Search Results (761)

Permeability is a critical parameter for evaluating the production potential of natural gas hydrate reservoirs, and its accurate prediction is essential for enhanced oil recovery (EOR). However, existing permeability models often assume a uniform particle distribution, neglecting the inherent heterogeneity of natural sediments, and rarely fully couple the effects of effective stress and temperature variations induced by EOR operations. To address that gap, this study develops a novel non-empirical fractal permeability model that incorporates particle heterogeneity through an offset angle (θ) and an aspect ratio (m), and couples these with thermoelastic theory to describe the evolution of the pore structure under coupled thermo-mechanical conditions. The model accounts for two hydrate growth habits (grain-coating and pore-filling) and allows for their coexistence via weighting coefficients. Using this model, we systematically investigate the individual and combined effects of effective stress, temperature, particle heterogeneity, and hydrate saturation on permeability. Model predictions are validated against independent experimental data from multiple sources, showing good agreement. The results reveal that permeability decreases with increasing effective stress and temperature, with stress playing a more dominant role; moreover, the transition between hydrate growth habits under stress is captured. The proposed model provides a theoretical tool to understand permeability evolution in heterogeneous hydrate reservoirs under varying thermo-mechanical conditions, thereby supporting EOR strategy optimization. Full article

The decision-making procedure to develop and manage a production strategy is challenging because it requires a high investment and is performed under uncertainty. Heavy-oil reservoirs present low mobility and a high production of water under waterflooding. However, intelligent wells with ICVs (inflow control valves) and polymer flooding can improve the field’s performance. This work proposes a decision analysis to select the best strategy for the development of a heavy-oil field, evaluating and comparing the feasibility of waterflooding, polymers, and ICVs. We complement the nominal optimization accomplished for the base case in previous works by considering a probabilistic procedure with uncertainties, which includes the following: the generation of uncertain scenarios, the initial risk evaluation, the optimization of production strategies, a risk curve analysis, and the selection of the best strategy. A model-based reservoir simulation is used to perform the procedure, with the Expected Monetary Value (EMV) quantifying the economic returns. The case study is a sandstone heavy-oil reservoir (13° API) that represents a real Brazilian offshore field. Based on the EMV, we selected the polymer flooding strategy for this case study. However, since better water management was achieved with small differences to the polymer strategy, the option of using the ICVs in combination with polymer could be attractive depending on the various objectives of an oil field. Full article

Surfactants play a crucial role in enhanced oil recovery by reducing interfacial tension (IFT) and promoting emulsification. However, for low-permeability reservoirs after water flooding, it remains unclear which ability is more crucial for improving recovery. To address this question, this study compared the oil displacement effects of three surfactants with different IFTs and emulsifying properties using a series of core displacement experiments. The results show that the strongly emulsifying surfactant S1# achieved an incremental oil displacement efficiency of 9.94%, which is higher than that of the ultra-low-IFT surfactant S3# (8.63%), while the composite surfactant S2# (strong emulsification + ultra-low-IFT) achieved the highest incremental oil displacement efficiency of 11.79%, representing an improvement of 3.16% compared with S3#. The three surfactants have the same effect on improving oil recovery and oil displacement efficiency in heterogeneous rock cores. Strong emulsification promotes abundant in situ emulsions, increases injection pressure (up to 0.85 MPa compared with 0.41 MPa for ultra-low-IFT flooding), and expands the swept volume, indicating that emulsification-driven sweep improvement dominates over capillary-force reduction under the investigated conditions. Furthermore, a composite displacement strategy combining emulsification-driven plugging and ultra-low-IFT oil washing achieved a 12.37% recovery improvement while maintaining relatively low injection pressure (~0.48 MPa). However, the effectiveness of this mechanism is strongly dependent on reservoir heterogeneity. When the permeability contrast increased from 5.4 to 17.3, incremental recovery decreased by up to 7.03%, demonstrating that strong heterogeneity significantly limits the effectiveness of emulsification-driven sweep expansion. This work advances the understanding of surfactant flooding mechanisms and provides guidance for designing and deploying surfactants in water-flooded low-permeability reservoirs. Full article

