Search Results (2,822)

Introduction: Efficient geothermal energy extraction has the potential to significantly alleviate the shortage of fossil energy, but low extraction efficiency and an insufficiently understood extraction mechanism remain key bottlenecks hindering its large-scale deployment. Method: This study develops a fluid–solid coupled numerical model based on the intrinsic physical properties of geological reservoirs to systematically analyze the energy extraction characteristics of geothermal systems. Simultaneously, the effects of key geological factors on fluid flow behavior within geothermal reservoirs are investigated. Furthermore, molecular dynamics simulations are employed to elucidate the microscopic mechanisms by which driving fluids facilitate geothermal energy extraction. Results: The results demonstrate that the thermo-hydraulic–mechanical (THM) numerical model was validated through a comparison with benchmark data reported in previous studies, exhibiting a high degree of agreement with geothermal extraction performance. The model further confirms that heat transport in the geothermal reservoir is characterized by a pronounced “tongue-in” isotherm pattern during the extraction process. Discussion: Lower initial temperatures of the driving fluid lead to more rapid geothermal energy extraction compared with higher initial temperatures, and the “tongue-in” phenomenon becomes increasingly pronounced as the initial injection temperature decreases. Moreover, increased injection pressure significantly enhances geothermal energy extraction efficiency; however, reduced pressure differentials markedly suppress the development of the “tongue-in” pattern and decrease reservoir permeability. In addition, water used as a heat-driving fluid achieves higher thermal extraction efficiency than water, while simultaneously exerting a stronger moderating effect on the permeability evolution of geothermal reservoirs. Conclusions: The simulation results obtained from the thermo-hydraulic-mechanical (THM) numerical model provide fundamental data to support the efficient development of geothermal reservoirs, while the associated analyses offer valuable insights into the selection of appropriate driving fluids for reservoirs with distinct geological characteristics. Full article

This study investigates methane leakage and diffusion from a buried high-pressure natural gas pipeline (8 MPa, 1000 mm diameter) using CFD simulations with the DES turbulence model. Based on homogeneous and layered soil models, the influences of soil porosity (0.46 to 0.54), particle size (10 μm to 100 μm), and soil stratification on the spatial and temporal characteristics of methane diffusion are systematically explored. The simulation results show that (1) methane diffuses from the leak hole to the surrounding soil in an ellipsoidal pattern, with the fastest diffusion speed along the pipeline’s axial direction. (2) In homogeneous soil, within the range of soil parameter values considered in this study, the absolute changes in risk assessment indices (FDR, GDR) caused by soil particle size were more significant; whereas the relative percentage changes in risk assessment indicators caused by soil porosity were more pronounced. (3) In layered soil, the permeability contrast between adjacent layers creates the permeability discontinuity interface effect. When a fine-grained or low-porosity layer overlies a coarse-grained layer, the upper layer acts as a hydraulic barrier, prolonging FDT from 130 s to 354 s while promoting significant horizontal spread at the interface. Conversely, a coarse-grained or high-porosity upper layer accelerates vertical breakthrough. These findings provide a scientific basis for risk assessment, monitoring site optimization, and emergency response planning, particularly in regions with heterogeneous stratified soils. Full article

In order to reveal the stress sensitivity characteristics of the Kuqa deep gas reservoir, this study investigates the problem from two complementary aspects. First, conventional variable confining pressure experiments and well-test interpretation are employed to clarify the basic stress sensitivity characteristics of the Kela 2 gas field under conditions of monotonically increasing effective stress. Second, considering that field operations such as gas injection and temperature rise may cause periodic pore-pressure fluctuations under nearly constant overburden pressure, this paper establishes a novel physical simulation method for multi-round charging and depletion recovery to investigate the additional reservoir responses under cyclic effective-stress evolution. The results show that (1) when the confining pressure increases from 5 MPa~40 MPa, the permeability of the core generally decreases, with a decrease of 5~85%. In contrast, the porosity decreased by only 2% to 12%. The number of cores with conventional air permeability greater than or equal to 1 mD in the Kela 2 gas field reservoir accounts for 63.4%. The stress sensitivity causes the permeability to decrease by less than or equal to 40%, and the overall stress sensitivity is not strong. (2) Post-test observations showed fracture development in some cores after the experiment, indicating that during the gas reservoir mining process, the stress cycle changes will cause some closed cracks in the core to reopen or produce new cracks, which will play a role in increasing permeability. After the crack is opened, the comprehensive recovery degree at the end of the stable production period increases by 21.7 percentage points, and 9.9 percentage points increase the comprehensive recovery degree at the end of the abandoned production. (3) The new understanding of this experiment has changed the traditional understanding that stress sensitivity can only lead to reservoir damage, and also pointed out a new technical direction for the field to improve reservoir physical properties and enhance oil recovery by changing stress effects such as heating-condensation, intermittent gas injection, and directional blasting. Full article

