Petroleum and Gas Engineering, 2nd edition

Pressure-dependent pore-volume deformation is a critical but poorly constrained variable in dynamic reserve assessment for ultra-deep fractured-vuggy carbonate reservoirs, where fractures, dissolution pores, and vugs respond differently to effective-stress loading. In this work, a pore-structure-aware evaluation strategy was developed by integrating high-temperature and high-pressure volumetric measurements with data-driven regression. Twelve carbonate core plugs from the Ordovician Yijianfang and Yingshan formations of the Fuman Oilfield were selected to represent matrix-pore, dissolution-pore, fracture-vug, and fracture-dominated pore systems. Stepwise net-pressure experiments were performed under simulated reservoir conditions, and pore-volume compressibility (Cp) was calculated from corrected pore-volume changes. Measured C_p values reveal a distinct stress-sensitive response: C_p declines sharply during the low-net-pressure stage and then tends toward a quasi-stable level as net pressure increases, indicating progressive closure of mechanically compliant fractures, narrow throats, and weakly supported dissolution pores. Although porosity is positively associated with Cp, samples with comparable porosity display markedly different compressibility values, confirming that pore-space geometry and fracture-related compliance must be considered. Eight representative regression algorithms were then compared, using net pressure, porosity, permeability, initial pore volume, surface porosity, temperature, and a pore-structure index as model inputs. To further assess model generalization to completely unseen core plugs, additional core-ID-based leave-one-core-out (LOCO) validation was performed for k-nearest neighbors and AdaBoost. Under this grouped validation, k-nearest neighbors yielded an RMSE of 13.5978 × 10⁻⁴ MPa⁻¹ and an R² of 0.8408, whereas AdaBoost achieved an RMSE of 10.0160 × 10⁻⁴ MPa⁻¹ and an R² of 0.9136, indicating greater cross-core robustness of AdaBoost. Permutation-importance analysis of the split-specific KNN model indicated that net pressure, porosity, surface porosity, and pore-structure index made the largest predictive contributions within that model. Moreover, the predicted normalized Cp values reproduced the experimentally observed decreasing trend with increasing net pressure, supporting the physical consistency of the k-nearest neighbors predictions. The proposed experimental–machine learning framework offers a pressure-dependent method for estimating pore-volume compressibility within the geological and petrophysical domain represented by the investigated Fuman Oilfield cores, and provides more representative inputs for material-balance analysis, dynamic reserve evaluation, and production adjustment. Full article

To address whirling- and vibration-induced failures in ultra-deep well drill strings caused by high slenderness ratios and complex loading conditions, this study establishes a nonlinear dynamic finite element model for a steel–titanium alloy composite drill string. The model is discretized with Euler–Bernoulli beam elements and solved using Newmark time integration combined with an iterative node-based spatial solution. Weight on bit, torque, wellbore–wall friction, impact/contact force, and equivalent drilling-fluid damping are considered. The model is used to evaluate how titanium alloy section size, length, wall thickness, and installation position affect whirling, lateral vibration, and torsional vibration. The results show that increasing drill-string diameter reduces the whirling range and lateral vibration intensity; when the diameter exceeds 149.23 mm, wall-impact frequency decreases markedly. Although the titanium alloy section exhibits approximately 60% higher local lateral vibration intensity than the steel section, the upper steel section experiences an approximately 18% reduction in lateral vibration. Installing the titanium alloy section in the middle of the string rather than near the bit reduces the overall lateral vibration intensity by approximately 30% and torsional vibration intensity by approximately 40%. Based on comparative sensitivity analysis, a titanium alloy section length of 1000–2000 m, diameter not less than 139.7 mm, and wall thickness not less than 12.7 mm are recommended for the simulated ultra-deep well conditions. These findings provide quantitative guidance for safer and more stable composite drill-string design. Full article

Molecular dynamics simulations examined the roles of molecular structure, thermodynamic compatibility, intermolecular association, and mixture composition in the supercritical CO₂ extraction of ten crude oil components at 363.15 K and 15 MPa. Single-component extraction ratios ranged from 80.70% for n-hexane to 5.85% for 2-naphthol. Compounds of similar size differed widely, indicating that topology, aromaticity, and polar functional groups were more informative than molecular size alone. CO₂ solubility parameters obtained from MD agreed with estimates derived from NIST data, and δ_CO2 = 7.28ρ_r captured their reduced density dependence over 303.15–363.15 K. Extraction generally decreased with increasing oil–CO₂ solubility parameter difference. In binary systems evaluated using oil boundaries determined by the half density criterion, higher fractions of nonpolar partners were associated with increased total extraction ratios, whereas higher fractions of polar partners were associated with decreases. Multicomponent systems showed redistribution that depended on the overall composition, and relative diffusion coefficients qualitatively reflected mobility differences. The gas–oil interaction competition factor, R_comp, decreased from 1.985 to 0.087 in the same order as the extraction ratios. Both the thermodynamic and energetic correspondences persisted after excluding 2-naphthol. Configurations and radial distribution functions showed that association in nonpolar hydrocarbons was dominated by dispersion interactions, whereas polar and aromatic components exhibited additional hydrogen bonding, aromatic stacking, and dipolar or electrostatic organization. Local CO₂ enrichment near polar sites alone did not explain overall extraction. Overall, the selective transfer of individual components was consistent with a balance between local CO₂–oil association and collective oil–oil cohesion that depended on mixture composition, while molecular organization may regulate the accessibility of favorable CO₂ contact sites. Full article

