Search Results (705)

The widely applied empirical Darcy’s law in geotechnical engineering faces significant challenges in describing low-velocity flow processes in low-permeability porous media such as tight sandstones containing irreducible water. A deep understanding of low-velocity non-Darcy two-phase flow behavior in low-permeability porous media is essential for evaluating the development of ultra-low-permeability reservoirs. In this study, seven low-permeability three-dimensional digital cores with distinct pore structures were constructed based on realistic ultra-low-permeability sandstones. Using the lattice Boltzmann method, pore-scale investigations of water displacing oil were conducted. Low-velocity two-phase flow behavior under varying wettability conditions, pore structures, and fluid viscosities was simulated. The underlying mechanisms of low-velocity non-Darcy flow in ultra-low-permeability sandstones were examined, leading to a modified low-velocity non-Darcy flow equation. This improved model was subsequently applied to numerical simulations of ultra-low-permeability reservoirs. The results demonstrate that non-Darcy effects manifest primarily as nonlinearities in seepage curves, representing a marked departure from conventional Darcy’s law. Low-velocity non-Darcy (LVND) flow is predominantly constrained by the influence of complex pore-throat structures and capillary forces on fluid distribution. The dynamic equilibrium among capillary forces arising from residual water saturation, viscous forces, and pressure gradients constitutes the fundamental mechanism governing the onset of LVND flow. Enhanced nonlinear behavior is observed with increasing viscosity of the invading phase and elevated capillary forces. Substantial discrepancies in reservoir production dynamics are identified between LVND and classical Darcian regimes. Through pore-scale numerical simulations, this study systematically elucidates LVND behavior during bi-phasic flow in low-permeability porous media, while identifying critical controlling factors. These findings provide scientific rationale and technical support for addressing geological engineering challenges in tight sandstone formations. Full article

A large number of low-resistivity and low-permeability reservoirs have been discovered in the deep Paleogene strata of the Wenchang Sag. These reservoirs are characterized by complex porosity–permeability relationships and difficulties in fluid property identification, which restrict the progress of exploration and development operations. However, existing reservoir studies mostly focus on either low-permeability or low-resistivity reservoirs, with relatively few investigations targeting this specific type. Using petrological analysis and physical property testing as the main methods, combined with sedimentary and diagenetic studies, this paper examines the characteristics and genesis of low-resistivity and low-permeability reservoirs in the Paleogene of the Wenchang Sag. The results show that the Paleogene reservoirs are dominated by lithic quartz sandstones, with secondary pores as the main reservoir space, consisting of medium–small pores and fine throats. Samples of the same grain size exhibit a favorable porosity–permeability correlation. Based on capillary pressure curve morphology, the reservoirs can be classified into three types: high mercury intrusion saturation with low displacement pressure, medium mercury intrusion saturation with medium displacement pressure, and medium mercury intrusion saturation with medium–high displacement pressure. The low porosity and permeability are mainly attributed to the fact that the reservoir rocks are primarily deposited in near-source braided fluvial delta underwater distributary channels, resulting in low compositional and textural maturity of sandstones. Strong compaction resistance leads to a significant reduction in primary pores during burial, and intergranular cement filling further deteriorates physical properties. On the other hand, rapid lithological changes and complex pore structures give rise to abundant isolated pores and poor connectivity, leading to high irreducible water saturation. Coupled with high formation water salinity, these factors collectively give rise to low-resistivity reservoirs in the study area. This study clarifies the formation mechanism of low-permeability and low-resistivity reservoirs in the Paleogene of the Wenchang Sag, providing guidance for reservoir evaluation in subsequent oil and gas exploration and serving as a reference for analogous areas. Full article

