Search Results (182)

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

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

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

To address the challenges of low displacement efficiency and gas channeling in the Lukqin thick oil reservoir, characterized by high viscosity (286 mPa·s) and strong heterogeneity (permeability contrast 5–10), this study systematically investigated water flooding and foam flooding mechanisms using a large-scale 2D sandpack model (5 m × 1 m × 0.04 m). Experimental results indicate that water flooding achieves only 30% oil recovery due to a mobility ratio imbalance (M = 128) and preferential channeling. In contrast, foam flooding enhances recovery by 15–20% (final recovery: 45%) through synergistic mechanisms of dynamic high-permeability channel plugging and mobility ratio optimization. By innovatively integrating electrical resistivity tomography with HSV color mapping, this work achieves the first visualization of foam migration pathways in meter-scale heterogeneous reservoirs at a spatial resolution of ≤0.5 cm, reducing monitoring costs by approximately 30% compared to conventional CT techniques. Key controlling factors for gas channeling (injection rate, foam quality, permeability contrast) are identified, and a nonlinear predictive model for plugging strength ((S = 0.70C^0.6 k_r^−0.28) (R² = 0.91)) is established. A composite optimization strategy—combining high-concentration slugs (0.7% AOS), salt-resistant polymer-enhanced foaming, and multi-round profile control—achieves a 67% reduction in gas channeling. This study elucidates the dynamic plugging mechanisms of foam flooding in heterogeneous thick oil reservoirs through large-scale physical simulations and data fusion, offering direct technical guidance for optimizing foam flooding operations in the Lukqin Oilfield and analogous reservoirs. Full article

Currently, the development of oil reservoirs with high water cut faces numerous challenges, including poor economic efficiency, difficulties in residual oil recovery, and a lack of effective development technologies. In light of these issues, this paper conducts research on gas drive development during the high water cut stage in middle–high permeability reservoirs and introduces an innovative technical approach for air thermal miscible flooding. In this study, the Enhanced Oil Recovery (EOR) mechanism and the dynamic characteristics of thermal miscible flooding were investigated through laboratory experiments and numerical simulations. The N₂ and CO₂ flooding experiments indicate that gas channeling is likely to occur when miscible flooding cannot be achieved, due to the smaller gas–water mobility ratio compared to the gas–oil mobility ratio during the high water cut stage. Consequently, the enhanced recovery efficiency of N₂ and CO₂ flooding is limited. The experiment on air thermal miscible flooding demonstrates that under conditions of high water content, this method can form a stable high-temperature thermal oxidation front. The high temperature, generated by the thermal oxidation front, promotes the miscibility of flue gas and crude oil, effectively inhibiting gas flow, preventing gas channeling, and significantly enhancing oil recovery. Numerical simulations indicate that the production stage of air hot miscible flooding in reservoirs with middle–high permeability and high water cut can be divided into three phases: pressurization and drainage response, high efficiency and stable production with a low air–oil ratio, and low efficiency production with a high air–oil ratio. These phases can enable efficient development during the high water cut stage in medium to high permeability reservoirs, with the theoretical EOR range expected to exceed 30%. Full article

CO₂ flooding technology has been established as a key technique that is both economically viable and environmentally sustainable, achieving enhanced oil recovery (EOR) while advancing CCUS objectives. This study addresses the challenge of optimizing CO₂ flooding well patterns in tight oil reservoirs through a geological–engineering integrated approach. A semi-analytical model incorporating startup pressure gradients and miscible/immiscible two-phase flow was developed to dynamically adjust injection intensity. An effective driving coefficient model considering reservoir heterogeneity and fracture orientation was proposed to determine well pattern boundaries. Field data from Blocks A and B were used to validate the models, with the results indicating optimal injection intensities of 0.39 t/d/m and 0.63 t/d/m, respectively. Numerical simulations confirmed that inverted five-spot patterns with well spacings of 240 m (Block A) and 260 m (Block B) achieved the highest incremental oil production (3621.6 t/well and 4213.1 t/well) while reducing the gas channeling risk by 35–47%. The proposed methodology provides a robust framework for enhancing recovery efficiency in low-permeability reservoirs under varying geological conditions. Full article