Methane production from water-bearing coal reservoirs is governed not only by methane adsorption capacity but also by the accessibility of adsorption domains and the efficiency of pore-scale transport during pressure depletion. However, the interfacial mechanism by which coal wettability and water occurrence regulate methane adsorption–desorption reversibility remains insufficiently understood. In this study, three representative Ordos Basin coal samples with different pore structures and surface polarities, denoted as OBC-L, OBC-M, and OBC-H, were investigated to explore the pore-scale mechanisms governing water-mediated methane storage and release rather than to establish basin-wide statistical relationships. A combined experimental workflow involving N₂ adsorption–desorption, FTIR and XPS analyses, contact angle and Zeta potential measurements, low-field NMR, high-pressure methane adsorption–desorption tests, kinetic modeling, hysteresis evaluation, and Pearson correlation analysis was used to clarify the coupling among pore structure, coal–water interfacial properties, water occurrence, methane storage, and methane release. The results show that OBC-H possesses the strongest dry-state methane storage potential, with the BET surface area increasing from 5.82 m²/g for OBC-L to 12.94 m²/g for OBC-H and the fitted Langmuir volume (V_L) reaching 22.3 cm³/g. Nevertheless, OBC-H also shows stronger water affinity, as reflected by an increase in the XPS-derived O/C atomic ratio from 0.118 to 0.186, a decrease in contact angle from 82.6° to 51.8°, and an increase in bound water fraction from 46.3% to 69.4%. With the transition from dry to saturated conditions, the fitted V_L of OBC-H decreases from 22.3 to 15.2 cm³/g, while the Langmuir pressure (P_L) increases from 1.38 to 3.00 MPa, indicating a simultaneous reduction in the model-estimated maximum methane adsorption capacity and apparent methane affinity. More importantly, the desorption results demonstrate that high adsorption capacity does not necessarily correspond to high methane deliverability. For OBC-H, the final desorption efficiency decreases from 79.6% to 54.2%, the effective diffusion coefficient decreases from 2.74 × 10⁻¹¹ to 0.86 × 10⁻¹¹ m²/s, and the hysteresis index increases from 12.8% to 36.4% under saturated water conditions. Correlation analysis further confirms that bound water fraction is positively associated with adsorption–desorption hysteresis but negatively associated with desorption efficiency, desorption rate constant, and effective diffusion coefficient. These findings are consistent with two distinct water-mediated constraints: adsorbed/bound interfacial water contributes to surface-site shielding, whereas capillary and saturated water occupation contributes to pore-throat transport restriction; together, these effects reduce methane release efficiency and enhancing desorption irreversibility. This study provides an interfacial interpretation of methane deliverability based on representative water-bearing coal samples and offers a mechanistic basis for understanding wettability- and water-retention-related transport constraints; broader applicability across the Ordos Basin requires validation using a larger number of samples from different coal seams and reservoir settings. Full article

Accurate oil saturation evaluation is critical for shale oil sweet-spot prediction and reserve assessment, but conventional resistivity-based interpretation is commonly challenged in clay-rich lacustrine shale oil reservoirs. In some favorable shale intervals, high oil-bearing potential is accompanied by low resistivity, which weakens the applicability of Archie-type saturation models and may lead to underestimation of oil saturation. To clarify the origin of this abnormal electrical response and improve saturation interpretation, this study investigates the upper fourth member of the Shahejie Formation in the Boxing Sag, Jiyang Sub-basin. Core description, thin-section observation, XRD mineral composition, porosity, measured oil saturation, TOC, S1 and conventional logging data were integrated to establish a core-calibrated and SOM-based reservoir classification workflow. Using GR, AC, CNL, DEN, Rt and Rs as input curves, the shale oil reservoirs were divided into Type I, Type II and Type III classes. Type I reservoirs exhibit better pore development and hydrocarbon enrichment, with mean porosity, oil saturation, TOC and S1 values of 4.95%, 59.18%, 2.21 wt% and 2.77 mg/g, respectively. However, their mean Rt is only 22.75 Ω·m, much lower than that of Type III reservoirs. This response defines a typical “three-high and one-low” logging pattern, characterized by high GR, high AC, high CNL and low resistivity. The resistivity-reversal behavior is mainly associated with clay-related conduction and relatively higher absolute water content, whereas organic matter and pyrite do not form continuous conductive pathways in the studied interval. Based on this mechanism, a class-dependent electrical–non-electrical log fusion model was developed by combining clay-corrected electrical saturation with neutron–density saturation constraints. Compared with the single electrical model and single non-electrical model, which yield mean absolute errors of 12.65 and 13.84 percentage points, respectively, the proposed fusion model reduces the error to 8.88 percentage points. Application to more than 40 wells identifies the central–western part of the Boxing Sag as the most favorable shale oil sweet-spot area. The cumulative thickness of Type I reservoirs generally exceeds 100 m in this area and locally reaches more than 150 m. The proposed workflow provides a practical method for identifying favorable low-resistivity lacustrine shale oil reservoirs using conventional logging data. Full article

The oilfield gathering and transportation system is an important component of oilfield energy use and therefore provides practical opportunities for supporting the dual-carbon goals through operating-parameter optimization. This study combined field cooling trials on high-water-cut well pipelines, thermal-hydraulic calculations of the downstream gathering network, regression-based surrogate models of the dehydration-station equipment, and coordinated system-level energy accounting. A constraint-based direct-search procedure initialized from the actual field operating condition was used to identify the best feasible operating point within the examined ranges. The search was terminated when a complete update cycle produced no further reduction in energy consumption while all engineering constraints remained satisfied. The field trials showed that the investigated well pipelines could be operated below the corresponding crude-oil pour points under the tested high-water-cut conditions. For the transfer-station-to-central-station stage, the original three-pipe heat-tracing process was adjusted to electric heating and hot-water blending according to the pipeline conditions. Within the central processing station, the equipment operating temperatures were coordinated with the upstream pipeline scheme. For the investigated operating condition, the resulting best feasible scheme produced a deterministic 3.18% reduction in total standard-coal-equivalent energy consumption. The results demonstrate the engineering value of coordinating low-temperature operating boundaries, pipeline heating processes, and station operating parameters in an existing high-water-cut gathering system. Full article