While CO₂ huff-n-puff (CO₂ HnP) is a promising technique for shale oil recovery, the characteristics and controlling factors of microscopically movable oil in lacustrine argillaceous-rich shales remain poorly understood. Shale samples from the Qingshankou Formation in the Songliao Basin were collected, and a series of experiments, including low-pressure N₂ adsorption, mercury injection porosimetry, and nuclear magnetic resonance, were conducted. High-pressure and high-temperature CO₂ HnP experiments were then conducted to investigate the effects of cycle number, soaking time and changes in pore structure on movable oil distribution. The shales exhibit multi-scale pores and lamellar fractures containing substantial residual oil (41.33–52.16% saturation). CO₂ HnP effectively mobilizes oil from macropores (50–1000 nm) and fractures (>1000 nm), with a limited effect in micro–mesopores (<50 nm). Three CO₂ HnP cycles were optimal for movable oil extraction. Extending the soaking time increased movable oil by ~4%, primarily from macropores and fractures (5.59–6.05%), with minimal improvement in smaller pores. A combination of CO₂ flooding followed by CO₂ HnP increased total movable oil by 4.83–7.26%, significantly enhancing recovery from micropores (7.26%) and macropores (9.21%). This study clarifies the pore size distribution and mobilization constraints of movable oil in argillaceous-rich shales. The integrated CO₂ flooding and HnP strategy proves to be highly effective, especially for movable oil in micro–mesopores. This study is the first to investigate pore-scale movable oil in lacustrine argillaceous-rich shales during CO₂ huff-n-puff under in situ reservoir conditions, and could provide critical insights for optimizing shale oil recovery in the Songliao Basin and similar lacustrine reservoirs. Full article

This study develops a fully coupled thermo–hydro–mechanical (THM) finite-element model to investigate fracture-induced fluid loss in depleted formations. To address the issue of assuming a homogeneous, unfractured medium, this approach incorporates the effects of pre-existing or induced fractures. By integrating thermoelastic stresses, fluid flow, and transient heat transfer, the model provides a more accurate simulation of coupled interactions, enabling a deeper understanding of stress evolution and fracture aperture behavior under temperature variations. The results show that pressure depletion reduces horizontal principal stresses in an approximately linear manner, with the minimum horizontal stress being more sensitive. The influence of wellbore pressure is concentrated in the near-wellbore region (r/rw < 2), where it increases circumferential stress at low azimuths and exhibits an almost linear positive correlation with fracture aperture. Fracture length has a negligible effect on pore-pressure variations (≤0.19 MPa) but increases circumferential stress at high azimuths and enlarges the aperture near the wellbore. Temperature effects, through thermoelastic stresses, dominate local stress redistribution, with the 90° azimuth showing the strongest sensitivity. Higher injection temperatures increase circumferential and radial stresses while decreasing near-wellbore aperture, whereas lower temperatures produce the opposite response. Although temperature differences cause only minor changes in pore pressure and far-field stresses, they exert first-order control on near-wellbore width evolution and the likelihood of lost circulation. These findings indicate that coordinated optimization of wellbore pressure, fracture dimensions, and injection temperature under depletion conditions is important for mitigating fracture-induced fluid loss and improving drilling safety and efficiency. Full article

Permeability evolution in hydrate-bearing porous media is a key factor controlling gas production efficiency during natural gas hydrate exploitation. In this study, laboratory experiments were conducted using sand-packed tubes filled with quartz sand and glass beads to systematically investigate the variation of liquid-phase permeability with hydrate saturation. The effects of pore structure, particle size, and initial gas injection pressure on hydrate formation and permeability reduction were analyzed. Furthermore, experimental results were compared with four commonly used permeability models, including the Kozeny model, the Dai model, the Masuda model, and the parallel capillary model. The results show that permeability decreases continuously with increasing hydrate saturation in both porous media, and the most rapid decline occurs at low saturation levels between 0 and 9%. Under the same conditions of 20–40 mesh and an initial pressure of 6.0 MPa, the pressure drop rate in the quartz-sand-packed tube reaches 1.062 kPa per minute, which is about 2.35 times higher than the 0.451 kPa per minute observed in the glass-bead-packed tube, indicating a faster hydrate formation rate and stronger permeability reduction in quartz sand. In addition, both increasing particle mesh size and raising the initial gas injection pressure significantly promote methane consumption and hydrate formation. Model comparison results demonstrate that permeability reduction is strongly dependent on pore structure. The Kozeny pore-filling model, the Dai model (M = 3), and the Masuda model (N = 8) show good agreement with the glass-bead data, whereas the Dai model (M = 8), the Masuda model (N = 15), and the pore-center form of the parallel capillary model better describe the quartz-sand system. In contrast, models based on particle-surface coating show poor agreement in both media. These findings indicate that permeability reduction is primarily controlled by pore-space occupation and flow-path restriction rather than uniform surface coverage. The results suggest that hydrate growth is more likely to occur in pore centers and critical pore-throat regions, although this conclusion is based on macroscopic model comparison and requires further validation by pore-scale observations. This study provides a quantitative basis for model selection and improves the understanding of permeability evolution in hydrate-bearing porous media. Full article

