivotal for sustaining the combustion front and ensuring the effectiveness of in-situ combustion enhanced oil recovery (ISC EOR). Employing 2071 experimental TGA datasets from 13 diverse crude oil samples extracted from the literature, this study sought to precisely model crude oil pyrolysis. A suite of robust machine learning techniques, encompassing three black-box approaches (Categorical Gradient Boosting-CatBoost, Gaussian Process Regression-GPR, Extreme Gradient Boosting-XGBoost), and a white-box approach (Genetic Programming-GP), was employed to estimate crude oil residue at varying temperature intervals during TGA runs. Notably, the XGBoost model emerged as the most accurate, boasting a mean absolute percentage error (MAPE) of 0.7796% and a determination coefficient (R2) of 0.9999. Subsequently, the GPR, CatBoost, and GP models demonstrated commendable performance. The GP model, while displaying slightly higher error in comparison to the black-box models, yielded acceptable results and proved suitable for swift estimation of crude oil residue during pyrolysis. Furthermore, a sensitivity analysis was conducted to reveal the varying influence of input parameters on residual crude oil during pyrolysis. Among the inputs, temperature and asphaltenes were identified as the most influential factors in the crude oil pyrolysis process. Higher temperatures and oil °API gravity were associated with a negative impact, leading to a decrease in fuel deposition. On the other hand, increased values of asphaltenes, resins, and heating rates showed a positive impact, resulting in an increase in fuel deposition. These findings underscore the importance of precise modeling for fuel deposition during crude oil pyrolysis, offering insights that can significantly benefit ISC EOR practices.

Spontaneous Imbibition Oil Recovery by Natural Surfactant/Nanofluid: An Experimental and Theoretical Study.

Organic surfactants have been utilized with different nanoparticles in enhanced oil recovery (EOR) operations due to the synergic mechanisms of nanofluid stabilization, wettability alteration, and oil-water interfacial tension reduction. However, investment and environmental issues are the main concerns to make the operation more practical. The present study introduces a natural and cost-effective surfactant named Azarboo for modifying the surface traits of silica nanoparticles for more efficient EOR. Surface-modified nanoparticles were synthesized by conjugating negatively charged Azarboo surfactant on positively charged amino-treated silica nanoparticles. The effect of the hybrid application of the natural surfactant and amine-modified silica nanoparticles was investigated by analysis of wettability alteration. Amine-surfactant-functionalized silica nanoparticles were found to be more effective than typical nanoparticles. Amott cell experiments showed maximum imbibition oil recovery after nine days of treatment with amine-surfactant-modified nanoparticles and fifteen days of treatment with amine-modified nanoparticles. This finding confirmed the superior potential of amine-surfactant-modified silica nanoparticles compared to amine-modified silica nanoparticles. Modeling showed that amine surfactant-treated SiO2 could change wettability from strongly oil-wet to almost strongly water-wet. In the case of amine-treated silica nanoparticles, a strongly water-wet condition was not achieved. Oil displacement experiments confirmed the better performance of amine-surfactant-treated SiO2 nanoparticles compared to amine-treated SiO2 by improving oil recovery by 15%. Overall, a synergistic effect between Azarboo surfactant and amine-modified silica nanoparticles led to wettability alteration and higher oil recovery.

Investigation of Brine pH Effect on the Rheological and Viscoelastic Properties of HPAM Polymer for an Optimized Enhanced Oil Recovery Design.

A novel approach to improve viscous and viscoelastic properties by exploiting the pH and salinity sensitivity of HPAM polymer is proposed in this paper. Polymer flooding is a well-developed and effective enhanced oil recovery technique. The design of the makeup brine is one of the most critical phases of a polymer flood project, since the brine composition, salinity, and pH directly influence the polymer viscosity and viscoelasticity. However, the viscoelastic properties of hydrolyzed polyacrylamide polymers have not been given much consideration during the design phase of polymer flood projects. Our experimental study focuses on the optimization of the makeup water design for polymer flooding by evaluating the optimum solution salinity and pH for better stability and improved viscoelastic behavior of the polymer. Initially, the brine salinity and ionic composition is adjusted and then hydrolyzed polyacrylamide (HPAM) polymer solutions of varying pH are prepared using the adjusted brine. Rheological experiments are conducted over a temperature range of 25-80 °C and at different aging times. Polymer thermal degradation as a function of pH is assessed by examining the solutions at 80 °C for 1 week. Amplitude sweep and frequency sweep tests are performed to determine the viscoelastic properties such as storage modulus, loss modulus, and relaxation time. A 15-40% increase in the polymer solution viscosity and a 20 times increase in relaxation time is observed in the pH range of 8-10 in comparison to the neutral solution. This can be attributed to the low-salinity ion-adjusted environment of the makeup brine and further hydrolysis and increased repulsion of polymer chains in an alkaline environment. These results indicate that the viscoelastic properties of a polymer are tunable and a basic pH is favorable for better synergy between the brine and the polymer. Alkaline low-salinity polymer solutions have exhibited 60% higher thermal stability in comparison to acidic solutions and thus can be successfully applied in high-temperature reservoirs. The results of this study show that polymer solutions with an optimum pH in the basic range exhibit a higher viscoelastic character and an increased resistance toward thermal degradation. Hence, the polymer solution salinity, ionic composition, and pH should be adjusted to obtain maximum oil recovery by the polymer flooding method. Finally, this study shows that more effective polymer solutions can be prepared by adjusting the pH and designing a low-salinity water/polymer recipe to get the additional benefit of polymer viscoelasticity. The optimized low-salinity alkaline conditions can reduce the residual oil saturation by stronger viscous and viscoelastic forces developed by more viscous polymers. The findings of this study can be employed to design an optimum polymer recipe by tuning the brine pH and salinity for maximum incremental oil recovery, particularly in high-temperature and high-salinity formations.

Toward Reducing Surfactant Adsorption on Clay Minerals by Lignin for Enhanced Oil Recovery Application.

The significant loss of surfactants during reservoir flooding is a challenge in oil field operations. The presence of clay minerals affects the surfactant performance, resulting in surfactant losses. This is because the mineralogical composition of the reservoir results in unpredicted adsorption quantity. Therefore, this paper seeks to investigate Aerosol-OT's adsorption on different quartz/clay mineral compositions during the flow. Also, it investigates adsorption mitigation by preflushing with lignin. The dynamic experiments were conducted on sand packs composed of quartz-sand and up to a 7% clay mineral content. The results obtained from the surfactant losses were compared with/without lignin preflush at different pH values. The main observation was the direct relationship between increasing the composition of clay minerals and the surfactant pore volume required to overcome the adsorption. The highest adsorption calculated was 46 g/kg for 7% kaolinite. Moreover, lignin successfully reduced the adsorption of Aerosol-OT by 60%. Therefore, the results demonstrate that the effects of the clay mineral content on adsorption could be efficiently minimized using lignin at a high pH.