Search Results (450)

The solubility of CO₂ in brine systems is critical for both carbon storage and enhanced oil recovery (EOR) applications. In this study, Gaussian Process Regression (GPR) with eight different kernels was optimized using the Grey Wolf Optimizer (GWO) algorithm to model this important phase behavior. Among the tested kernels, the ARD Matern 3/2 and ARD Matern 5/2 kernels achieved the highest predictive accuracies, with R² values of 0.9961 and 0.9960, respectively, on the test data. This demonstrates superior performance in capturing CO₂ solubility trends. The GWO algorithm effectively tuned the hyperparameters for all kernel configurations, while the ARD capability successfully quantified the influence of key physicochemical parameters on CO₂ solubility. The outstanding performance of the ARD Matern 3/2 and ARD Matern 5/2 kernels suggests their particular suitability for modeling complex thermodynamic behaviors in brine systems. Furthermore, this study integrates fundamental thermodynamic principles into the modeling framework, ensuring all predictions adhere to physical laws while maintaining excellent accuracy (test R² > 0.98). These results highlight how machine learning can improve CO₂ injection processes, both for underground carbon storage and enhanced oil production. Full article

At present, various advanced technologies for field development based on gas-enhanced oil recovery (EOR) methods are widely applied worldwide. These include high-pressure gas injection (hydrocarbon gases, nitrogen, flue gases), water-alternating-gas (WAG) injection, and carbon dioxide (CO₂) flooding. This study presents the results of filtration experiments investigating the application of gas EOR methods using core samples from a heavy oil reservoir. The primary objective of these experiments was to determine the oil displacement factor and analyze changes in interfacial tension upon injection of different gas agents. The following gases were utilized for modeling gas EOR processes: nitrogen (N₂), carbon dioxide (CO₂), and hydrocarbon gases (methane, propane). The core samples used in the study were obtained from the East Moldabek heavy oil field in Kazakhstan. Based on the results of the filtration experiments, carbon dioxide (CO₂) injection was identified as the most effective gas EOR method in terms of increasing the oil displacement factor, achieving an incremental displacement factor of 5.06%. Other gas injection methods demonstrated lower efficiency. Full article

The stability of nitrogen gas foam hinders its applicability in petroleum applications. Fly ash nanoparticles and clay improve the N₂ foam stability, and flue gas foams provide a cost-effective solution for carbon capture, utilization, and storage (CCUS). This study examines the stability, volume, and bubble structure of foams formed using two anionic surfactants, sodium dodecyl sulfate (SDS) and sodium dodecylbenzene sulfonate (SDBS), along with the cationic surfactant cetyltrimethylammonium bromide (CTAB), selected for their comparable interfacial tension properties. Analysis of foam stability and volume and bubble structure was conducted under different CO₂/N₂ mixtures, with half-life and initial foam volume serving as the evaluation criteria. The impact of fly ash and clay on SDS-N₂ foam was also evaluated. The results showed that foams created with CTAB, SDBS, and SDS exhibit the greatest stability in pure nitrogen, attributed to low solubility in water and limited gas diffusion. SDS showed the highest foam strength attributable to its comparatively low surface tension. The addition of fly ash and clay significantly improved foam stability by migrating to the gas–liquid interface, creating a protective barrier that reduced drainage. Both nano fly ash and clay improved the half-life of nitrogen foam by 11.25 times and increased the foam volume, with optimal concentrations identified as 5.0 wt% for fly ash and 3.0 wt% for clay. This research emphasizes the importance of fly ash nanoparticles in stabilizing foams, therefore optimizing a foam system for enhanced oil recovery (EOR). Full article