The Ordos Basin hosts abundant lacustrine shale oil resources. Adequately retained hydrocarbons in source rocks, together with favorable mobility, are prerequisites for large-scale shale oil exploitation. Therefore, the quantitative characterization of retained hydrocarbon content and mobility is a core research focus in shale oil exploration and development. This study investigates Chang 7 shale with varying lithofacies and geochemical characteristics. Stepwise pyrolysis and pyrolysis gas chromatography–mass spectrometry (GC–MS) were applied to analyze retained hydrocarbons in different occurrence states, their compositions, and biomarkers. In addition, nuclear magnetic resonance (NMR) combined with CO₂ flooding experiments was conducted, and the collected products under different displacement pressures were analyzed using GC–MS. The aim was to quantitatively examine the variations in expelled oil volume, compositional differences during migration, and occurrence features of shale oil within reservoir micro-pores. The results show the following: (1) Organic-rich shale is characterized by higher proportions of light and medium hydrocarbons, lower heavy fractions, and elevated aromatic hydrocarbon content. In contrast, low-organic-carbon mudstone or siltstone contains more medium and heavy hydrocarbons, with lower light and aromatic fractions. The C13−/C14+ ratio increases with total organic carbon (TOC). (2) In black shale, oil displacement is mainly contributed by mesopores. At low pressures, oil expulsion is difficult and dominated by heavy hydrocarbons. When pressure reaches a threshold, the capillary-bound oil in micropores is released, increasing production and improving oil quality. Muddy siltstone shows higher displacement efficiency than black shale, with contributions from pores of all sizes. At low pressures, its expelled oil volume is larger and lighter than that of black shale. With increasing pressure, the oil yield rises significantly, and medium–large pores produce heavier fractions compared with micropores, likely because light hydrocarbons preferentially enter micropores and are less prone to dissipation. (3) The main controlling factors for shale oil enrichment include retained hydrocarbon content, mobile hydrocarbon fraction, fluidity, and engineering-related parameters. Thick shale layers with high organic matter abundance, high proportions of light–medium hydrocarbons, and favorable porosity–permeability conditions, as well as interbedded siltstone, are enriched in mobile hydrocarbons. Full article

To clarify the migration and structural evolution of mining-induced overburden following grouting reconstruction of the Fourth Aquifer, the inner section of Panel 1022-2 in Wugou Coal Mine was taken as the engineering background. The evolution law of overburden movement and the development characteristics of the caving zone were systematically investigated via theoretical analysis, similar-material simulation, and numerical simulation. In addition, the maximum caving-zone height of Panel 1022-2 was calculated based on the measured caving-to-mining ratio of the adjacent Panel 1010-1. The results show that following grouting reconstruction of the Fourth Aquifer, the water inflow and permeability coefficient decreased significantly, the mining-induced water-body grade was classified as Grade III, and the required coal pillar type was converted from a waterproof safety coal (rock) pillar to an anti-collapse safety coal (rock) pillar. The bedrock failure morphology evolved sequentially from a symmetrical trapezoid to a stepped shape and finally to an asymmetrical saddle shape, with a maximum caving-zone height of 19.0 m, whereas the Fourth Aquifer evolved from fracture initiation and bed separation to asymmetrical overall subsidence. Overburden migration is jointly controlled by bedrock thickness and the mechanical properties of the unconsolidated layer, presenting a distinct three-stage evolution pattern. As the size of the reserved safety coal (rock) pillar decreases, the overburden failure mode changes from overall plastic failure under relatively thick bedrock, to semi-block failure with longitudinal fractures penetrating to the base of the Fourth Aquifer and transverse fractures and interlayer separation initiating inside the aquifer, and finally to intensified failure under thin-bedrock conditions. Based on field analogy with Panel 1010-1, the maximum caving-zone height of Panel 1022-2 was calculated to be 19.73 m, which is in good agreement with the numerical and similar-material simulation results, verifying the reliability of the three-stage overburden evolution law and the caving-zone height evaluation. Full article