Although low-permeability oil reservoirs boast abundant resources, oil recovery remains relatively low due to the limitations of current water flooding development technology in oilfields. To address the current challenges of low-permeability oil reservoirs, nano-SiO₂ particle aqueous solutions, instead of conventional water injection, have been applied to these reservoirs, which can achieve promising results. Nevertheless, due to the simple surface structure of nano-SiO₂ particles, the unsaturated hydroxyl groups on their surfaces tend to undergo electrostatic attraction with cations in formation water, leading to particle aggregation and flocculation, ultimately compromising their stability. Therefore, studying the interaction between nano-SiO₂ particles and cations in saline solutions is of great significance for providing guidance on the application of nano-SiO₂ particles in low-permeability oilfields. In light of this, this paper employs molecular dynamics simulations and quantum chemical methods to investigate the processes of interactions between nano-SiO₂ particles and cations from a microscopic perspective. The results indicate that the interaction zone between monovalent cations and nanoparticles lies approximately 0.2 nm to 0.3 nm away from the particle surface. In comparison, the interaction zone between divalent cations and nanoparticles extends roughly from 0.3 nm to 0.4 nm from the particle surface. The range and depth of influence of divalent cations are more pronounced. No covalent or ionic bonds are formed between monovalent cations and nanoparticles. However, divalent cations can form ionic bonds with nanoparticles, thereby altering their structural configuration. Among these interactions, electrostatic forces represent the dominant interaction force responsible for changing the configuration of nano-SiO₂ particles, whereas van der Waals forces and hydrogen bonding forces are merely weak interactions. Moreover, as the valence state of the cation increases from monovalent to divalent, the cation forms new ionic bonds with the nano-SiO₂ particles, significantly modifying their structural configuration and further undermining their stability. The findings of this study can improve our understanding of the existing state of nano-SiO₂ particles in formation water, which can help to improve the application effect of nano-SiO₂ particles in low-permeability oil fields. Full article

Maintaining effective fluid-loss control in water-based drilling fluids under coupled high-salinity, high-temperature, and high-density conditions remains a critical challenge in deep and ultra-deep drilling operations. In this study, a low-molecular-weight polymer fluid-loss additive (LM-ASQF) was synthesized via redox-initiated copolymerization of acrylamide, dimethyldiallylammonium chloride, and sodium allyl sulfonate. The synthesis route and proposed polymer structure were further illustrated to clarify the incorporation of amide, quaternary ammonium, and sulfonate functional units within the LM-ASQF molecular architecture. The polymer exhibited a controllable number-average molecular weight of 18.2–29.4 kDa with a unimodal distribution. Thermal analysis confirmed that no main-chain-dominated degradation occurred below 220 °C, indicating structural stability under high-temperature conditions. In drilling-fluid systems containing NaCl, CaCl₂, and mixed salts (0–20%), LM-ASQF maintained stable rheological properties, with apparent viscosity ranging from 26.1 to 41.6 mPa·s, while the API fluid loss was controlled within 5.8–11.2 mL. After thermal aging at 220 °C for 16 h, the API fluid loss remained below 13 mL in both freshwater and mixed-salt systems. In high-density systems (1.80–2.40 g/cm³), the drilling fluids preserved continuous rheological structures and showed no abrupt increase in filtration. Mechanistically, fluid-loss control was primarily attributed to synergistic interfacial adsorption of amide groups, hydration stabilization induced by sulfonate functionalities, and particle rearrangement-driven filter-cake densification, rather than viscosity enhancement through long-chain entanglement. This mechanism enables effective filtration control without excessive viscosity increase, thereby maintaining rheological compatibility under complex conditions. These results demonstrate that the low-molecular-weight design strategy provides a reliable approach for achieving stable fluid-loss control in water-based drilling fluids under high salinity, elevated temperature, and high-density conditions. Full article

Refracturing is an important stimulation technique for improving the productivity of mature shale gas wells. However, for low-productivity horizontal wells, the controlling effects of production history and pre-refracturing energy replenishment on fracture re-initiation and repropagation remain insufficiently quantified. This study focuses on mature wells in the H Block of the Fuling shale gas field. The Jiaoshiba area in the Fuling shale gas field, located on the eastern margin of the Sichuan Basin, is characterized by organic-rich marine shales of the Wufeng–Longmaxi Formation, where gas enrichment is jointly controlled by the Jiaoshiba anticline, fault distribution, and favorable preservation conditions. A three-dimensional geological model was constructed using seismic interpretation, well logging, core analysis, ant-tracking fracture attributes, and field fracturing data. A one-way coupled finite-element workflow was then applied to simulate the evolution of pore pressure and in situ stress during primary production, water-injection energy replenishment, and refracturing. The model was calibrated against historical bottomhole flowing pressure data, with a pressure-response matching accuracy greater than 85%. The results show that a lower initial production (4 × 10⁴ m³/d) allocation can mitigate reservoir pressure depletion and maintain a more favorable stress environment for fracture branching during refracturing. Compared with refracturing after 10 or 20 years of production, refracturing after 5 years produced a stronger post-treatment response in the simulated cases. For water-injection energy replenishment, an injection rate of 700 m³/d restored reservoir pressure and regulated the local stress field more effectively than 500 m³/d, whereas increasing the rate to 1000 m³/d provided only limited additional pressure recovery. Overall, under the simulated reservoir conditions, a technically favorable parameter combination for the target well is an initial production allocation of 4 × 10⁴ m³/d, refracturing after approximately 5 years of production, and one year of pre-refracturing water-injection energy replenishment at about 700 m³/d. These findings provide a reference for refracturing timing and pre-treatment energy-replenishment design in depleted shale gas reservoirs. Full article