Recovering oil by fracturing fluid imbibition has demonstrated significant potential for enhanced oil recovery (EOR) in tight oil reservoirs. White mineral oil (WMO), kerosene, or saturated alkanes with matched apparent viscosity have been widely used as “crude oil” to investigate imbibition mechanisms in light shale oil or tight oil. However, the representativeness of these simulated oils for low-maturity crude oils with higher viscosity and greater content of resins and asphaltenes requires further research. In this study, imbibition experiments were conducted and T₂ and T₁–T₂ nuclear magnetic resonance (NMR) spectra were adopted to investigate the oil recovery characteristics among resin–asphaltene-rich Jimusar shale oil and two WMOs. The overall imbibition recovery rates, pore scale recovery characteristics, mobility variations among oils with different occurrence states, as well as key factors influencing imbibition efficiency were analyzed. The results show the following: (1) WMO, kerosene, or alkanes with matched apparent viscosity may not comprehensively replicate the imbibition behavior of resin–asphaltene-rich crude oils. These simplified systems fail to capture the pore-scale occurrence characteristics of resins/asphaltenes, their influence on pore wettability alteration, and may consequently overestimate the intrinsic imbibition displacement efficiency in reservoir formations. (2) Surfactant optimization must holistically address the intrinsic coupling between interfacial tension reduction, wettability modification, and pore-scale crude oil mobilization mechanisms. The alteration of overall wettability exhibits higher priority over interfacial tension in governing displacement dynamics. (3) Imbibition displacement exhibits selective mobilization characteristics for oil phases in pores. Specifically, when the oil phase contains complex hydrocarbon components, lighter fractions in larger pores are preferentially mobilized; when the oil composition is homogeneous, oil in smaller pores is mobilized first. Full article

The diffusion coefficient (DC) of CO₂ in brine is a key parameter in geological carbon sequestration and CO₂-Enhanced Oil Recovery (EOR), as it governs mass transfer efficiency and storage capacity. This study employs three machine learning (ML) models—Random Forest (RF), Gradient Boost Regressor (GBR), and Extreme Gradient Boosting (XGBoost)—to predict DC based on pressure, temperature, and salinity. The dataset, comprising 176 data points, spans pressures from 0.10 to 30.00 MPa, temperatures from 286.15 to 398.00 K, salinities from 0.00 to 6.76 mol/L, and DC values from 0.13 to 4.50 × 10⁻⁹ m²/s. The data was split into 80% for training and 20% for testing to ensure reliable model evaluation. Model performance was assessed using R², RMSE, and MAE. The RF model demonstrated the best performance, with an R² of 0.95, an RMSE of 0.03, and an MAE of 0.11 on the test set, indicating high predictive accuracy and generalization capability. In comparison, GBR achieved an R² of 0.925, and XGBoost achieved an R² of 0.91 on the test set. Feature importance analysis consistently identified temperature as the most influential factor, followed by salinity and pressure. This study highlights the potential of ML models for predicting CO₂ diffusion in brine, providing a robust, data-driven framework for optimizing CO₂-EOR processes and carbon storage strategies. The findings underscore the critical role of temperature in diffusion behavior, offering valuable insights for future modeling and operational applications. Full article

This study presents a comprehensive evaluation of miscible gas injection (MGI) strategies for enhanced oil recovery (EOR) in high-salinity reservoirs, with a focus on the Raleigh Oil Field. Using a calibrated Equation of State (EOS) model in CMG WinProp™, eight gas injection scenarios were simulated to assess phase behavior, miscibility, and swelling factors. The results indicate that carbon dioxide (CO₂) and enriched separator gas offer the most technically and economically viable options, with CO₂ demonstrating superior swelling performance and lower miscibility pressure requirements. The findings underscore the potential of CO₂-EOR as a sustainable and effective recovery method in pressure-depleted, high-salinity environments. Full article

Vibration-stimulated waterflooding (VS-WF) is a promising enhanced oil recovery (EOR) method, especially for reservoirs with high-viscosity or emulsified oil. This study explores the effect of low-frequency vibration (2 Hz and 5 Hz) on oil mobilization under constant pressure and flow rate, using both crude and emulsified oil samples. Vibration significantly improves recovery by inducing stick-slip flow, lowering the threshold pressure, and enhancing oil phase permeability while suppressing the water phase flow. Crude oil recovery increased by up to 24% under optimal vibration conditions, while emulsified oil showed smaller gains due to higher viscosity. Intermittent vibration achieved similar recovery rates to continuous vibration, but with reduced energy use. Statistical analysis revealed a strong correlation between pressure fluctuations and oil production in vibration-assisted tests, but no such relationship in non-vibration cases. These results provide insight into the mechanisms behind vibration-enhanced recovery, supported by analysis of pressure and flow rate responses during waterflooding. Full article