During coalbed methane (CBM) production, coal reservoir pore/fracture structure varies dynamically under the action of fluid–solid coupling. And coal reservoir permeability changes accordingly. In order to factually investigate the dynamic changes in coal reservoir permeability in the CBM well drainage process, a comparative simulation experiment on the difference in coal permeability sensitivity to confining pressure (external pressure) and pore pressure (internal pressure) was carried out in this study. The results show that coal permeability presents a typical negative exponential decline with a decrease in pore pressure. The pore pressure sensitivity experiment can effectively simulate the permeability sensitivity characteristics caused by coal reservoir pressure. Based on the negative exponential function relationship between permeability and effective stress, a new calculating method for the effective stress coefficient was deduced. Namely, its value could be expressed as the quotient of the pore pressure sensitivity curve regression coefficient divided by the confining pressure sensitivity curve regression coefficient. A dynamic theoretical model for coal reservoir permeability characterized by reservoir pressure was systematically constructed based on the unique fluid (gas/liquid)–solid coupling characteristics of coal reservoirs. Furthermore, the general characteristics of the stress sensitivity of coal permeability during coalbed methane (CBM) recovery were analyzed. The dynamic evolution characteristics of coal reservoir permeability in the study area were further examined. Taking the production and drainage data of a typical actual CBM production well as an example, the theories regarding the permeability sensitivity of coal reservoirs to reservoir pressure presented in this paper were validated in practice. This indirectly confirmed the rationality and accuracy of the calculation method for the effective stress coefficient obtained through laboratory-based permeability sensitivity simulation experiments. This research provides robust theoretical support for the systematic monitoring and prediction of fluid production, reservoir pressure, and permeability during the CBM production process, carrying significant practical implications. Full article

Recently, a substantial quantity of oil and gas has been discovered in the pre-salt Lower Cretaceous microbialite successions of Brazil’s Santos Basin, thereby prompting a global surge in research related to microbialites. It has been demonstrated that microbial shoal reservoirs yield the highest hydrocarbon production, with optimal reservoir properties, as evidenced by experience in the field of oilfield production. However, as research progresses, it has become increasingly evident that significant heterogeneity exists in both the lithology and physical properties within microbial shoal bodies. In order to address the identified knowledge gap, the present study employs systematic petrological and petrophysical datasets. These include 30-m continuous core samples, thin-section analyses, routine petrophysical tests and mercury injection capillary pressure (MICP) measurements. The aim is to characterize the internal microfacies architecture and reservoir heterogeneity of microbial shoals. It is imperative to ascertain the principal factors that govern the heterogeneity observed in these reservoirs. This critical step is essential for a comprehensive understanding of the subject matter. The results of the study demonstrate that: the Barra Velha Formation microbial shoals in the Santos Basin can be subdivided into three microfacies, which are delineated from base to top. The foundation of the shoal is the shoal base. The rock composition is dominated by the presence of spherulites, with intracrystalline pores functioning as the primary reservoir spaces. The compositional rocks of the shoal flank are poorly sorted microbial debris, with intergranular and intragranular pores formed by penecontemporaneous dissolution. The sedimentary succession of the shoal core is characterized by well-sorted microbial debris rocks displaying multiple shallowing-upward sequences, with reverse-graded textures. The primary storage space is constituted by fabric-selective pores from penecontemporaneous dissolution, though these are subject to local disruption by destructive silicification. Meanwhile, the microbial shoals demonstrate wide porosity (8.8–26.4%, mean 16.8%) and permeability (0.13–839 mD, mean 169 mD) ranges, thus classifying them as medium-porosity, high-permeability reservoirs. The superimposition of microfacies and diagenetic processes gives rise to considerable reservoir heterogeneity. It is evident that the shoal core microfacies exhibits robust energy and substantial grain size, characteristics that facilitate its exposure above lake level during periods of high-frequency lake-level oscillation. This exposure is further compounded by the influence of atmospheric water dissolution, which remodels the microfacies during the quasi-contemporaneous period. The reservoir quality is optimal, exhibiting the highest proportion of large pores. The reservoir properties of the shoal flank are closely followed by medium and large pores, and those of the shoal base are the worst, with micro and medium pores. Full article