The impact modification of polyamide 6 (PA6) using maleic anhydride-grafted ethylene/1-octene copolymers (EOR-g-MAH) involves a trade-off between improved compatibilization, grafting-induced changes in modifier molecular weight $MW$, and melt processability. In this study, EOR modifiers with comparable initial $MW$ but different octene contents ($c_{\mathrm{o}\mathrm{c}\mathrm{t}}$ = 13, 15, and 16 mol%) were grafted to two MAH levels ($c_{\mathrm{M}\mathrm{A}\mathrm{H}}$ = 0.5 and 1.0 wt%) and incorporated into PA6 at a fixed composition. The system was designed to maintain a comparable microstructure, enabling the isolation of grafting-induced changes in modifier properties from microstructural effects. $MW$ distributions were analyzed by gel permeation chromatography, and the impact behavior was evaluated over a wide temperature range, using an instrumented Charpy impact test. The results reveal a strong, interrelated, $c_{\mathrm{o}\mathrm{c}\mathrm{t}}$- and $c_{\mathrm{M}\mathrm{A}\mathrm{H}}$-dependent competition between β-scission and cross-linking during grafting, which governs the modifier’s $MW$ distribution and particle strength. Higher $c_{\mathrm{o}\mathrm{c}\mathrm{t}}$ (15 and 16 mol%) enhances the impact performance up to ≈0 °C, well above the brittle–ductile transition temperature (BDTT), through increased elastic and plastic deformation capability of the modifiers. At elevated temperatures, however, successive melting of the modifiers leads to a loss of particle strength. At high $c_{\mathrm{o}\mathrm{c}\mathrm{t}}$ and $c_{\mathrm{M}\mathrm{A}\mathrm{H}}$ = 1.0 wt%, susceptibility to β-scission increases, leading to $MW$ reduction that, for $c_{\mathrm{o}\mathrm{c}\mathrm{t}}$ = 16 mol%, is detrimental to impact performance, particularly above the BDTT. This effect is further amplified by reduced ductility due to stronger polar intermolecular interactions at high grafting levels. A moderate $c_{\mathrm{M}\mathrm{A}\mathrm{H}}$ = 0.5 wt% and $c_{\mathrm{o}\mathrm{c}\mathrm{t}}$ = 15 mol% provides an optimal compromise between strength and ductility, delivering high impact strength across a broad temperature range. At this $c_{\mathrm{M}\mathrm{A}\mathrm{H}}$ level, the number of PA6 chains covalently anchored to the modifier particles is moderate, resulting in lower compound viscosity and supporting favorable melt processability. Full article

Upper E_s4 lacustrine calcareous shale in the Dongying Depression is characterized by strong pore–throat heterogeneity that limits shale-oil producibility. This study quantifies multiscale pore–throat complexity using high-pressure mercury intrusion-based fractal analysis (segmented fractal dimensions D₁–D₃ and a weighted comprehensive fractal dimension, D_c) and evaluates its control on oil occurrence and mobilization using low-field 2D NMR (T₁–T₂) and confocal microscopy before and after high-temperature, high-pressure spontaneous imbibition. Reservoirs show clear scale segmentation, with micropore fractality governing quality differentiation. Imbibition promotes desorption and redistribution from adsorbed to free oil, but effective mobilization is primarily controlled by pore–fracture connectivity: samples with well-connected networks can mobilize both adsorbed and free oil efficiently, whereas poorly connected systems exhibit desorption without effective production, implying that thermal stimulation alone is insufficient without fracture-assisted flow pathways. Movable-oil saturation decreases systematically with increasing D_c, indicating that higher roughness and tortuosity intensify capillary retention and Jamin trapping. D_c provides an actionable criterion for sweet-spot ranking and for designing stimulation–imbibition coupling and water-based EOR strategies in lacustrine calcareous shale-oil reservoirs. Full article

The impact modification of polyamide 6 (PA6) using maleic anhydride grafted ethylene/1-octene copolymers (EOR-g-MAH) is well-established, yet the isolated influence of intrinsic modifier parameters—specifically octene content $c_{\mathrm{o}\mathrm{c}\mathrm{t}}$ and molecular weight $MW$—remains insufficiently understood due to confounding microstructural effects. This study presents a systematic approach to decouple these variables by maintaining constant grafting degree, modifier content, and compound morphology. A series of PA6/EOR-g-MAH compounds was prepared with controlled variations in $c_{\mathrm{o}\mathrm{c}\mathrm{t}}$ (8–15 mol%) and $MW$ (34–42 kg/mol). Instrumented Charpy impact testing across a temperature range from −40 °C to +23 °C enabled quantification of crack initiation and propagation energies ($E_{\mathrm{i}\mathrm{n}\mathrm{i}\mathrm{t}}$ and $E_{\mathrm{p}\mathrm{r}\mathrm{o}\mathrm{p}}$), providing mechanistic insight into the brittle–ductile transition. Complementary thermal, rheological, and tensile analyses of the modifiers revealed how $c_{\mathrm{o}\mathrm{c}\mathrm{t}}$ governs cavitation behavior and low-temperature toughness, while $MW$ in particular influences particle integrity and energy dissipation at elevated temperatures. The results demonstrate that targeted adjustment of $c_{\mathrm{o}\mathrm{c}\mathrm{t}}$ and $MW$ allows for the precise tuning of brittle–ductile transition temperature (BDTT) and impact resistance. The compound containing a high-$MW$ modifier with intermediate $c_{\mathrm{o}\mathrm{c}\mathrm{t}}$ (13 mol%) exhibited the most favorable balance of toughness and strength retention at elevated temperatures. These findings offer design principles for engineering thermoplastics with enhanced performance across broad service conditions. Full article