Polymer flooding is a widely used enhanced oil recovery (EOR) method for improving energy efficiency and reducing the carbon footprint of oil production. Optimizing polymer concentration is critical for maximizing recovery while minimizing economic and environmental costs. Here, we present a systematic experimental study which shows that even very low concentrations of polymers yield relatively high recovery rates at adverse mobility ratios (230 cP oil). A series of core flood experiments were conducted on Bentheimer sandstone rock, with polymer concentrations ranging from 40 ppm (1.35 cP) to 600 ppm (10.0 cP). Beyond a mobility ratio threshold, increasing polymer concentration did not significantly enhance recovery. This plateau in performance was attributed to the persistence of viscous fingering and oil crossflow into pre-established water channels. The study suggests that low concentrations of polymer may mobilize oil at high mobility ratios by making use of the pre-established water channels as transport paths for the oil and that the rheology of the polymer enhances this effect. These findings enable reductions in the polymer concentration in fields with adverse mobility ratios, leading to substantial reductions in chemical usage, energy consumption, and environmental impact of the extraction process. Full article

The in situ emulsification synergistic self-profile control system has wide application prospects for efficient development on offshore oil reservoirs. During water flooding in Bohai heavy oil reservoirs, random emulsification occurs with superimposed Jamin effects. Effectively utilizing this phenomenon can enhance the efficient development of offshore oilfields. This study addresses the challenges hindering water flooding development in offshore oilfields by investigating the emulsification mechanism and key influencing factors based on oil–water emulsion characteristics, thereby proposing a novel in situ emulsification flooding method. Based on a fundamental analysis of oil–water properties, key factors affecting emulsion stability were examined. Core flooding experiments clarified the impact of spontaneous oil–water emulsification on water flooding recovery. Two-dimensional T1–T2 NMR spectroscopy was employed to detect pure fluid components, innovating the method for distinguishing oil–water distribution during flooding and revealing the characteristics of in situ emulsification interactions. The results indicate that emulsions formed between crude oil and formation water under varying rheometer rotational speeds (500–2500 r/min), water cuts (30–80%), and emulsification temperatures (40–85 °C) are all water-in-oil (W/O) type. Emulsion viscosity exhibits a positive correlation with shear rate, with droplet sizes primarily ranging between 2 and 7 μm and a viscosity amplification factor up to 25.8. Emulsion stability deteriorates with increasing water cut and temperature. Prolonged shearing initially increases viscosity until stabilization. In low-permeability cores, spontaneous oil–water emulsification occurs, yielding a recovery factor of only 30%. For medium- and high-permeability cores (water cuts of 80% and 50%, respectively), recovery factors increased by 9.7% and 12%. The in situ generation of micron-scale emulsions in porous media achieved a recovery factor of approximately 50%, demonstrating significantly enhanced oil recovery (EOR) potential. During emulsification flooding, the system emulsifies oil at pore walls, intensifying water–wall interactions and stripping wall-adhered oil, leading to increased T2 signal intensity and reduced relaxation time. Oil–wall interactions and collision frequencies are lower than those of water, which appears in high-relaxation regions (T1/T2 > 5). The two-dimensional NMR spectrum clearly distinguishes oil and water distributions. Full article