Reservoir pore structure is intimately linked to seepage characteristics; thus, determining its spatial variations is essential for formulating precise development schemes and remaining oil recovery strategies. Although the second member of the Shahejie Formation (Es₂) reservoir in the central-eastern Jizhong Depression generally possesses favorable macroscopic physical properties, discrepancies exist in dynamic development performance and remaining oil distribution across different regions. To clarify the influence of pore structure on seepage behavior, this study investigates the Es₂ reservoir in the Wen’an and Wuqiang areas of the Jizhong Depression, Bohai Bay Basin, utilizing integrated analytical methods including casting thin sections, scanning electron microscopy (SEM), mercury intrusion porosimetry (MIP), relative permeability tests, and microscopic visualized percolation experiments. The results demonstrate that the Wen’an area is dominated by primary intergranular pores with a bimodal throat distribution. Despite a high areal porosity (21.6%), its fine throats (3.87 μm) and severe heterogeneity (sorting coefficient: 16.20) lead to poor connectivity (mercury withdrawal efficiency: 11.29%), resulting in a finger-like water drive, a narrow two-phase co-seepage zone (30.48%), and a lower ultimate displacement efficiency (50.64%). In contrast, the Wuqiang area features dissolved-intergranular pores with a unimodal throat distribution. Benefiting from larger throats (7.75 μm) and lower heterogeneity (sorting coefficient: 4.32), it exhibits superior connectivity (mercury withdrawal efficiency: 31.57%), uniform displacement, a wider co-seepage zone (40.72%), and a higher ultimate efficiency (59.34%). Given the lower waterflooding efficiency in the Wen’an area, subsequent gas displacement experiments following waterflooding demonstrated an overall recovery increment of 25.83%. Based on the disparities in pore structures and seepage characteristics between the two areas, it is recommended that the Wuqiang area should continue utilizing conventional waterflooding, while the Wen’an area should consider gas displacement after waterflooding. Full article

Polymer gel profile control technology can effectively modify water flow channels in water-flooded oil reservoirs and enhance oil recovery. However, most polymer gel systems exhibit poor performance, such as low strength, not suitable for high-temperature and high-salinity reservoir conditions, leading to ineffective water shutoff. To address this challenge in complex formations of high-temperature, high-salinity fractured reservoirs, a temperature- and salt-tolerant polymer gel system with delayed crosslinking was developed based on the concept of slow hydrogen-bond crosslinking. Laboratory evaluations demonstrated that a gel system formulated with 0.4 wt% HPAM and 0.2 wt% PEI (HPAM/PEI) achieved a gel strength grade of G index. Even at 100 °C or a salinity of 200,000 ppm, the HPAM/PEI system maintained a gel strength grade of F, indicating excellent temperature resistance and shear stability. The slow hydrogen-bond crosslinking mechanism endowed the system with delayed gelation characteristics. Sandpack and core flooding experiments confirmed that the HPAM/PEI system could form high-strength gels in situ with low polymer retention. After treatment, the permeability of the core was reduced by over 99%, and the effective blocking duration exceeded 12 months. This study provides a theoretical foundation for applying the HPAM/PEI gel system in deep profile control and water shutoff in high-temperature and high-salinity reservoirs. Full article

This study, based on the characteristic that a small number of hydrocarbon-rich sub-sags control the majority of oil and gas reservoirs discovered in the HZ sag, establishes a foothold on the HZ26 sub-sag—the most prolific hydrocarbon-generating sub-sag in the HZ sag, focuses on WC formation of its peripheral structures, and discusses the hydrocarbon accumulation mechanism of WC formation in the HZ sag. Hydrocarbon charging periods were determined through an integrated analysis of homogenization temperatures of brine inclusions coexisting with hydrocarbon inclusions, stratigraphic burial and thermal history, and hydrocarbon generation stages of source rocks. A multiphase fluid charging physical simulation experiment was conducted to establish a covariant relationship between reservoir permeability and hydrocarbon charging pressure difference. Based on the residual pressure history and reservoir property evolution, a coupling relationship was established between the hydrocarbon charging driving force and resistance during hydrocarbon charging periods. The covariant relationship between reservoir permeability and hydrocarbon charging pressure difference and the coupling relationship between hydrocarbon charging driving force and resistance during hydrocarbon charging periods were then integrated to reconstruct the hydrocarbon charging process. The results reveal a mechanism for large-scale hydrocarbon charging and differential accumulation under the influence of overpressure. Full article

