Search Results (606)

In carbonate petroleum reservoirs, permeability impairment caused by asphaltene precipitation and deposition remains a major challenge that limits long-term productivity. This study introduces a green polymeric nanocomposite (KCl/SiO₂/Xanthan/Origanum vulgare, NCs) designed to control interfacial dynamics and preserve flow capacity in carbonate formations. Using a multi-technique approach—interfacial tension (IFT) analysis, atomic force microscopy (AFM), and rock-core, fluid-flooding experiments at simulated subsurface conditions—the NCs’ abilities were evaluated in terms of their potential to modify properties at fluid–fluid and fluid–rock interfaces. The NCs increased the CO₂–brine/oil IFT slope in certain pressure regions by up to 40.77%. These results indicate competitive adsorption that stabilizes interfaces. Adsorption isotherms confirmed a monolayer mechanism with a high capacity of 294.12 mg/g. AFM topographic mapping revealed order-of-magnitude changes in surface roughness (reductions in average roughness by ~75%, root-mean-square by ~83%, peak-to-valley by ~93%). These results directly link nanoscale smoothing to reduced capillary pinning. Core flooding tests demonstrated that NCs treatment decreased formation damage by up to 67.45% at 4000 psi, maintaining a high permeability ratio (k/k_i = 0.87) and preserving porosity (φ/φ_i = 0.887, representing 88.7% porosity retention). These results establish that the studied NCs coherently manipulate fluid physics in relation to molecular adsorption and macroscopic permeability. Consequently, these NCs offer a sustainable, high-performance strategy for flow assurance and formation damage control in geological and geothermal reservoirs. Full article

The tight sandstone gas reservoir in Qingshimao gas field has the characteristics of complex gas–water distribution, low reservoir quality, low porosity, low permeability and high water saturation. Single-well productivity is low, the production and pressure decrease rapidly, the stable production period is short and economically viable development remains challenging. Therefore, considering the reservoir physical properties and development characteristics of the Qingshimao area, physical experiments and numerical simulations were conducted to investigate the reserve utilization characteristics of complex tight water-bearing gas reservoirs and to evaluate the effectiveness of CO₂ injection in restoring reservoir pressure and enhancing gas recovery after depletion. The results show that: (1) The movable-water saturation of Type I and Type II reservoirs ranged from 2 to 18% and 3–21%, respectively, while increasing water saturation reduced cumulative gas production and increased gas-flow resistance. Type III and Type IV reservoirs are limited by low permeability and fine pore throat. The movable-water saturation is less than 8% and 6% respectively under high water saturation conditions, and the gas–water flow is obviously limited. (2) Both continuous CO₂ injection and post-injection soaking can promote residual-gas recovery after depletion. Post-injection soaking prolongs the contact time between CO₂ and residual methane, whereas fractured cores exhibit more rapid pressure recovery but earlier CO₂ breakthrough. (3) Pore scale and two-dimensional visualization experiments show that after CO₂ injection, the pressure is transferred from the injection inlet to the production outlet, and the depleted low-pressure area is supplemented. The incremental recovery factor of the two-dimensional models after CO₂ injection ranged from 22.81 to 25.28 percentage points. (4) The numerical simulation results show that permeability, water saturation, and the injection and production rates jointly control pressure restoration and gas recovery during CO₂ injection. The high-permeability reservoir achieves a higher recovery factor but experiences earlier CO₂ breakthrough. High water saturation and high injection and production rates will weaken the effective sweep. In field application, the layers with good connectivity and moderate water saturation should be preferred, and the injection and production rates should be reasonably controlled to reduce the risk of gas channeling. Overall, post-depletion CO₂ injection can effectively restore reservoir pressure, mobilize residual methane, and enhance gas recovery in tight water-bearing gas reservoirs. The experimental results support post-depletion CO₂ injection as a potential approach for improving the development performance of tight water-bearing gas reservoirs. Full article