Accurate prediction of formation pore pressure is of great significance for drilling safety, the efficient development of oil and gas resources, and engineering risk control. Traditional methods based on empirical parameters or mechanical models are difficult to fully adapt to complex geological conditions. Although intelligent models have strong nonlinear modeling capabilities, they are highly dependent on large-scale and high-quality training data, and tend to suffer from poor generalization ability and insufficient adaptability in blocks with limited samples or significant differences in geological characteristics. To improve the adaptability of the model between different blocks, this study introduces a heterogeneous transfer learning method to construct a formation pore pressure prediction model suitable for scenarios with inconsistent feature spaces. This method can effectively transfer knowledge from the source domain to the target domain, alleviating the prediction difficulties caused by differences in data distribution. Experimental results show that the proposed method still maintains excellent prediction accuracy and stability under the conditions of limited training samples and complex geological conditions, and has better generalization ability and cross-block applicability compared with traditional models. Full article

This study investigates the heterogeneity of pore structures in lacustrine shale gas reservoirs, with a specific focus on shales from the Lower Cretaceous Shahezi Formation in the Lishu Fault Sag of the Songliao Basin. By integrating multi-scale characterization techniques—including high-pressure mercury intrusion, N₂/CO₂ adsorption, and nuclear magnetic resonance (NMR)—we examined the pore networks across five identified lithofacies: organic-rich clayey shale, organic-rich mixed shale, organic-rich siliceous shale, organic clayey shale, and organic mixed shale. The results indicate that mesopores (2–50 nm) constitute the dominant fraction of pore volume (31.7%–56.6%), followed by micropores (<2 nm) and macropores (>10 μm). Notable lithofacies-dependent variations were observed: organic-rich clayey shale exhibits abundant organic pores, clay interlayer pores, and intragranular dissolution pores with favorable connectivity; organic-rich siliceous shale is mainly dominated by inorganic pores with limited organic porosity; mixed shales are characterized by clay mineral contraction fractures and intergranular pores. The key controlling factors are mineral composition and organic matter abundance: clay content shows a positive correlation with pore volume and surface area in organic-rich clayey shale, but a negative correlation in organic mixed shale. Brittle minerals (quartz and feldspar) generally reduce porosity through compaction. Total organic carbon (TOC) displays a weak positive correlation with mesopore volume, while thermal maturity (Ro = 1.2%–1.73%) exerts influences that vary by lithofacies. In contrast to marine shales—which are dominated by high-maturity (Ro > 2.0%) organic pores and quartz-supported frameworks—terrestrial shales primarily rely on inorganic pores derived from clay minerals (e.g., illite). This study clarifies the relationships among lithofacies, pore structure, and controlling factors, thereby providing a basis for evaluating the gas potential of terrestrial shales. Full article