The thermal development in heavy oil reservoirs with edge and bottom water is poor, while gas huff-n-puff development shows a high recovery and strong adaptability. The formation of foamy oil during gas huff-n-puff is one of the reasons for the high recovery. In order to determine the factors affecting the foamy oil flow during gas huff-n-puff, experiments using a one-dimensional sandpack were conducted. The influences of drawdown pressure and cycle number were analyzed. The formation conditions of foamy oil were preliminarily clarified, and the enhanced oil recovery (EOR) mechanism of foamy oil was revealed. The experimental results show that the drawdown pressure and cycle number are two important factors affecting the formation of foamy oil. Foamy oil flow is prone to forming under a moderate drawdown pressure of 0.5–0.75 MPa, and being too small or too large is unfavorable. Foamy oil is more likely to form in the first two cycles, and it becomes increasingly challenging with the increase in the cycle number. These two factors reflect two necessary conditions for the formation of foamy oil during gas huff-n-puff: one is allowing the oil and gas to flow adequately to provide the shear and mixing for the generation of micro-bubbles, and the other is that the oil content should not be too small to avoid the inability to disperse and stabilize bubbles. The formation of foamy oil, on the one hand, increases the volume of the oil phase, and on the other hand, it reduces the mobility of the gas phase and slows down the pressure decline rate in the core, thereby enhancing the driving force for oil displacement. So, under the influence of the foamy oil, the gas production volume in a cycle declined by about 26%, and the average oil recovery increased by 4.5–6.9%. Full article

Steam-assisted gravity drainage (SAGD) is a widely used thermal enhanced oil recovery (EOR) technique in North America, particularly in high-permeability oil sand reservoirs. While effective, its economic viability has declined due to low oil prices and high greenhouse gas (GHG) emissions from the steam generation. To improve cost-effectiveness and reduce emissions, solvent-assisted SAGD techniques have been explored. Expanding Solvent-SAGD (ES-SAGD) involves co-injecting light hydrocarbons like propane or butane with steam to enhance oil viscosity reduction. This approach lowers the steam–oil ratio by combining solvent dissolution effects with thermal effects. However, the high cost of solvents, particularly butane, challenges its commercial feasibility. Propane is cheaper but less effective, while butane improves performance but remains expensive. This research aims to optimize ES-SAGD by using a propane–butane mixture to achieve efficient performance at a lower cost than pure butane. A linear sand pack is used to evaluate different propane/butane compositions, maintaining constant operational conditions and a solvent concentration of 15 vol.%. Temperature monitoring provides insights into steam chamber growth. Results show that solvent injection significantly enhances ES-SAGD performance compared to conventional SAGD. Performance improves with increasing butane concentration, up to 80% butane in the C₃–C₄ mixture at the test pressure and ambient temperature. Propane alone results in the lowest system temperature, while conventional SAGD reaches the highest temperature. These findings highlight the potential of optimized solvent mixtures to improve ES-SAGD efficiency while reducing costs and GHG emissions. Full article

This study is dedicated to fundamental research on evaluating the effectiveness of enhanced oil recovery (EOR) methods for high-viscosity oil reservoirs. This paper presents the results of filtration experiments assessing the application of thermal, chemical, and gas-based EOR techniques to reservoir cores of high-viscosity oil, using the East Moldabek field in Kazakhstan as a case study. Experimental studies were conducted on the Cretaceous horizons M-II and M-III as well as the Jurassic horizon J-IV. The obtained production data from the East Moldabek wells indicated the low efficiency of conventional recovery methods. The objective of this study was to identify the most effective EOR method in terms of displacement efficiency. The investigated recovery techniques included base case conventional waterflooding (displacement using formation water), thermal EOR (hot-water flooding), chemical EOR (polymer flooding and ASP flooding), and gas EOR (nitrogen and CO₂ flooding). The filtration experiments were conducted at different times using various filtration systems. The results indicated that the most effective EOR methods for the highly viscous oil in the East Moldabek field were the chemical and thermal EOR techniques. The chemical EOR included ASP flooding, polymer flooding, and surfactant solution injection. ASP flooding achieved the highest increase in displacement efficiency, reaching 19%, making it the most effective method among all of the others. Full article

This study investigates the adsorption of surfactants on Algerian reservoir rock from Hassi Messaoud. A new data generation method based on a design of experiments (DOE) approach has been developed to improve the accuracy of adsorption modeling using artificial neural networks (ANNs). Unlike traditional data acquisition methods, this approach enables a methodical and structured exploration of adsorption behavior while reducing the number of required experiments, leading to improved prediction accuracy, optimization, and cost-effectiveness. The modeling is based on three key parameters: surfactant type (SDS and EOR ASP 5100), concentration, and temperature. The dataset required for ANN training was generated from a polynomial model derived from a full factorial design (DOE) established in a previous study. Before training, 32 different ANN configurations were evaluated by varying learning algorithms, adaptation functions, and transfer functions. The best-performing model was a cascade-type network employing the Levenberg–Marquardt learning function, learngdm adaptation, tansig activation function for the hidden layer, and purelin for the output layer, achieving an R² of 0.99 and an MSE of 6.84028 × 10⁻⁹. Compared to DOE-based models, ANN exhibited superior predictive accuracy, with a performance factor (PF/3) of 0.00157 and the same MSE. While DOE showed a slight advantage in relative error (9.10 × 10⁻⁵% vs. 1.88 × 10⁻⁴% for ANN), ANN proved more effective overall. Three optimization approaches—ANN-GA, DOE-GA, and DOE-DF (desirability function)—were compared, all converging to the same optimal conditions (SDS at 200 ppm and 25 °C). This similarity between the various optimization techniques confirms the strength of genetic algorithms for optimization in the field of EOR and that they can be reliably applied in practical field operations. However, ANN-GA exhibited slightly better convergence, achieving a fitness value of 2.3247. Full article