Knowledge of the migration characteristics of polymer systems in pore throats is essential for the effective application of polymers as a profile-control oil-displacement agent for enhanced oil recovery. In this study, the effect of concentration on the viscosity and hydrodynamic radius of polymer systems was investigated using a rheometer and a dynamic light scattering instrument. Furthermore, pore-throat models, homogeneous cores, and multi-measuring-point sand-packed models were constructed to investigate pore-scale migration patterns and the effect of the throat–polymer ratio (defined as the ratio of throat size to polymer hydrodynamic radius) on the migration properties of polymers in porous media. The results showed that the transport of polymer systems in porous media is primarily related to the throat–polymer ratio. When this ratio is sufficiently small (i.e., no more than 18.94), the migration pattern of the polymer systems in the pore-throat model does not exhibit the characteristics of polymer solution flow, but rather, of discontinuous-dispersion retention, plugging-breakthrough migration, and stable-plugging retention. Upon increasing the injection rate, the polymer systems also exhibit the migration characteristics of discontinuous dispersion at a larger throat–polymer ratio. Moreover, polymer system migration resistance and improved sweep efficiency in porous media are influenced by not only the viscosity of polymer systems, but also the throat–polymer ratio. The smaller the throat–polymer ratio, the stronger the retention and plugging ability of the polymer systems. The outcomes of this study are significant for the design of polymer flooding operations in oilfields. Full article

CO₂-assisted steam huff and puff is an effective method to improve oil recovery and store CO₂ in heavy oil reservoirs. However, few studies focused on complex geological formations, such as bottom water. The bottom water condition not only complicates the process of oil production and CO₂ sequestration, but also makes migration and distribution of oil, water and CO₂ unclear. In this paper, a numerical geological model of an offshore heavy oil reservoir with bottom water is established to analyze the influence of bottom water on injection and production parameters, oil recovery and CO₂ storage capability under vertical and horizontal well layouts. The results show that the bottom water could maintain the formation pressure, but reduce the steam chamber radius and heavy oil utilization area, increase water production and decrease the oil–water ratio. CO₂ could enhance oil recovery in the bottom water reservoir. Oil development indicators of the horizontal well are higher than the vertical well. Meanwhile, CO₂-assisted steam huff and puff use in the bottom water reservoir can create a high-pressure and -temperature environment to make CO₂ supercritical, as it has better CO₂ storage capability and efficiency. The CO₂ storage efficiency of the horizontal well is 63% larger than the vertical well. Thus, the horizontal well layout should be used as a priority if bottom water presents. Conducted analysis of bottom water formation sensitivity parameters shows that the advantageous formation conditions are high oil saturation, porosity of 0.2–0.4 and permeability of 2000–3000 mD. The influence degrees of each formation parameter were evaluated as well. Full article