Geothermal energy and underground thermal storage (UTES) are vital to the low-carbon energy transition, yet their optimization is bottlenecked by multi-scale heterogeneity, coupled thermal–hydraulic–mechanical–chemical (THMC) processes, and the high computational cost of full-physics simulations. This review systematically evaluates machine learning (ML) as a foundational paradigm for overcoming these computational and scale-bridging challenges. We categorize current advances into three key functional roles. First, data-driven upscaling directly maps pore-scale features to macro-scale effective properties, replacing traditional empirical homogenization. Second, deep surrogate models mimic high-fidelity THMC simulations at a fraction of the computational cost, enabling real-time prediction and uncertainty quantification. Third, physics-informed digital twins integrate real-time sensor streams with cloud architectures for dynamic reservoir management. Furthermore, we address the generalization limits of purely data-driven approaches, highlighting physics-informed machine learning (PIML) and hybrid architectures that embed conservation laws as strict constraints. Finally, we outline future pathways toward multimodal data fusion and edge-cloud deployment, marking a shift from static offline modeling to dynamic, physics-safeguarded real-time reservoir optimization. Full article

Per- and polyfluoroalkyl substances (PFASs) are persistent, surface-active contaminants for which soil represents the largest terrestrial reservoir. This review synthesizes a rapidly expanding but fragmented body of literature in order to reframe PFAS not merely as a groundwater transport problem but as a systemic stressor of soil health, drawing together their reported effects on the chemical, physical and biological properties of soils and giving particular attention to the calcareous, alkaline, carbon-poor and seasonally dry soils of the Mediterranean. The reviewed evidence suggests that, chemically, PFASs perturb the coupled carbon and nitrogen cycles rather than the bulk soil reaction, transiently stimulating and then depressing organic carbon turnover, drawing down the dissolved organic carbon pool and disturbing nitrification, while their retention and bioavailability are governed chiefly by organic carbon, chain length and pH. Physically, the surfactant character that defines these molecules lowers the surface tension of soil water and concentrates PFASs at the air–water interface, so that in unsaturated and drought-prone soils much of the burden is retained and then released episodically, most clearly on rewetting after dry periods. Biologically, the literature consistently reports dose-dependent declines in microbial viability, diversity and enzyme activity, alongside toxicity to earthworms and other soil fauna, with sensitivity strongly modulated by soil texture and organic matter. Across all three domains, the Mediterranean emerges as both potentially vulnerable and conspicuously understudied, the available data being clustered in a few western countries and effectively absent for much of the eastern and southern basin, so that the regional assessment offered here rests largely on mechanistic inference rather than on direct observation. The review argues that these coupled mechanistic and geographic gaps define an urgent, region-specific research agenda for the protection of soil health. Full article

Large-scale and long-term hydrogen storage is a key requirement for a sustainable hydrogen-based energy system. Although underground hydrogen storage (UHS) in porous media has gained increasing attention, the behavior of hydrogen during cyclic injection and withdrawal remains poorly understood. This study experimentally investigates the effects of cyclic hydrogen injection cycles (3, 6, 9, and 12 cycles) on the physical and mechanical properties of both dry and brine-saturated Berea, which serves as a representative reservoir rock. Porosity, permeability, and mineral composition of the samples were measured before and after the injection cycles, while triaxial tests were conducted post-injection and compared with reference sister samples. Results show negligible and inconsistent mineralogical changes before and after hydrogen injection. Porosity remained nearly constant (<2 percentage variation), whereas permeability declined by more than 20% in samples, which can impact recovery efficiency. Mechanical properties remained largely unchanged, indicating stability. However, further experimental and modeling studies are required to better understand the observed permeability reduction and its implications for underground hydrogen storage (UHS). Full article