Pore structure and multifractal characteristics are two critical indicators for evaluating the heterogeneity of tight sandstone reservoirs. An integrated analysis comprising physical property tests, X-ray diffraction, casting thin sections, scanning electron microscopy, high-pressure mercury intrusion (HPMI), and constant-rate mercury intrusion (CRMI) is conducted on five samples from the Jurassic Sangonghe Formation in the northern Turpan-Hami Basin to investigate the full-scale pore size distribution (FPSD) and its multifractal characteristics. The results indicate that the pores in tight sandstone are mainly residual intergranular pores, dissolution pores, intercrystalline pores, and microfractures. The FPSD exhibits a bimodal or trimodal pattern, with dominant pore sizes ranging from 0.00516 μm to 1.15 $\mathsf{\mu }\mathrm{m}$. Two key multifractal parameters, the multifractal dimension range ($D_{min}-D_{max}$) and the relative dispersion ($R_d$), were utilized to effectively characterize pore structure heterogeneity and asymmetry. Higher $D_{min}-D_{max}$ values correspond to stronger heterogeneity, whereas lower $R_d$ values indicate a dominance of nanoscale pores. Furthermore, $D_{min}-D_{max}$ and $R_d$ exhibit negative correlations with permeability and clay mineral content, and positive correlations with feldspar content. This study demonstrates the utility of FPSD in characterizing pore structure and highlights the applicability of multifractal theory in assessing the heterogeneity of tight sandstone reservoirs. Full article

Managed pressure drilling (MPD) is the core technology for developing formations with high pressure and narrow density windows. It precisely maintains the bottomhole pressure (BHP) within the safe operating window defined by formation pore pressure and fracture pressure by actively regulating the wellbore pressure profile. If pressure control becomes unstable, it can easily trigger gas kicks or lost circulation, posing a severe threat to operational safety. However, existing model predictive control (MPC) schemes have significant limitations: pure data-driven models exhibit poor generalization under complex conditions, while control algorithms based on traditional mechanistic models struggle to meet the stringent real-time requirements of field control cycles due to high-complexity numerical iteration processes. To balance control precision and real-time performance, this paper proposes a physics-informed model predictive control framework (PINC-MPC). During the training phase, physical prior knowledge such as the law of mass conservation is embedded into the neural network as constraints to construct a physically consistent deep surrogate model, enabling it to characterize complex wellbore characteristics. In the control phase, this surrogate model replaces the time-consuming numerical solving process of the mechanistic model within the MPC loop, achieving near-real-time state prediction and rolling optimization while ensuring physical fidelity. Experimental results indicate that PINC-MPC demonstrates superior control performance. Its median single-step solving time is only 16.81 ms, achieving an 11.1-fold acceleration compared to the mechanistic model-based scheme (187.3 ms). In a 5000 s full-cycle closed-loop control experiment, the total time required for the former is only 1.68 s, while the latter reaches 18.73 s, representing an efficiency improvement of approximately 91%. In terms of control accuracy, the integrated absolute error (IAE), reflecting the total deviation of the control process, significantly decreased from 63.40 MPa·s for the industrial successive linearization MPC (SLMPC) to 12.90 MPa·s, an improvement of 79.7%. Especially in extreme dynamic conditions such as simulated pump shutdowns for pipe connections and sudden gas kicks, the framework demonstrates excellent predictive ability and response efficiency. It can proactively trigger compensation actions to keep BHP fluctuations within 0.30 MPa, significantly outperforming the traditional SLMPC method. The research results prove that PINC-MPC provides an efficient, precise, and robust nonlinear control strategy for MPD systems, offering important engineering reference value for enhancing the automation level of intelligent drilling systems. Full article

In response to the significant challenges posed by ice accumulation and contamination from various fluids in complex operating conditions for metallic materials, this study utilises picosecond laser precision machining to develop a ‘slippery surface’ featuring a micro-channel network structure. The core innovation of this study lies in the use of laser-machined micrometre-scale array textures to overcome the limitations of traditional isolated pores. These globally interconnected micro-channels serve as highly efficient reservoirs and dynamic transport channels for lubricants, significantly enhancing the interfacial capillary locking force of the lubricant. Experimental results demonstrate that this unique network geometry endows the surface with exceptional fluid replenishment and self-healing properties, enabling it to exhibit outstanding broad-spectrum hydrophobicity towards various fluids—including water, crude oil and ethanol (surface tension range: 17.9–72.0 mN m⁻¹)—with sliding angles consistently below 12°, whilst effectively slowing the dehydration and solidification processes of biological fluids. At a low temperature of −15 °C, the surface achieved an ice formation delay of up to 286 s, with an ice adhesion strength of only 33.9 kPa, ensuring that accumulated ice could be spontaneously detached under minimal external force. Furthermore, the micro-channel network structure serves as a key protective mechanism against mechanical wear, maintaining robust slippery properties even after three hours of high-pressure water jet scouring (Weber number of 300). This reliable interface, achieved through structural management, provides an efficient and scalable platform for addressing the all-weather anti-icing and antifouling requirements of outdoor infrastructure. Full article