The Yanshangou landslide, located in the Baihetan Reservoir area, poses severe potential threats to the normal operation of the reservoir due to its distinct deformation characteristics and high sensitivity to reservoir water level fluctuations. This study systematically investigates the geological background, deformation characteristics, stability evolution, and landslide-induced surge hazards of the Yanshangou landslide in the Baihetan Reservoir area. This work only considers the influence of reservoir water level fluctuations, which is the dominant factor controlling the current progressive deformation of the landslide. Field surveys and GNSS/deep displacement monitoring results revealed that the Yanshangou landslide exhibits obvious staged deformation characteristics, and the landslide deformation rate was closely coupled with the dynamic changes in reservoir water level. A slope stability evaluation method integrating the Morgenstern–Price limit equilibrium method and Richard’s equation was established, and the results indicated that the Yanshangou landslide has low saturated permeability. Therefore, its factor of safety (FOS) presents a clear four-stage variation trend in response to reservoir water level fluctuations. A Smoothed Particle Hydrodynamics (SPH)-based numerical model was further developed to simulate the landslide-induced surges under two typical reservoir water level scenarios (815 m and 765 m). The simulation results demonstrated that a high reservoir water level led to more intense surges with greater height and higher velocity, while a low reservoir water level resulted in surges with a wider propagation range along the reservoir bank. The research findings of this study provide a comprehensive theoretical basis and detailed data support for the prevention and mitigation of geological hazards in the Baihetan Reservoir area, and also offer a reference for the hazard management of similar reservoir landslides worldwide. Full article

With the gradual depletion of conventional hydrocarbon resources, low- and ultra-low-permeability reservoirs have become important targets for oil development. Nanoemulsions exhibit great potential for enhanced oil recovery because of their favorable interfacial activity, small droplet size, and excellent transport capability. However, the interfacial dynamics and capillary mechanisms involved in microscale two-phase displacement processes remain poorly understood. In this study, a self-developed micro-capillary bundle apparatus was used to investigate nanoemulsion displacement behavior in micrometer-scale capillaries. The interfacial behavior was quantitatively analyzed based on the relationship between interface velocity and pressure difference (v-ΔP). The results show that the displacement process follows the classical Washburn equation, with a linear relationship between v and ΔP. During oil displacement, the capillary force remains negative and acts as a resistance, indicating a pressure-driven forced displacement mechanism. Environmental factors such as temperature, electrolyte concentration, and wettability have limited effects, whereas pore size plays a dominant role. The addition of an appropriate amount of microspheres can reduce capillary resistance and lower the required driving pressure. The present findings mainly reveal the interfacial motion characteristics and capillary mechanisms of nanoemulsions in microscale pore throats, providing a fundamental basis for understanding fluid transport behavior in low-permeability reservoirs. Full article

The Late Permian coal-bearing strata in western Guizhou Province, South China, are developed with multiple coal seams and rich in coalbed methane (CBM) resources. Controlled by the sealing layers within the coal-bearing strata, multiple vertically superposed independent CBM systems were formed, which complicates the CBM accumulation characteristics and limits CBM development. Through systematic sampling of the main coal seams and different lithologic strata in Borehole 101 on the southeastern limb of the Agong Syncline in western Guizhou, mercury intrusion porosimetry (MIP) and Klinkenberg permeability experiments were conducted on coal and rock samples. The results show that the coal samples have an average pore volume of 0.0417 mL/g, an average porosity of 5.37%, an average mercury withdrawal efficiency of 69.79%, and an average well test permeability of 0.3743 mD; the rock samples have an average pore volume of 0.0064 mL/g, an average porosity of 1.43%, an average mercury withdrawal efficiency of 7.88%, and an average Klinkenberg permeability of 0.0128 mD. The pore and permeability conditions of rock layers are significantly poorer than those of coal seams, which favorably contributes to the formation of effective sealing layers between coal seams and facilitates the CBM preservation. Mudstone and argillaceous siltstone in the coal-bearing strata, characterized by their low porosity and permeability, are suitable as effective gas and water barriers between coal seams. Based on a comprehensive analysis of the vertical variations in permeability, porosity, and gas-bearing characteristics of Borehole 101, the Upper Permian coal-bearing strata are preliminarily divided into four independent CBM-bearing systems. These systems are separated by tight rock layers with extremely low permeability and porosity, and their division aligns closely with the third-order sequence stratigraphic framework. The findings can provide a theoretical basis for deepening the understanding of CBM accumulation mechanisms in multi-seam regions and optimizing the orderly CBM development models. Full article