Enhanced oil recovery (EOR) via CO₂ flooding is a promising strategy for improving hydrocarbon recovery and carbon sequestration, yet the influence of pH on solid–liquid interfacial interactions in quartz-dominated reservoirs remains poorly understood. This study employs molecular dynamics (MD) simulations to investigate the pH-dependent adsorption behavior of crude oil components on quartz surfaces and its impact on CO₂ displacement mechanisms. Three quartz surface models with varying ionization degrees (0%, 9%, 18%, corresponding to pH 2–4, 5–7, and 7–9) were constructed to simulate different pH environments. The MD results reveal that aromatic hydrocarbons exhibit significantly stronger adsorption on quartz surfaces at high pH, with their maximum adsorption peak increasing from 398 kg/m³ (pH 2–4) to 778 kg/m³ (pH 7–9), while their alkane adsorption peaks decrease from 764 kg/m³ to 460 kg/m³. This pH-dependent behavior is attributed to enhanced cation–π interactions that are facilitated by Na⁺ ion aggregation on negatively charged quartz surfaces at high pH, which form stable tetrahedral configurations with aromatic molecules and surface oxygen ions. During CO₂ displacement, an adsorption–stripping–displacement mechanism was observed: CO₂ first forms an adsorption layer on the quartz surface, then penetrates the oil phase to induce the detachment of crude oil components, which are subsequently displaced by pressure. Although high pH enhances the Na⁺-mediated weakening of oil-surface interactions, which leads to a 37% higher diffusion coefficient (8.5 × 10⁻⁵ cm²/s vs. 6.2 × 10⁻⁵ cm²/s at low pH), the tighter packing of aromatic molecules at high pH slows down the displacement rate. This study provides molecular-level insights into pH-regulated adsorption and CO₂ displacement processes, highlighting the critical role of the surface charge and cation–π interactions in optimizing CO₂-EOR strategies for quartz-rich reservoirs. Full article

This study addresses the unclear mechanisms by which preferential flow channels (PFCs), formed during long-term waterflooding, affect nano-gel microsphere (NGM) flooding efficiency, utilizing CMG reservoir numerical simulation software. A dynamic evolution model of PFCs was established by coupling CROCKTAB (stress–porosity hysteresis) and CROCKTABW (water saturation-driven permeability evolution), and the deep flooding mechanism of NGMs (based on their gel properties such as swelling, elastic deformation, and adsorption, and characterized by a “plugging-migration-replugging” process) was integrated. The results demonstrate that neglecting PFCs overestimates recovery by 8.7%, while NGMs reduce permeability by 33% (from 12 to 8 mD) in high-conductivity zones via “bridge-plug-filter cake” structures, diverting flow to low-permeability layers (+33% permeability, from 4.5 to 6 mD). Field application in a Chang 6 tight reservoir (permeability variation coefficient 0.82) confirms a >10-year effective period with 0.84% incremental recovery (from 7.31% to 8.15%) and favorable economics (ROI ≈ 10:1), providing a theoretical and engineering framework for gel-based conformance control in analogous reservoirs. Full article

Acid gas injection (AGI), which primarily involves injecting hydrogen sulfide (H₂S) and carbon dioxide (CO₂), is recognized as a cost-efficient and environmentally sustainable method for controlling sour gas emissions in oil and gas operations. This review examines case studies of twelve AGI projects conducted in Canada, Oman, and Kazakhstan, focusing on reservoir selection, leakage potential assessment, and geological suitability evaluation. Globally, several million tonnes of acid gases have already been sequestered, with Canada being a key contributor. The study provides a critical analysis of geochemical modeling data, monitoring activities, and injection performance to assess long-term gas containment potential. It also explores AGI’s role in Enhanced Oil Recovery (EOR), noting that oil production can increase by up to 20% in carbonate rock formations. By integrating technical and regulatory insights, this review offers valuable guidance for implementing AGI in geologically similar regions worldwide. The findings presented here support global efforts to reduce CO₂ emissions, and provide practical direction for scaling-up acid gas storage in deep subsurface environments. Full article