In karst tunnel engineering, water-filled cavities located above the tunnel crown, under the combined effects of excavation disturbance and hydraulic pressure, are prone to triggering water and mud inrush disasters. The thickness of the water-resisting rock layer is therefore a key factor controlling the stability of the surrounding rock. To address the difficulty in accurately characterizing the mechanical behavior of the crown of horseshoe-shaped tunnels using conventional circular plate or beam models, this study innovatively develops an explicit analytical model for the minimum safe thickness of the water-resisting rock layer based on clamped elliptical thin plate theory and Kirchhoff plate theory, incorporating the influence of cross-sectional geometry. Parametric sensitivity analysis indicates that both karst water pressure and tunnel crown height significantly amplify the required minimum safe thickness, whereas an increase in the tensile strength of the surrounding rock effectively reduces the thickness demand. Specifically, when the karst water pressure increases from 2.5 MPa to 4.5 MPa, the minimum safe thickness rises from 7.5 m to 10.0 m, showing an approximately linear growth trend. The analytical model is further validated through numerical simulations under different “water pressure–thickness” conditions. The results demonstrate that at the calculated recommended thickness, the surrounding rock achieves stable convergence after excavation. High tensile stress and elevated pore pressure zones are mainly concentrated near the tunnel crown, without the formation of through-going tensile failure. Engineering application indicates that the proposed model can provide a quantitative basis for the design of water-resisting rock layer thickness and the assessment of water inrush risk in karst tunnels. Full article

Recent deep exploration in the northern Sichuan Basin has advanced our understanding of Lower Cambrian Canglangpu Formation carbonate reservoirs. However, the characteristics, genesis, and distribution of the reservoir, as well as future exploration targets, remain unclear. Specifically, core and thin-section analyses indicate that these reservoirs are notably tight, with virtually no visible macroporosity and low permeability (0.01–1 mD). However, helium porosity measurements reveal values of 2–5%, suggesting significant storage potential. An integrated approach utilizing optical and scanning electron microscopy (SEM), high-pressure mercury injection capillary pressure (MICP), nuclear magnetic resonance (NMR), and micro-computed tomography (micro-CT) was employed to characterize the pore systems. Quantitative thin-section analysis reveals visible areal porosity markedly lower than helium porosity, indicating predominance of micropores; mercury intrusion and NMR demonstrate that intragranular and intergranular micropores constitute most pore volume, although effectively connected throat sizes remain below 1 µm. Comparative stratigraphic evaluations show that porosity is more developed in the dolomite-rich upper and middle intervals of the depositional cycles, whereas the lower intervals are less porous. Early subaerial exposure promoted dolomitization and dissolution, which facilitated pore development. However, the influence of sediment mixing led to a reduction in porosity. And deep burial subjected the rocks to intense compaction and cementation, destroying most of the primary pore space. Consequently, reservoir quality is ultimately governed by the interplay between the original depositional environment and the later diagenetic history, with paleotopographic highs identified as the most promising exploration targets. These findings establish a predictive framework for reservoir quality in tight carbonate rocks, which holds significant implications for analogous plays worldwide. Full article