Understanding how methane moves through nanoporous media is key to predicting performance in unconventional gas reservoirs. At these extremely small scales, pore sizes approach the molecular level, where classical flow assumptions begin to fail and multiple transport mechanisms can occur at the same time. In this work, a unified framework is developed to characterize methane flow regimes using a real-gas corrected Knudsen number. By combining pore size, pressure, and temperature within a single formulation, the approach captures how flow behavior evolves across realistic reservoir conditions. A unified flow regime map is used to characterize the gradual shift in transport behavior—from adsorption-dominated and diffusion-like mechanisms in ultra-tight pores, to transition and slip flow, and eventually to continuum (Darcy) flow in larger pores. The results show that pore size plays the dominant role in determining flow behavior, while pressure introduces a dynamic effect, particularly during reservoir depletion. Sensitivity analysis also highlights that flow regime classification depends not only on thermodynamic conditions but also on molecular-scale parameters such as methane diameter. Comparison with established models and experimental observations shows that the framework captures the expected increase in rarefaction effects at low pressures and small pore sizes. Overall, the results emphasize that gas transport in nanoporous systems is not governed by a single mechanism but evolves over time and across scales. The proposed framework offers a simple, physically grounded tool for identifying dominant transport mechanisms and supporting model selection, while also providing a foundation for more advanced descriptions of gas flow in unconventional reservoirs. Full article

Polymer flooding is an important enhanced oil recovery technology for high-water-cut heterogeneous reservoirs, where long-term waterflooding commonly leads to preferential flow channels and insufficient mobilization of remaining oil in less-swept intervals. In this study, a hydrophobically modified partially hydrolyzed polyacrylamide-type polymer containing hydrophobic associative groups was evaluated for mobility control and enhanced oil recovery in heterogeneous porous media with the assistance of well-log-interpreted reservoir parameters. Reservoir heterogeneity was first characterized using interpreted effective thickness, porosity, permeability, oil saturation, and water saturation, and the polymer performance was then examined through rheological measurements, core-flooding experiments, and field production response analysis. The results show that the representative reservoir layers exhibit a wide permeability range of 7.9–186.5 mD, with higher water saturation in high-permeability layers and higher oil saturation in medium- and low-permeability layers. The polymer solution shows concentration-dependent thickening, shear-thinning behavior, salinity tolerance, and thermal-aging stability, retaining a viscosity of 139.5 mPa·s at 180,000 mg/L salinity and 74.9% viscosity retention after aging for 504 h. Core-flooding results indicate that the medium-permeability core achieves the highest polymer incremental recovery of 14.5 ± 0.8%, reflecting a favorable balance between injectivity and residual flow resistance. Field production data further show that daily oil production increases from 11.6 to 20.4 t/d, water cut decreases from 93.1% to 81.6%, and cumulative oil increment reaches 2055 t after polymer injection. The proposed mechanism involves associative thickening, pore-throat-adaptive transport, residual flow resistance, flow-path redistribution, and remaining-oil mobilization. This study establishes a heterogeneity-constrained mobility-control framework linking well-log-interpreted reservoir parameters, permeability-dependent polymer transport, residual flow resistance, and field production response, showing that effective polymer flooding depends on balancing injectivity, flow resistance, and remaining-oil availability rather than maximizing bulk viscosity alone. Full article

Accurate multiphase flow measurement in horizontal wells is fundamentally challenged by the antagonistic electrical responses of water and gas: Electrical Resistance Tomography (ERT) loses sensitivity to thin liquid films, while Electrical Capacitance Tomography (ECT) suffers signal saturation in conductive water, preventing either modality from covering the full operating envelope alone. This study proposes a physics-guided hybrid modeling framework that integrates multi-modal ERT/ECT sensing to achieve high-precision flowrate inversion. The framework utilizes a corrected multi-modal fusion algorithm, achieving a liquid holdup MAPE of 2.5 ± 0.5% representing a nearly two-fold improvement over the best single-modality system (Direct ERT, 4.5%). For velocity estimation, an optimized cross-correlation method yields results with ± 3.0% error, incorporating multi-sensor and multi-sequence fusion. A key finding is that deep neural networks exhibit Architectural Phase Specialization: multi-branch architectures (MB-DNN) perform strongly on localized, heterogeneous liquid structures (2.0% liquid error), whereas fully-connected architectures (FC-DNN) excel at capturing the global patterns of the continuous gas core (1.2% gas error). By hybridizing a calibrated drift-flux physical model with these phase-specialized DNNs, the framework achieves overall averaged errors of 1.8% for gas and 1.5% for liquid across the full experimental envelope. The proposed framework was evaluated on 444,313 experimental samples and subsequently validated in a three-month industrial trial at the Puguang gas field under extreme conditions (26 MPa, 80 °C), where it maintained a prediction error of ± 2.3%. This work establishes a scalable, physically consistent paradigm for intelligent hydrocarbon production monitoring. Full article

During depressurization-driven shale gas production, methane migration and state transformation in nanopores affect the source composition of produced gas. However, the relative contributions of initially free and initially adsorbed methane remain difficult to quantify at the molecular scale. In this study, we develop a Frame-0-based source-tracing framework for methane recovery in an idealized graphene square nanopore using molecular dynamics simulations under a stepwise depressurization protocol. Radical Voronoi local density and a two-component Gaussian mixture model are used to assign one-time initial labels to methane molecules at Frame 0. PID–preserving cross-frame tracking is then used to quantify the stage-wise and cumulative source contributions from the two initial populations. For the representative case of R = 10 nm and T = 353.15 K, the stage-wise fraction from the initially free population decreases from 79.5% to 62.2% as pressure decreases, while that from the initially adsorbed population increases from 20.5% to 37.8%. Increasing pore width mainly enhances total recovery through the contribution of initially free methane. Increasing temperature improves the contributions from both populations, with a stronger effect on initially free methane. The present results provide a molecular-scale quantitative characterization of methane initial-source attribution under the current stepwise depressurization protocol and establish a source-tracing framework that can be further extended to more realistic pore models. Full article