The reservoir quality and gas-bearing properties of the Wufeng Formation–Longmaxi Formation shale vary significantly across different structural units in the Luzhou area of the Sichuan Basin. The mechanisms of shale gas enrichment, tectonic controls, and accumulation models are critical determinants of the potential for three-dimensional (3D) development. Integrating data from core analyses, logging interpretation, focused ion beam scanning electron microscopy (FIB-SEM), and high-resolution core scanning, this study investigates the control exerted by fracture development and tectonic activity on shale gas enrichment and preservation. A conceptual model for shale gas enrichment and accumulation is established, and the potential for 3D development of deep shale gas in the Luzhou block is evaluated. The results indicate that: (1) Reservoir heterogeneity in deep shale gas plays is jointly governed by reservoir space characteristics, diagenesis, structural position, tectonic evolution, and fracture-fluid activity. Organic-rich siliceous shales retain favorable reservoir properties, characterized by an organic matter (OM) pore-dominated pore structure, relatively high porosity and permeability, and good gas-bearing potential due to overpressure preservation. (2) Structural style exerts dominant control over the gas-bearing variability. Synclines are significantly more favorable than anticlines, with free gas migration governing the enrichment pattern. The cores and flanks of synclines form zones of high gas content due to structural integrity, whereas the gas content decreases in anticlinal areas near faults. (3) Shale gas enrichment relies on the synergistic configuration of “high organic carbon content + high-quality pore reservoir space + robust structural preservation conditions.” Well L213 in the syncline core, distant from faults, exhibits good structural integrity and preservation conditions. Free gas from structurally lower positions migrates laterally toward the flanking anticlines, with a portion preserved in the syncline flanks. Concurrently, microfractures enhance reservoir storage and permeability, rendering syncline structures more conducive to shale gas preservation. (4) The high-quality shale succession in the study area is thick and laterally continuous, characterized by “vertical stacked pay zones.” This provides an excellent geological foundation for 3D development. By optimizing the well trajectory design and employing efficient fracturing technologies, such as “intensive fracturing” combined with temporary plugging and diversion, full and balanced utilization of vertically stacked sweet spot reservoirs can be achieved, significantly enhancing the single-well productivity and estimated ultimate recovery (EUR). Full article

This study evaluates the performance of foamed geopolymer concrete (FGC) incorporating rigid polyurethane (PU) waste as a partial sand replacement and aluminum powder (AP, 1%) as a foaming agent. The mixtures were based on metakaolin, fly ash, and silica fume. Fresh and hardened properties were assessed, including workability, setting time, density, compressive strength, flexural strength, splitting tensile strength, elastic modulus, water absorption, porosity, gas permeability, and chloride ion penetration. Microstructural characteristics were examined using scanning electron microscopy (SEM). The results show that moderate PU incorporation significantly enhances mechanical performance. The optimal mixture (PU30) achieved a compressive strength of 47.25 MPa at 180 days, representing a 15.6% increase compared to the control. Flexural and splitting tensile strengths improved by 19.9% and 16.7%, respectively, while the elastic modulus increased by 33.8% to 0.95 GPa. These improvements are attributed to enhanced particle packing and more efficient stress transfer within the matrix. In contrast, higher PU contents (>30%) reduced mechanical performance due to increased total porosity and weakened interfacial bonding. Durability-related properties indicated that mixtures PU20–PU30 exhibited reduced permeability and optimized pore structure, characterized by lower pore connectivity. SEM observations confirmed a denser matrix with uniformly distributed pores at optimal PU levels. Additionally, the integration of Random Forest regression with GLCM-based texture analysis demonstrated strong capability in predicting mechanical properties from SEM images. Overall, the combined use of PU waste and AP enables the production of lightweight, structurally efficient, and sustainable FGC with improved mechanical and durability performance. Full article