Both the Lower Silurian Longmaxi Formation and the Upper Permian Dalong Formation shales in southern China are organic-rich with well-developed nanoscale reservoir pores, demonstrating significant shale gas exploration potential. However, the current lack of in-depth research on the differential depositional and reservoir evolution characteristics of these two shale sequences has left the main controlling factors of the reservoirs unclear, thereby constraining breakthroughs in shale gas development. Focusing on the Longmaxi and Dalong formation shales in the Sichuan Basin, this study employed various analytical methods, including major and trace element analyses, X-ray diffraction (XRD), high-pressure mercury intrusion (HPMI), nitrogen adsorption, CO₂ adsorption, and scanning electron microscopy (SEM). Investigations into the depositional paleoenvironment, paleoproductivity, organic matter enrichment, and microscopic difference mechanisms of nanoscale reservoirs reveal that the Longmaxi Formation shale represents a passive continental margin shelf facies. It is characterized by strong terrigenous input, a predominance of quartz and clay minerals, and consists mainly of siliceous and argillaceous shale facies with high organic matter abundance. In contrast, the Dalong Formation shale was deposited in an intra-platform basin under the influence of intra-platform rifting. It features weak terrigenous input, highly reducing conditions, and strong paleoproductivity. Dominated by quartz and carbonate minerals, its lithofacies are primarily siliceous and calcareous shales. Within the Dalong Formation, the diagenetic dissolution of carbonate minerals promotes the development of micrometer-scale pores larger than 100 μm, while the extensive thermal evolution of organic matter fosters the formation of honeycomb- and embayment-like nanoscale micropores and mesopores, rendering it a relatively superior shale reservoir. Ultimately, the high-TOC shales in the lower part of the Longmaxi Formation and the upper part of the Dalong Formation are identified as the primary sweet spot intervals for future shale gas development. Full article

To investigate the seepage and mechanical behavior of the overlying strata during solution mining in salt deposits, porous sandstones with different grain sizes were selected for study. First, a series of microscopic tests, including SEM, MIP, and NMR, was conducted to characterize the pore structure of the rocks. Subsequently, using a servo-controlled triaxial rock testing system, permeability tests covering the complete stress–strain process were performed under different confining pressures and seepage pressures based on the steady-state method, in order to analyze the seepage and mechanical characteristics of the sandstones during deformation and failure. The results indicate that the investigated aquifer sandstones are characterized by weak cementation, high porosity, large pore size, good pore connectivity, and relatively high permeability. High confining pressure enhances the mechanical strength of the sandstone while reducing its permeability, whereas increasing seepage pressure decreases mechanical strength and enhances permeability during triaxial compression under pore water pressure conditions. Throughout the complete stress–strain process, the evolution of permeability is jointly controlled by the intrinsic pore structure of the rock, the stress loading path, and the failure mode. Under high confining pressure, localized compaction bands may develop, and the formation of such localized structures suppresses any increase in permeability. Acoustic emission shows good correlations with both the stress–strain response and permeability evolution. This study provides new insights into the pore structure of loose, highly permeable sandstones and their hydromechanical coupling behavior throughout the complete stress–strain process. Full article

Sulfamethoxazole (SMX) is one of the most frequently detected antibiotics in aquatic environments and is difficult to remove by conventional biological treatment because of its persistence, potential toxicity to microbial communities, and associated risk of antibiotic resistance selection. Aerobic granular sludge membrane bioreactors (AGMBRs), which combine the compact and stratified structure of aerobic granular sludge with membrane-based solid–liquid separation, have emerged as a promising platform for SMX-contaminated wastewater treatment because they provide high biomass retention, decoupled sludge retention time (SRT) and hydraulic retention time (HRT), and stable effluent quality. This review systematically summarizes recent advances in AGMBRs for SMX removal, with emphasis on how operating parameters (e.g., dissolved oxygen, hydraulic retention time, organic loading rate, C/N ratio, and sludge retention time) and membrane-related factors (e.g., membrane flux, aeration-induced shear, membrane type, and pore size) affect treatment performance and process stability. The main SMX attenuation pathways in AGMBRs are discussed from three perspectives: sorption and partitioning within granules and extracellular polymeric substances (EPSs), microbial biodegradation and co-metabolism, and membrane retention that prolongs effective contact time and shapes microbial ecology. Particular attention is given to the dual role of EPS and soluble microbial products (SMPs), which contribute to granule stability and SMX tolerance but also accelerate membrane fouling through cake-layer formation, pore blocking, and transmembrane pressure increase. Current challenges include incomplete understanding of transformation products, ARG- and MGE-related risks, long-term fouling–biodegradation interactions, and the lack of pilot-scale validation. Future research should therefore focus on mechanism clarification, integrated control of removal and fouling, energy-efficient operation, and scale-up of AGMBRs for practical antibiotic wastewater treatment. Full article