High-volume, long-duration flowback in ultra-deep fractured wells couples pressure, rate, water production, fracture conductivity, and stress-sensitive reservoir properties, making it difficult for pressure transient analysis (PTA), flowing material balance (FMB), and rate transient analysis (RTA) to maintain parameter continuity across flowback stages. This study proposes a physics-constrained artificial-intelligence (AI)-assisted workflow centered on FMB. PTA provides permeability, fracture half-length, and fracture-conductivity priors; RTA, Blasingame, and Agarwal–Gardnerdiagnostics provide production-dynamic constraints; and machine-learning models perform anomaly screening, stage recognition, time-series correction, type-curve discrimination, and multi-method fusion. The workflow was applied to Well Baitan 1, an ultra-deep fractured gas well with eight-stage fracturing and multi-regime flowback data. Isolation forest preprocessing removed 32 abnormal records, random forest (RF) drainage-type classification reached 93% accuracy, and long short-term memory (LSTM) correction improved production-forecast fitting from 87% to 95%. Neural-network fusion yielded matrix permeability of 0.49 mD and dynamic reserves of 1.93 × 10⁴ m³, reducing static geological-volume validation error to 2.8%. The results show that AI improves productivity evaluation when constrained by diagnostic flow models and geological validation, providing a traceable basis for optimizing flowback intensity, monitoring frequency, and stabilized deliverability estimation. Full article

The Block MZ features tight reservoir physical properties and poor interlayer connectivity, making conventional injection-production patterns ineffective for formation energy supplementation. Although high initial production can be achieved after fracturing, stable production is difficult to maintain, resulting in a low ultimate recovery factor. To improve reserve utilization, two rounds of well pattern infilling and well adjustment have been implemented in the block, reducing the well spacing from the original 400 m to less than 50 m. The reservoir development has experienced three stages: depletion development, water huff and puff, and water flooding combined with fracturing. Nevertheless, the current recovery degree remains only approximately 7.0%. No obvious high-pressure main fractures are identified during the drilling, logging, and fracturing operations of infill wells, indicating that a large amount of remaining oil within the well spacing of 50–100 m has not been effectively produced. To further enhance the recovery factor and remaining oil producing degree of the mature tight oil reservoir in Block MZ, a novel combined fracturing technology dominated by pre-CO₂ injection, temporary plugging and diversion, and volume fracturing is innovatively proposed with the well group taken as the overall production enhancement unit. This technology effectively improves fracture complexity and expands the CO₂ sweep volume. Field application results demonstrate that the proposed technology can not only boost the production of a single well but also realize collaborative production enhancement of the entire well group. Compared with the conventional volume fracturing adopted in the early stage, the effective influencing radius of the well group is expanded from 50–150 m to 200–350 m, and the number of affected wells increases from 4 to 6–7. The average daily oil increment per well in the initial 90 days rises from 2.4 t/d to 8.1 t/d, and the average cumulative oil increment per well during the natural flow stage increases significantly from 67 t to 692 t. The remarkable production enhancement effect provides a novel technical approach for EOR (enhanced oil recovery) in mature tight oil blocks. Full article

Turbidite sandstones of the Chang 6 member and delta-front sandstones of the Chang 8 member in the Yuele Block, southwestern Yishan Slope, Ordos Basin, serve as the primary tight oil reservoirs. In this study, a total of 243 continuous core samples from multiple wells were collected for integrated analyses, including cast thin-section observation, scanning electron microscopy (SEM), X-ray diffraction (XRD) of clay minerals, routine core physical property measurements and mercury intrusion porosimetry (MIP), to systematically compare sedimentary–diagenetic disparities between semi-deep lacustrine turbidites (Chang 6) and delta-front sandstones (Chang 8). Measured data indicate that the two intervals have similar average porosities of 9.27% and 9.88%, while their respective geometric mean permeabilities differ markedly, with values of only 0.142 × 10⁻³ μm² for Chang 6 and 0.260 × 10⁻³ μm² for Chang 8. Micro-pore-throat size and connectivity dominate reservoir fluid flow capacity, and total porosity alone cannot objectively evaluate reservoir quality. Delta-front sandstones of the Chang 8 member are supplied by a proximal magmatic-rich provenance from the southwest, and widespread grain-coating chlorite forms during early diagenesis, effectively mitigating compaction damage and inhibiting quartz overgrowth, leading to well-preserved primary pores. As mixed-provenance deposits lacking protective chlorite rims, Chang 6 turbidites experience more intensive compaction, and abundant fibrous illite and carbonate cements precipitate in the subsequent diagenetic stage to fill and separate pore throats, forming an isolated micropore network. Quantitative comparison with baseline parameters of the Longdong region reveals that the Yuele Block is located closer to the southwestern sediment source, resulting in higher contents of magmatic lithics and chlorite in Chang 8 as well as elevated illite concentrations in Chang 6 relative to regional averages, which verifies that source-to-sink transport distance regulates reservoir quality by driving the differentiation of clay mineral assemblages. A complete quantitative coupling sequence of “provenance supply–authigenic clay mineral-pore evolution” is defined herein, and two distinct sedimentary–diagenetic evolutionary routes are classified: high-quality delta-front reservoirs protected by grain-coating chlorite, and low-quality turbidite reservoirs blocked by illite–carbonate cements. This research refines the diagenetic differentiation rules for continental tight sandstones with diverse sedimentary origins in the Ordos Basin and provides quantitative mineralogical criteria for identifying tight oil sweet spots in proximal provenance blocks. Full article