Oil production will remain essential in the coming decades, requiring environmental responsibilities that are aligned with Agenda 2030. Enhanced oil recovery (EOR) increases recovery efficiency with low investment, but environmental protection technologies (EOR and Env), including green EOR (GEOR) and waste treatment (WT), must be integrated. The BRICS association, representing half of global oil production, promotes technology transfer in this context. Worldwide patent data (2004–2023) of EOR and Env technologies at TRL 4–5 in BRICS and non-BRICS countries were compared for nine GEOR (1489 patents) and nine WT (2292 patents) methods. China is the global leader (73%, being 98% of BRICS patents), maintaining dominance even when normalized by GDP. Non-BRICS patents are from the USA (41%), Japan (31%), and the Republic of Korea (14%). BRICS countries surpassed non-BRICS in 2014, with a 5.9% growth rate, −13.2% for non-BRICS, with all methods growing, whereas in non-BRICS, only water flocculation treatment is growing. BRICS technological specialization is expanding more rapidly than that of non-BRICS countries. BRICS countries exhibit higher relative technological advantages and distance in surfactants, polymers, macromolecules, sludge treatment, and multistage water treatment devices. Non-BRICS countries are more competitive in in situ combustion, water alternating gas (WAG), re-pressurization, vacuum techniques, flotation, water–oil separation, sorption, or precipitation, flocculation, and oil-contaminated water. China is the primary BRICS leader and is positioned to define BRICS policies regarding technology transfer and innovation. Technological partnerships between BRICS and non-BRICS countries are strongly recommended to enhance synergy and achieve sustainable and efficient production more rapidly. Full article

The CCUS industry is developing rapidly worldwide, and its projects are gradually transitioning from single-section initiatives to whole-industry applications. Capture targets have expanded from power plants and natural gas processing to include steel, cement, kerosene, fertilizer, and hydrogen production. This paper analyzes CO₂ emissions in eight major industries around oil regions in China, including emission factors, emission scale, and the composition and distribution of emission sources. The cost of CO₂ sources and CO₂-EOR affordable cost limits under different scenarios are calculated for different oil regions. The main influencing factors of the cost are analyzed, and possible ways to fill the cost gap are proposed. This paper also constructs a CO₂-EOR strategic planning framework and a mathematical programming model, formulating short-term, mid-term, and long-term strategic plans for CO₂-EOR and storage in 10 oil regions. Full article

Hydrogen as fuel in civil aviation gas turbines is promising due to its no-carbon content and higher net specific energy. For an entry-level market and cost-saving strategy, it is advisable to consider reusing existing engine components whenever possible and retrofitting existing engines with hydrogen. Feasible strategies of retrofitting state-of-the-art Jet A-1 fuelled turbofan engines with hydrogen while applying minimum changes to hardware are considered in the present study. The findings demonstrate that hydrogen retrofitted engines can deliver advantages in terms of core temperature levels and efficiency. However, the engine operability assessment showed that retrofitting with minimum changes leads to a ~5% increase in the HP spool rotational speed for the same thrust at take-off, which poses an issue in terms of certification for the HP spool rotational speed overspeed margin. Full article

Gas channeling during CO₂ flooding poses a significant challenge to enhanced oil recovery (EOR) in heterogeneous reservoirs, limiting both oil recovery and CO₂ sequestration efficiency. To address this issue, a CO₂-responsive plugging gel was developed using polyethyleneimine (PEI), sodium dodecyl sulfate (SDS), and nano-silica. The gel formulation, containing 0.8% SDS, 0.8% PEI, and 0.1% nano-silica, demonstrated excellent CO₂-responsive thickening behavior, achieving a viscosity of over 12,000 mPa·s under selected conditions. The gel exhibited reversible viscosity changes upon CO₂ and N₂ injection, shear-thinning and self-healing properties, and stability under high-temperature (90 °C) and high-salinity (up to 20,000 mg/L) conditions. Plugging experiments using artificial cores with gas permeabilities of 100 mD and 500 mD achieved a plugging efficiency exceeding 95%, reducing permeability to below 0.2 mD. These results emphasize the potential of the CO₂-responsive plugging gel as an efficient approach to reducing gas channeling, boosting oil recovery, and enhancing CO₂ storage capacity in crude oil reservoirs. Full article