Carbon dioxide injection is one of the most advanced and commercially proven methods of enhanced hydrocarbon recovery, and CO₂ injection has been shown to be very effective in conventional oil reservoirs and is gaining attention in gas, unconventional, and coalbed methane reservoirs. The advantages of CO₂ injection lie in the favorable phase properties and interactions with reservoir fluids, such as swelling, reduction in oil viscosity, reduction in interfacial tension, and miscible displacement in favorable cases. But the low viscosity and density of CO₂ compared to the reservoir fluids result in unfavorable mobility ratios and gravity override, resulting in sweep efficiency limitations. This review offers a broad and EOR-centric evaluation of the various CO₂ injection methods for a broad array of reservoir types, such as depleted oil reservoirs, gas reservoirs for the purpose of gas recovery, tight gas/sands, as well as coalbed methane reservoirs. Particular attention will be given to the use of mobility control/sweep enhancement techniques such as water alternating gas (CO₂-WAG), foam-assisted CO₂ injection, polymer-assisted WAG processes, as well as hybrid processes that combine the use of CO₂ injection with low salinity or engineered waterflood. Further, recent developments in compositional simulation, fracture-resolving simulation, hysteresis modeling, and data-driven optimization techniques have been highlighted. Operational challenges such as injectivity reduction, asphaltene precipitation, corrosion, and conformance problems have been reviewed, along with the existing methods to mitigate such issues. Finally, key gaps in the current studies have been identified, with an emphasis on the development of EHR processes using CO₂ in complex and low-permeability reservoirs, enhancing the resistance of chemical and foam methods in realistic conditions, and the development of reliable methods for optimizing the process on the field scale. This review article will act as an aid in the technical development process for the implementation of CO₂ injection projects for the recovery of hydrocarbons. Full article

Background and Objectives: Glioblastoma (GBM), defined as IDH-wildtype CNS WHO grade 4, remains the most common and aggressive primary malignant brain tumor in adults. Although the extent of resection (EOR), particularly gross total resection (GTR), is considered a potentially modifiable factor, survival comparisons across surgical groups are vulnerable to selection bias and unmeasured biological confounding. We evaluated the association between GTR and survival outcomes in patients with newly diagnosed IDH-wildtype GBM in a dual-center, real-world cohort. Materials and Methods: We conducted a retrospective, dual-center cohort study of 100 adult patients with histopathologically confirmed GBM who underwent primary surgical resection between 2015 and 2021. GTR was defined as no measurable residual contrast-enhancing tumor on early postoperative MRI (≤72 h). All patients received adjuvant chemoradiotherapy according to the Stupp protocol. Survival was analyzed using Kaplan–Meier methods with log-rank tests and explored using univariable Cox regression analysis. Given the missing key prognostic covariates (notably MGMT promoter methylation) and the retrospective design, the analyses were reported as unadjusted and descriptive. Results: Of the 100 patients, 63 (63%) underwent GTR and 37 (37%) non-GTR. The GTR group had a significantly higher rate of radiologic complete response (42.9% vs. 10.8%, p = 0.001). However, no significant differences were observed in overall survival (OS; median 13 vs. 12 months, p = 0.847) or progression-free survival (PFS; 8 vs. 8 months, p = 0.963) between the groups in unadjusted analyses. Long-term Kaplan–Meier estimates (e.g., 5-year OS) should be interpreted cautiously due to the small number of patients at risk and potential selection and biological confounding. Conclusions: In this dual-center cohort, GTR was associated with improved radiologic response but not with longer OS or PFS in unadjusted analyses. These results should be considered hypothesis-generating and not interpreted as evidence against maximal safe resection. The absence of MGMT promoter methylation status, lack of volumetric EOR quantification (including non-contrast-enhancing/FLAIR disease), and lack of standardized functional outcome data substantially limited causal inference. Prospective studies integrating molecular stratification, volumetric resection metrics, and functional outcome assessments are warranted. Full article

Integrating enhanced oil recovery (EOR) with geological carbon storage presents a dual-strategy solution for sustainable hydrocarbon production and greenhouse gas emission mitigation. CO₂ flooding, particularly under miscible conditions, is a pivotal technology in this endeavor. This study employs advanced in situ nuclear magnetic resonance (NMR) imaging to visually and quantitatively investigate the pore-scale mechanisms of CO₂ flooding in fractured carbonate rocks from a Kazakhstan oilfield. By establishing a novel correlation between NMR data and pore throat size distribution, we quantify the lower limit of pore throat mobilization—a key parameter for evaluating storage and displacement efficiency. Results show that miscible CO₂ flooding significantly reduces this limit to the submicron scale (0.1 μm) in matrix rocks, dramatically improving oil recovery from small pores. However, fracture networks dominate fluid flow, leading to early gas breakthrough and severely limiting CO₂ penetration and miscible displacement in the matrix. The study provides pore-scale insights for optimizing CO₂ injection strategies to maximize both hydrocarbon recovery and CO₂ storage potential in complex carbonate formations. The study elucidates the microscopic mobilization mechanisms and remaining oil distribution patterns during CO₂ flooding in volatile reservoirs. Moreover, it represents an environmentally friendly methodology for mitigating greenhouse gas emissions. Full article