The Taiyuan Formation in the Daniudi Gas Field of the Ordos Basin was formed in a tidal flat mixed sedimentary environment. It represents a typical tight sandstone reservoir with significant exploration and development potential. However, current research on the reservoir evaluation of the Taiyuan Formation is relatively limited. This study focuses on the Taiyuan Formation in the Da 17 well area of the Daniudi Gas Field, employing methods such as petrographic analysis, X-ray diffraction, porosity/permeability measurements, mercury injection capillary pressure, and scanning electron microscopy to conduct a detailed investigation of sand dams in the tidal flat environment. By combining reservoir characteristics with detailed sedimentary microfacies classification, and on the basis of discussing the relationship between reservoir heterogeneity and natural gas production capacity, this study performs reservoir classification and evaluation. The characteristics and distribution patterns of relatively high-quality reservoirs are clarified. Through the analysis of lithological characteristics and sedimentary markers, it is determined that the Taiyuan Formation in the Da 17 well area represents a typical tidal flat sedimentary environment, with sand dams serving as the primary development sites for sand bodies. The Taiyuan Formation sandstone is mainly composed of medium- to fine-grained lithic quartz sandstone and lithic sandstone. The predominant pore types include primary pores, secondary pores, and fractures. The porosity of the reservoir ranges from 0.3% to 14.2%, while the permeability varies from 0.006 to 29.7 × 10⁻³ μm², classifying it as a typical tight sandstone reservoir. Using the gas testing method, the lower limit of the physical properties of the Taiyuan Formation reservoir has been determined to be 3.9%. Considering the heterogeneity characteristics and productivity information of the sand layers, the reservoirs of the Taiyuan Formation are classified into three types: Type I reservoirs are predominantly composed of pebbly coarse sandstone and coarse sandstone, with porosity > 10%, permeability > 0.8 × 10⁻³ μm², mainly developed in the center of sand dams, exhibiting medium heterogeneity; Type II reservoirs consist of coarse sandstone with porosity ranging from 4% to 10% and permeability from 0.1 to 0.8 × 10⁻³ μm², with the main body of the sand dams belonging to this reservoir type, also showing medium heterogeneity; Type III reservoirs are composed of medium to fine sandstone, with porosity < 4% and permeability < 0.1 × 10⁻³ μm², mainly developed at the edges of sand dams, exhibiting strong heterogeneity. By integrating the distribution characteristics of sedimentary facies sand bodies, the planar distribution characteristics of the various reservoir types are clarified. Full article