Cyclic Solvent Injection (CSI), one of the most promising solvent-based enhanced oil recovery (EOR) methods, has attracted the oil industry’s interest due to its energy efficiency, produced oil quality, and environmental suitability. Previous studies revealed that foamy oil flow is considered as one of the main mechanisms of the CSI process. However, due to the presence of complex high-permeable channels known as wormholes in Post-Cold Heavy Oil Production with Sands (Post-CHOPS) reservoirs, understanding the effect of each operational parameter on the performance of the CSI process in these reservoirs requires a pore-scale investigation of different wormhole configurations. Therefore, in this project, a comprehensive microfluidic experimental investigation into the effect of symmetrical and asymmetrical wormholes during the CSI process has been conducted. A total of 11 tests were designed, considering four different microfluidic systems with various wormhole configurations. Various operational parameters, including solvent type, pressure depletion rate, and the number of cycles, were considered to assess their effects on foamy oil behavior in post-CHOPS reservoirs in the presence of wormholes. The finding revealed that the wormhole configuration plays a crucial role in controlling the oil production behavior. While the presence of the wormhole in a symmetrical design could positively improve oil production, it would restrict oil production in an asymmetrical design. To address this challenge, we used the solvent mixture containing 30% propane that outperformed CO₂, overcame the impact of the asymmetrical wormhole, and increased the total recovery factor by 14% under a 12 kPa/min pressure depletion rate compared to utilizing pure CO₂. Moreover, the results showed that applying a lower pressure depletion rate at 4 kPa/min could recover a slightly higher amount of oil, approximately 2%, during the first cycle compared to tests conducted under higher pressure depletion rates. However, in later cycles, a higher pressure depletion rate at 12 kPa/min significantly improved foamy oil flow quality and, subsequently, heavy oil recovery. The interesting finding, as observed, is the gap difference between the total recovery factor at the end of the cycle and the recovery factor after the first cycle, which increases noticeably with higher pressure depletion rate, increasing from 9.5% under 4 kPa/min to 16% under 12 kPa/min. Full article

In the development of high-temperature and high-salinity oil fields, biopolymer scleroglucan flooding technology faces significant challenges. Traditional scleroglucan products exhibit poor injectability and high extraction costs. This study investigated the application potential of the original fermentation broth of exopolysaccharides (EPS) produced by microorganisms in a simulated high-temperature and high-salinity oil reservoir environment. The polysaccharide was identified as scleroglucan through IR and NMR analysis. Its stability and rheological properties were comprehensively evaluated under extreme conditions, including temperatures up to 150 °C, pH levels ranging from 1 to 13, and salinities up to 22 × 10⁴ mg/L. The results demonstrated that EPS maintained excellent viscosity and stability, particularly at 76.6 °C and 22 × 10⁴ mg/L salinity, where its viscosity remained above 80% for 35 days. This highlights its significant viscoelasticity and stability in high-temperature and high-salinity oil reservoirs. Additionally, this study, for the first time, examined the rheological properties of the original fermentation broth of scleroglucan, specifically assessing its injectability and enhanced oil recovery (EOR) performance in a simulated Middle Eastern high-temperature, high-salinity, medium-low permeability reservoir environment. The findings revealed an effective EOR exceeding 15%, confirming the feasibility of using the original fermentation broth as a biopolymer for enhancing oil recovery in extreme reservoir conditions. Based on these experimental results, it is concluded that the original fermentation broth of Athelia rolfsii exhibits superior performance under high-temperature and high-salinity conditions in medium–low permeability reservoirs, offering a promising strategy for future biopolymer flooding in oil field development. Full article

The impact of water on CO₂ sequestration and enhanced oil recovery processes is significant. In this study, a CO₂–water-film–crude-oil–rock molecular system was established. Then, the influence of water-film thickness on the dissolution and dispersion of CO₂ and crude oil under different temperature and pressure scenarios was examined through molecular dynamics simulations. The results indicate that water films hinder CO₂ diffusion into the oil, reducing its ability to lower oil density. When the thickness of the water film increases from 0 nm to 3 nm, the oil density increases by 86.9%, and the average diffusion coefficient of oil decreases by 72.30%. Increasing the temperature enhances CO₂–oil interactions, promoting CO₂ and water diffusion into oil, thereby reducing oil density. Under conditions of a 2 nm water film and 10 MPa pressure, increasing the temperature from 100 °C to 300 °C results in a decrease of approximately 32.1% in the oil density. Pressure also promotes oil and water-film density reduction, but its effect is less significant compared to temperature. These results elucidate the function of the water film in CO₂-EOR processes and its impact on CO₂ dissolution and diffusion in water-bearing reservoirs. Full article