Fracture–vuggy carbonate reservoirs contain discrete caves, fractures, conduits, and vugs, which makes recoverable-reserve evaluation strongly dependent on connected volume rather than on total pore volume alone. This study develops a unit-scale dynamic reserve-updating method for the S48 unit, Tahe Oilfield, by coupling a water-body-corrected material-balance equation, a heterogeneity-corrected waterflood characteristic curve, and iterative geological-model calibration. The main methodological contribution is to convert static fracture–vug architecture into dynamically constrained connected subsystems: the parameter Rwo quantifies connected/injected water volume at the fracture–vug unit scale, whereas the coefficient M corrects the apparent slope of waterflood curves for non-uniform sweep and preferential pathways. The revised workflow was calibrated against pressure, production, injection-response, and history-matched simulation data. Sensitivity analysis indicates that the estimated reserve-utilization degree increased from 48.77% +/− 4.8 percentage points during natural depletion to 74.1% +/− 6.7 percentage points after gas injection, reflecting staged reserve mobilization within the tested uncertainty range. The method is intended for field-scale reserve updating in reservoirs with sufficient pressure-production data; its transferability remains limited by static-model quality, channeling intensity, and the single-unit validation scope of this study. Full article

The complex propagation behavior of hydraulic fractures (HFs) in strongly heterogeneous conglomerate reservoirs poses significant challenges for effective reservoir stimulation. In particular, the interaction between fractures and gravel-induced heterogeneity often leads to highly tortuous fracture networks and uneven stimulation efficiency. To address this issue, a series of laboratory true triaxial hydraulic fracturing experiments were conducted on artificially prepared conglomerate specimens with controlled gravel size and distribution. A quantitative evaluation index, termed the Fracture Complexity Index (FCI), was proposed to characterize the tortuosity and complexity of fracture networks by integrating multiple geological and engineering factors. The effects of cluster spacing and fracturing fluid viscosity on multi-fracture propagation behavior were systematically investigated. The results show that increasing cluster spacing enhances inter-fracture interaction and promotes fracture tortuosity, while lower fluid viscosity facilitates fracture branching but may limit effective propagation distance due to energy dissipation. To further quantify the trade-off between fracture complexity and propagation extent, a dimensionless fracture length was introduced and combined with FCI to establish a fracture morphology evaluation framework. This framework enables the classification of fracture patterns and reveals the coupling relationship between engineering parameters and fracture geometry. The findings provide new insights into the mechanisms of fracture propagation in conglomerate reservoirs and offer a quantitative basis for optimizing fracturing design, particularly in balancing fracture complexity and effective stimulation range in strongly heterogeneous formations. Full article

Formation pore pressure is a critical parameter controlling drilling safety and wellbore stability, and its prediction in ultra-deep carbonate formations is challenging due to extreme temperature–pressure conditions, complex geological settings, and strong lithological heterogeneity. This study develops a multi-parameter while-drilling process that integrates drilling engineering parameters, mud logging gas measurements, cuttings-based elemental logging data, and drilling fluid performance indicators to investigate the processes governing abnormal overpressure and its real-time responses. By combining elemental logging parameters, rock drillability indices, and gas logging responses, a predictive framework for detecting abnormal pore pressure is established. The results show that structural position strongly controls overpressure distribution; secondary fault zones preferentially host abnormal overpressure; synchronous enrichment of S and Sr in cuttings-derived elemental data provides precursor signals; and gas logging indicators, including total hydrocarbon peaks and hydrocarbon migration velocity, are highly sensitive to overpressure. Application of the proposed while-drilling process to three ultra-deep wells (Fudong-101, Hade-18, and TKe-1) generated nine real-time pressure warnings, eight of which were confirmed, yielding a prediction accuracy of 88.89%. These results demonstrate that the proposed process effectively improves real-time identification of abnormal overpressure in ultra-deep carbonate formations, enhancing drilling safety and operational efficiency. Full article

A sustainable polymer-based filtration control system was developed for high-temperature, high-density water-based drilling fluids. The system’s rheological stability, filtration performance, and filter cake properties were evaluated under varying conditions of temperature, salinity, and density. The drilling fluid density ranged from 1.80 to 2.20 g/cm³, the temperature from 25 to 150 °C, and the NaCl mass fraction w(NaCl) = 5–20%. The results indicated that increasing fluid density resulted in a progressive increase in apparent and plastic viscosities (from 42.6/28.4 mPa·s to 65.1/47.9 mPa·s), while the yield point remained relatively stable (14.2–17.2 Pa), suggesting that high solid loading enhanced viscous dissipation without inducing structural stiffening. Filtration loss increased moderately with temperature (6.8–12.3 mL at 25–150 °C) and salinity (6.8–10.7 mL at w(NaCl) = 5–20%), whereas it decreased significantly with increasing density (13.1–9.4 mL at 1.80–2.20 g/cm³), indicating a density-dominated filtration regime. At 120 °C, w(NaCl) = 12%, and 2.00 g/cm³, the developed system achieved a low filtration loss of 8.4 mL, outperforming three representative conventional filtration-control systems, including starch-based, sulfonated asphalt-based, and polymer-based technologies. Filter cake analysis revealed that increasing density facilitated the packing of multi-scale solids, reducing filter cake thickness from 1.62 mm to 0.98 mm and permeability from 1.34 × 10⁻¹⁵–4.05 × 10⁻¹⁶ m², while significantly improving resistance to erosion and compression. These findings demonstrate that the combination of interfacial stabilization and filter cake densification offers a robust and controllable filtration solution for high-temperature, high-density drilling environments, presenting a promising approach for drilling fluid systems in challenging conditions. Full article