Understanding how liquid hydrocarbons flow through nanoporous shale matrices is essential for predicting shale oil productivity and evaluating unconventional resources. Despite substantial advances in geological and geochemical characterization, the physical and chemical mechanisms governing oil mobility in tight shale media remain incompletely constrained. This knowledge gap has become particularly evident through an anomalous phenomenon: the prolific production of low-volatile black oil from low- to medium-maturity, extremely tight shale reservoirs, where such viscous oils were previously expected to exhibit limited mobility. This unexpected behavior challenges existing physical models of oil flow. In this Perspective, we revisit the key controls on oil mobility by integrating available geological, geochemical, and reservoir evidence, including the influence of lithofacies on pore systems, the effects of thermal maturity and organic matter on fluid properties, the mechanisms of overpressure generation, and the interactions between hydrocarbons and shale matrices. We particularly emphasize the physical–chemical interaction processes between hydrocarbons and shale matrices, which have been largely overlooked in previous models. Based on these analyses, we propose a conceptual cross-scale migration–accumulation framework for shale oil and discuss its implications using representative shale systems from North America and China. The available evidence indicates that oil mobility is jointly controlled by mineral composition, pore structure, pressure coefficients, hydrocarbon physical–chemical properties, and hydrocarbon–matrix coupling. Thermal maturity emerges as a key parameter because it modulates several of these controls and therefore affects effective oil flow. Despite regional differences, broadly comparable controls may operate across different shale systems. Laminated carbonate-rich shales deposited under saline conditions exhibit high oil mobility even at low maturity, whereas clay-rich freshwater lacustrine shales require higher maturity to achieve comparable flow. The proposed framework links pore-scale processes with reservoir- and basin-scale accumulation and may provide a conceptual basis for evaluating movable oil resource potential in different shale systems. Full article

Fractal analysis has been widely applied to characterize the complexity of pore systems in tight sandstone reservoirs. However, fractal parameters derived from different experimental techniques are frequently interpreted without sufficient consideration of their distinct physical meanings. In this study, tight sandstones from the Fuyu Formation in the Songliao Basin were investigated using cast thin sections, scanning electron microscopy, high–pressure mercury intrusion porosimetry, and nuclear magnetic resonance. The objective was to establish a comparative interpretation framework that distinguishes capillary–pressure–controlled geometric fractal dimensions from NMR–derived apparent relaxation–response fractal parameters (ARR fractal parameters). The pore–throat system is dominated by medium– to fine–sized throats, with the dominant pore–throat radii concentrated between 0.05 and 0.15 μm. Mercury–intrusion–derived fractal parameters primarily characterize the geometric heterogeneity of relatively large and fine pore–throat systems, whereas NMR–derived parameters mainly reflect the apparent relaxation response associated with pore–scale fluid occurrence rather than strict geometric complexity. In the present MICP–NMR subset, comparative regression trends indicate that the geometric fractal parameter representing fine pore throats is more responsive to median pore–throat radius and movable–fluid saturation, whereas the NMR–derived apparent relaxation–response parameter associated with longer relaxation times shows a relatively closer relationship with log–transformed permeability. These relationships should be regarded as exploratory response trends rather than universal predictive models. These findings demonstrate that the two types of fractal parameters provide complementary rather than interchangeable information for reservoir evaluation. The proposed comparative framework offers a physically constrained basis for integrating pore–throat geometry, relaxation response, fluid occurrence, and seepage properties in the characterization of tight sandstone reservoirs. Full article

Coal-measure gas co-production is a critical strategy for enhancing the single-well productivity of unconventional natural gas. However, the pronounced vertical heterogeneity and complex combinations of co-existing reservoirs create substantial asynchronous propagation behaviors during hydraulic fracturing, fundamentally limiting the accurate prediction of multi-reservoir stimulation outcomes. This study employs numerical simulation to investigate fracture development, using the reservoir combinations of the Linxing area on the northeastern margin of the Ordos Basin as a geological model. Our results show that the thickness ratio and mechanical properties of individual rock layers are primary controls on fracture propagation. Specifically, a higher coal seam thickness ratio reduces fracture half-length but increases width, while a greater sandstone layer thickness ratio decreases width and increases height. We further propose the novel concept of the fracture propagation coefficient to characterize the heterogeneity of the fracturing process. It is found that fracture development is closely related to the distance from the injection point, the physical properties of rock layers, and the mechanical property differences between adjacent strata. The distribution of fractures is governed by the coupling effect between injection point location and reservoir mechanical properties. The reservoir–fracture response relationships established in this study provide a scientific basis for optimizing reservoir selection and fracturing parameters in coal-measure gas development. Full article