Enhanced oil recovery (EOR) in fractured reservoirs presents significant challenges due to fluid channeling and poor sweep efficiency. In this study, a synergistic EOR system was developed with polymer-based weak gel as the primary component and foam as the auxiliary enhancer. The system utilizes a low-concentration polymer (1000 mg·L⁻¹) that forms a weakly cross-linked three-dimensional viscoelastic gel network in the aqueous phase, inheriting the core functions of viscosity enhancement and profile control from polymer flooding. Foam acts as an auxiliary component, leveraging the high sweep efficiency and strong displacement capability of gas in fractures. These two components synergistically create a multiscale enhancement mechanism of “bulk-phase stability control and interfacial-driven displacement.” Systematic screening of seven foaming agents identified an optimal formulation of 0.5% SDS and 1000 mg·L⁻¹ polymer. Two-dimensional visual flow experiments demonstrated that the polymer-induced gel network significantly improves mobility control and sweep efficiency under various injection volumes (0.1–0.7 PV) and gravity segregation conditions. Numerical simulation in a 3D fractured network model confirmed the superiority of this enhanced system, achieving a final oil recovery rate of 75%, significantly outperforming gas flooding (65%) and water flooding (59%). These findings confirm that weakly cross-linked polymer gels serve as the principal EOR material, with foam providing complementary reinforcement, offering robust conformance control and enhanced recovery potential in fracture-dominated reservoirs. Full article

Declining recovery factors from mature oil fields, coupled with the technical challenges of recovering residual oil under harsh reservoir conditions, necessitate the development of advanced enhanced oil recovery (EOR) techniques. While promising, chemical EOR often faces economic and technical hurdles in high-salinity, high-temperature environments where conventional polymers like hydrolyzed polyacrylamide (HPAM) degrade and fail. This study presents a comprehensive numerical investigation that addresses this critical industry challenge by applying a rigorously calibrated simulation framework to evaluate a novel hybrid EOR process that synergistically combines an ionic liquid (IL) with HPAM polymer. Utilizing core-flooding data from a prior study that employed the same Berea sandstone core plug and Saudi medium crude oil, supplemented by independently measured interfacial tension and contact angle data for the same chemical system, we built a core-scale model that was history-matched with RMSE < 2% OOIP. The calibrated polymer transport parameters—including a low adsorption capacity (~0.012 kg/kg-rock) and a high viscosity multiplier (4.5–5.0 at the injected concentration)—confirm favorable polymer propagation and effective in -situ mobility control. Using this validated model, we performed a systematic optimization of key process parameters, including IL slug size, HPAM concentration, salinity, temperature, and injection rate. Simulation results identify an optimal design: a 0.4 pore volume (PV) slug of IL (Ammoeng 102) reduces interfacial tension and shifts wettability toward water-wet, effectively mobilizing residual oil. This is followed by a tailored HPAM buffer in diluted formation brine (20% salinity, 500 ppm), which enhances recovery by up to 15% of the original oil in place (OOIP) over IL flooding alone by improving mobility control and enabling in-depth sweep. This excellent history match confirms the dual-displacement mechanism: microscopic oil mobilization by the IL, followed by macroscopic conformance improvement via HPAM-induced flow diversion. This integrated simulation-based approach not only validates the technical viability of the hybrid IL–HPAM flood but also delivers a predictive, field-scale-ready framework for heterogeneous reservoir systems. The work provides a robust strategy to unlock residual oil in such challenging reservoirs. Full article

Severe reservoir heterogeneity in offshore oilfields often leads to dominant flow channels, high water cut, and low sweep efficiency during long-term water flooding. In this study, an in situ self-assembled composite foam system combining soft polymer particles with a low-interfacial-tension foaming agent was developed for profile control and enhanced oil recovery (EOR) in offshore heterogeneous reservoirs. The self-assembly characteristics and physicochemical properties of different particle systems were evaluated to optimize the composite foam structure. Static and dynamic experiments were conducted to assess foam stability, plugging performance, injectivity behavior, and oil displacement efficiency. Results show that the optimized composite foam undergoes in situ self-assembly under reservoir conditions, forming a stable particle–foam structure that enhances selective plugging and mobility control. Core flooding experiments demonstrate that the system increases oil recovery by up to 27.2% across a wide permeability range. Field application further confirms its effectiveness in regulating interlayer water absorption, stabilizing injection pressure, and reducing water cut. These results indicate that the proposed in situ self-assembled composite foam is a promising technique for integrated profile control and enhanced oil recovery in offshore heterogeneous reservoirs. Full article