Carbonate mound–shoal complexes, despite their complex pore structures and pronounced heterogeneity, represent one of the most productive reservoir units within carbonate formations. Accurately predicting key physical properties—such as porosity, permeability, and flow zone index—from well log data remains a significant challenge for conventional empirical methods. This study investigates the application of machine learning algorithms for optimizing the prediction of reservoir properties in hill-and-plain carbonate bodies. Six machine learning approaches—Support Vector Machines (SVM), Backpropagation Neural Networks (BPNN), Long Short-Term Memory Networks (LSTM), K-Nearest Neighbors (KNN), Random Forests (RF), and Gaussian Process Regression (GPR)—are systematically evaluated and compared. The analysis employed flow zone indices, geological data, and well log curves to classify porosity–permeability types. Seven logging parameters were used as input features: spectral gamma ray (SGR), uranium-free gamma ray (CGR), photoelectric absorption cross-section index (PE), bulk density (RHOB), acoustic travel time (DT), neutron porosity (NPHI), and true resistivity (RT). These features were paired with measured physical property values to train and validate the predictive models. Results demonstrate distinct algorithmic advantages for specific properties. The RF model achieved superior performance in permeability prediction, yielding an R² of 0.6824, whereas the GPR model provided the highest accuracy for porosity estimation, with an R² of 0.7342 and an Accuracy Index (ACI) of 0.9699. Despite these improvements, machine learning models still face limitations in accurately characterizing low-permeability zones within highly heterogeneous hill–terrace reservoirs. To address this challenge, the study integrates geological prior knowledge into the machine learning framework and applies cross-validation techniques to optimize model parameters, thereby providing a practical and robust approach for detailed assessment of mound–hoal carbonate reservoirs. Full article

The Dengying Formation gas reservoir in the Penglai gas field, located in the central Sichuan Basin, exhibits substantial resource potential and promising development prospects. This reservoir is characterized by well-developed fractures and dissolution cavities, strong heterogeneity, complex gas–water relationships, and widespread edge–bottom water. During production, edge–bottom water is prone to channeling and intrusion through high-permeability pathways, which severely constrains well productivity and overall gas recovery. To address these challenges, this study takes a fractured-vuggy carbonate edge–bottom water gas reservoir as an example. By integrating large-scale physical simulation with cross-scale numerical simulation, a rational production allocation method suitable for strongly heterogeneous gas reservoirs has been developed. The research results indicate that: (1) Large-scale physical simulation experiments demonstrate that for fractured-vuggy bottom water gas reservoirs, implementing rate reduction and pressure control after water breakthrough can effectively suppress water invasion and coning, extend the stable production period, and increase the recovery factor by approximately 16%; (2) Based on the dynamic characteristics of water invasion, key similarity criteria including the Bond number, capillary number, gravity–viscous force ratio, and geometric–temporal similarity ratio were selected to establish a scientific parameter design method for cross-scale numerical simulation; (3) By considering factors such as reservoir type and aquifer energy, single-well mechanistic models were used to determine appropriate production rates for individual wells, enabling rapid optimization of production allocation plans. This provides crucial guidance for efficient gas well development and surface facility planning. Full article

The presence of source rock with a high concentration of kerogen is not a sufficient condition for petroleum formation, as maturation requires specific thermodynamic conditions. In this study, the artificial maturation of organic matter was investigated through hydrothermal treatment simulating the vaporization–condensation zones associated with in situ combustion and steam-assisted recovery processes. The experiments were conducted under an inert nitrogen atmosphere at 250–350 °C to reproduce oxygen-depleted thermal environments where hydrothermal reactions dominate. The results demonstrate that the bitumoid yield increases with temperature, reaching a maximum of 4.44 wt.% at 300 °C, followed by a decline at 350 °C due to secondary cracking. At the same time, gas generation increases significantly, with a more than five-fold rise in total gas yield between 250 and 350 °C. In parallel, the H/C atomic ratio of kerogen decreases from 1.17 in the initial sample to 0.52 at 350 °C, indicating progressive aromatization and advanced catagenetic transformation. These changes are accompanied by the conversion of high-molecular-weight kerogen into resins, asphaltenes, and subsequently lighter hydrocarbons. The study provides experimental evidence for the effectiveness of hydrothermal processes in inducing kerogen transformation under inert conditions, offering insights into the mechanisms governing artificial maturation in unconventional reservoirs. Full article

Gas condensate banking can significantly reduce near-well gas productivity by as much as ~60% in tight gas reservoirs. Existing treatment techniques are resource demanding and could alter the reservoir structure permanently. This study investigates the effectiveness of enhanced electrokinetic oil recovery (EK-EOR) as a low-impact alternative for treating condensate banks. Using compositional reservoir simulation (CMG GEM), the influence of key reservoir and operational parameters—porosity, permeability, producer well location (i, j), injection rate, and injection pressure—on cumulative gas production (CGP) was examined. A Box–Behnken design of experiments was employed to generate 62 simulation runs, and a proxy model was developed to approximate full-field responses. Statistical validation showed strong model fidelity (R² = 0.99, AAPE = 2.2%). The proxy was then optimized using a genetic algorithm (GA) to identify conditions that maximize gas recovery. Results indicate that lower injection rates and lower injection pressures maximize CGP through enhanced electro-osmotic flow and reduced water blocking, achieving a peak cumulative gas of 4.06 × 10⁸ ft³. A secondary optimum at high injection pressure could be attributed to re-pressurization and partial re-vaporization of condensate near the wellbore. Reservoir quality also exerted a strong control: higher permeability and moderate porosity favoured gas yield, while optimal producer placement near the reservoir boundary increased drainage efficiency. This study demonstrates a systematic optimization framework combining design of experiments, proxy modelling, and evolutionary algorithms to evaluate EK-EOR performance. Full article