We investigate the dynamics of a driven quantum field coupled to a finite-temperature reservoir. The corresponding master equation is solved using superoperator techniques, yielding an analytical expression for the density operator. To obtain a compact and physically transparent description of the dynamics, we adopt a phase-space representation based on the Husimi Q-function. For an initially coherent state, we derive a closed-form Gaussian expression for the Husimi Q-function whose stationary limit corresponds to a displaced thermal state. This approach also enables an analytical study of quantum-interference dynamics for an initial superposition of coherent states. Furthermore, we derive the corresponding Fokker–Planck equation for the Husimi Q-function and obtain closed-form expressions for relevant statistical quantities, including the mean photon number, the photon-number standard deviation, and the Mandel parameter. We also investigate the Wehrl and linear entropies, which quantify the loss of phase-space information and purity induced by the thermal environment. The framework provides a complete analytical characterization of the phase-space dynamics, photon statistics, and entropic properties of driven–dissipative quantum fields while avoiding the explicit manipulation of the density operator. Full article

Exploration of ultra-deep tight sandstones in the Silurian Lower Kepingtage Formation, Tarim Basin, is hindered by low success rates. Here, we integrated 3D seismic, core, and petrographic data to investigate reservoir characteristics and fault controls on hydrocarbon accumulation. The formation was characterized by low porosity (3–9%) and permeability (0.01–1.1 mD), with residual intergranular and dissolution pores as primary storage. Strike–slip faults exhibited distinct Riedel shear segmentation—extensional, translational, and compressional—resulting in variable vertical connectivity. Comparative analysis of Wells W3 and W5 revealed that reservoir physical properties, rather than structural location or fault proximity, dominate accumulation outcomes. Specifically, Well W5 achieved high production on a slope due to superior reservoir quality, whereas structurally high Well W3 failed due to poor physical properties. We propose a paradigm shift from targeting “structural highs” to identifying “high-quality sandy bodies” at the intersection of fault conduits and favorable lithologies. This study provides a robust theoretical basis for ultra-deep tight oil and gas exploration. Full article

China hosts abundant coal-rock gas (CRG) resources, which have become a critical unconventional natural gas contributor to national reserve expansion and production increment. Supercritical carbon dioxide (ScCO₂) fracturing is recognized as a green and efficient stimulation technology, exhibiting great potential for high-efficiency CRG exploitation. To clarify the effects and intrinsic mechanisms of ScCO₂ treatment on coal fracture initiation, propagation, and CRG recovery enhancement, true triaxial fracturing and CO₂-CH₄ displacement experiments were performed in combination with multiple microscopic characterization methods, including X-ray diffraction (XRD), Fourier-transform infrared spectroscopy (FTIR), and Scanning electron microscopy (SEM). The multi-scale experimental investigation systematically revealed the fracture development mechanism, permeability variation characteristics, and microstructural evolution of coal reservoirs under ScCO₂ interactions. The results indicate that ScCO₂ fracturing significantly lowers the coal fracture initiation threshold compared with conventional hydraulic fracturing, with the breakdown pressure reduced by 26.2% and the initiation time shortened by 37.5%. Such advantages facilitate coal fracture activation and the development of complex fracture networks. Long-term ScCO₂ soaking induces the dissolution of inorganic minerals (e.g., calcite, plagioclase, and clay minerals) and the extraction of inherent organic matter within coal matrices. The coupled hydro-chemical reactions reconstruct the coal pore structure, enlarge pore throats, and improve reservoir permeability, achieving a maximum permeability enhancement of approximately 1.6 times. Meanwhile, ScCO₂ displacement yields a prominent CRG recovery performance, with an ultimate gas recovery factor up to 93.85%. The CRG enhancement mechanism of ScCO₂ fracturing is comprehensively attributed to three core coupled effects. First, ScCO₂ dynamic fracturing generates intricate fracture networks, which greatly optimize reservoir seepage channels and flow space. Second, the ScCO₂–formation water–coal interaction modifies coal physical properties via mineral dissolution and organic matter extraction, thereby improving reservoir permeability. Third, the preferential adsorption of CO₂ over CH₄ triggers effective competitive adsorption and gas displacement, further promoting adsorbed methane desorption and elevating CRG recovery efficiency. This study provides a solid theoretical foundation for the field application of ScCO₂ fracturing technology and offers valuable insights into the green, efficient, and sustainable development of deep coal-rock gas resources. Full article