CO₂-enhanced gas recovery (CO₂-EGR) is a crucial technology for achieving both natural gas production increase and CO₂ geological storage. While pure CO₂ flooding demonstrates favorable recovery performance, the technical challenges and high costs associated with purifying CO₂ remain significant. CO₂ purification from exhaust gas incurs prohibitive costs, while direct injection of an unpurified CO₂–N₂ mixture can greatly cut engineering expenditure. Nitrogen also provides synergistic pressure support, working with CO₂ to drive natural gas displacement. Therefore, from an economic and practical standpoint, employing impure CO₂ mixtures (e.g., CO₂–N₂) for flooding presents a more advantageous approach. To clarify the factors influencing the recovery enhancement in tight sandstone gas reservoirs using CO₂–N₂ mixtures, long-core flooding experiments were conducted at 100 °C. This study systematically investigates the impact patterns of three key factors—injection timing, injection rate, and injection gas composition—on the enhanced recovery of tight sandstone gas reservoirs. The experimental results indicate that: (1) Advancing the injection timing significantly improves the recovery performance for both CO₂ and N₂ flooding. However, the cumulative recovery factor (sum of the depletion recovery and the incremental recovery from gas injection) shows a declining trend. (2) The enhanced recovery effect exhibits a trend of first increasing and then decreasing with the increase in injection rate. When the injection rate exceeds 0.05 mL/min, it tends to cause premature breakthrough of the injected gas, thereby reducing the displacement efficiency. (3) As the proportion of CO₂ in the injected gas increases, the enhanced recovery effect shows a nonlinear rise. The highest incremental recovery (17.02%) was achieved with pure CO₂ flooding, while pure N₂ flooding yielded the lowest result (14.64%). The research findings, from a macroscopic perspective, elucidate the influence patterns of three distinct factors on enhancing gas recovery in tight sandstone reservoirs, thereby providing theoretical foundation and scientific guidance for the development of such reservoirs. In summary, the injection timing, injection rate and CO₂ proportion in injected gas are the key controlling factors for gas flooding enhanced recovery in tight sandstone reservoirs. This study clarifies the macroscopic influence law of each factor, and the optimized development parameters proposed can provide direct theoretical support and technical guidance for the on-site application of gas flooding in tight sandstone reservoirs. Full article

Horizontal well fracturing serves as a critical technology for enhancing production from tight sandstone gas reservoirs, where accurate prediction of formation breakdown pressure is essential for optimizing fracture design and improving stimulation effectiveness. This study proposes a novel fusion-driven workflow for predicting breakdown pressure in horizontal wells by synergistically integrating physics-based mechanistic modeling with data-driven machine learning. The approach overcomes the computational limitations of conventional analytical models and mitigates the data scarcity constraints inherent in purely empirical methods by using high-fidelity mechanistic simulations to generate physically consistent training samples. Results demonstrate that the hybrid dataset, with an optimal fusion ratio of 1:1.5 between field data and mechanistic-derived samples, yields the highest predictive accuracy. The proposed model, built on an XGBoost algorithm whose hyperparameters are efficiently optimized via a tree-structured Parzen estimator (TPE), exhibits superior generalization capability and robustness, achieving an average prediction error of 7.45% on unseen well data. This work confirms that the fusion framework provides a reliable and practical tool for breakdown pressure prediction in cased horizontal wells, which can directly support the design and implementation of efficient and sustainable fracturing operations in tight gas reservoirs. Full article

In response to the complex drilling conditions in the carbonate reservoirs of the Tahe Oilfield, a brine-based solids-free drilling fluid system using oilfield-produced water was developed. Most existing solids-free drilling fluid systems are formulated with fresh water or low-mineralization water, which cannot maintain stability in the high-salinity, high-mineralization conditions of oilfield water. This study addresses this gap by systematically optimizing viscosifiers, fluid-loss control agents, and lubricants, enabling the use of highly mineralized produced water. The developed system maintains good rheological properties and fluid loss control even under challenging conditions. Laboratory tests show that the system, with POLY-V as the viscosifier, DEG-FLO and STAR-AM as fluid-loss agents, and ATV-SLIP as the lubricant, exhibits stable performance under the high-temperature, high-salinity conditions typical of the Tahe Oilfield, with limited performance degradation. Full article

Lacustrine shale oil in the Chang 7 Member of the Ordos Basin is controlled by a multi-scale pore–throat system in which oil occurrence, spontaneous imbibition, and pore-structure evolution are tightly coupled. In this study, nitrogen adsorption and micro-computed tomography (μCT) were employed to characterize pore-size distribution and connectivity, whereas nuclear magnetic resonance (NMR) T₂ relaxation was utilized to classify oil occurrence states, and X-ray diffraction (XRD) and total organic carbon (TOC) analyses were performed to determine mineralogical and organic compositions. Spontaneous imbibition experiments were conducted at 60 °C and subsequently extended to temperature–pressure sequence tests. The Chang 7 shale exhibits a stratified pore system in which micropores, mesopores, and macropores jointly define a three-tier “micropore adsorption–mesopore confinement–macropore mobility” pattern. As pore size and connectivity increase, the equilibrium imbibed mass and initial imbibition rate both rise, while enhanced wettability (contact angle decreasing from 81.2° to 58.7°) further strengthens capillary uptake. Temperature elevation promotes imbibition, whereas increasing confining pressure suppresses it, revealing a “thermal enhancement–pressure suppression” behavior. μCT-based network analysis shows that imbibition activates previously ineffective pore–throat elements, increasing coordination number and connectivity and reducing tortuosity, which collectively represents a capillary-driven structural reconfiguration of the pore network. When connectivity exceeds a threshold of about 0.70, the flow regime shifts from interface-dominated to channel-dominated. Building on these observations, a multi-scalecoupling framework and a three-stage synergistic mechanism of “pore-throat activation–energy conversion–structural reconstruction” are established. These results provide a quantitative basis for predicting imbibition efficiency and optimizing capillary-driven development strategies in deep shale oil reservoirs. Full article

Tight reservoirs are highly heterogeneous, with complex pore-throat structures and varying fluid occurrences. The Archie equation shows a nonlinear relationship, making traditional logging interpretation methods unreliable for accurately predicting water saturation. This paper employs particle swarm optimization (PSO), using Pearson correlation coefficient-based feature selection, to compare the accuracy of three machine learning algorithms: XGBoost, LightGBM, and MERF in predicting water saturation in tight reservoirs. It also applies the SHAP value algorithm to provide a visual and interpretive analysis of the PSO LightGBM model. The research results indicate that the root mean square error (RMSE), coefficient of determination (R2), and accuracy of water saturation (Swa) of the PSO-LightGBM model on the training and test sets are 0.955, 3.087, 91.8%, and 0.89, 5.132, 85.2%, respectively. Interpretability analysis using SHAP values reveals that the five normalized logging parameters—SP, M2R3, DEN, DT, and CN—are the most influential features in the water saturation prediction model. In application examples involving water saturation prediction across eight sections of tight reservoirs in the study area, the PSO–LightGBM, PSO–XGBoost, and PSO–MERF models achieved Swa of 88.9%, 80.3%, and 87.8%, respectively. The results demonstrate that the PSO–LightGBM model is a reliable and efficient method for predicting water saturation, with significant practical potential. Full article

During drilling in fractured formations, wellbore instability issues such as fluid loss and collapse frequently occur, severely compromising drilling safety. Traditional criteria such as Mohr–Coulomb often fail to adequately account for fracture effects, leading to inaccurate collapse pressure predictions. Taking the Tahe Oilfield as a case study, this research develops an enhanced model for predicting wellbore collapse pressure in fractured formations. Based on principles of elastic mechanics and Biot’s effective stress theory, a stress distribution model around deviated wellbores is established. The single weak plane strength criterion is integrated with the Mohr–Coulomb criterion to characterize failure mechanisms in both fractured zones and intact rock matrix. Newton’s iterative method, implemented in MATLAB, is employed to solve for collapse pressure, and a sensitivity analysis is conducted to evaluate the influence of factors such as in situ stresses and fracture orientation. A case study from Well THX demonstrates that neglecting fractures results in a symmetrical collapse pressure profile and an unduly narrow safe mud weight window. In contrast, accounting for fractures significantly increases the required mud weight and identifies an optimal azimuth range for enhancing wellbore stability. The Mohr–Coulomb criterion is shown to underestimate the necessary mud weight, which aligns with actual wellbore collapse incidents encountered during drilling. The single weak plane criterion offers more accurate predictions, recommending a higher minimum mud density and an optimized well trajectory to mitigate drilling risks. These findings offer theoretical and practical guidance for mitigating wellbore instability in fractured formations. Full article

With the rapid development of offshore oil and gas fields in China, there is an increasing demand for high-efficiency and high-reliability compression equipment. This study presents the design and localization of a 25 MW gas turbine-driven centrifugal compressor unit specifically developed for offshore platforms. Based on performance calculations, the gas turbine and compressor were selected and structurally optimized. A skid-mounted base frame with vibration isolation was designed to adapt to offshore steel deck structures, and a control system was developed and integrated. Performance verification was conducted through risk-based type tests. The results show that the unit demonstrates excellent operational stability, high efficiency, and reliability, fully meeting the requirements of offshore oil and gas applications. This work provides technical support and engineering experience for promoting the localization of key offshore equipment. Full article

During sand cleanout operations in shale oil horizontal wells, severe wellbore leakage occurs due to incompatibility between plugging particles and the formation, resulting in a failure to establish circulation. This study determined the optimal plugging theory for the target formation characteristics through laboratory leakage sealing tests and numerical simulations such as fluid–discrete element coupling (CFD-DEM). The results show the following: Plugging experiments indicated that the Vickers criterion achieved the best performance, with an invasion depth of 9 mm, followed by the Ideal Packing Theory, at 12 mm, while the D90 rule performed the worst, with an invasion depth of 13 mm. The simulations results from the CFD-DEM coupling model demonstrated that the Vickers criterion achieves the most effective plugging performance, followed by the Ideal Packing Theory, with the D90 rule exhibiting the least effectiveness. This indirectly validates the rationality and effectiveness of the Vickers criterion in configuring particle sizes for plugging materials. Finally, sand-packed-tube displacement experiments demonstrate that the Vickers criterion yields the lowest permeability and optimal plugging performance, further validating its rationality and effectiveness in configuring particle sizes for plugging materials. This research provides crucial technical support for the safe and efficient development of shale oil horizontal wells, effectively reduces operational costs, and holds significant importance for advancing technological progress in shale oil extraction. Full article

To address the issue of wellbore instability during drilling in fractured formations, this study systematically investigates the influence mechanisms of fracture geometry and strength parameters on wellbore stability by constructing a multi-weak plane strength criterion and a thermo-hydro-chemical coupling model. Based on Jæger’s single weak plane criterion, a multi-weak plane strength criterion considering the synergistic effects of multiple fracture groups is established. By integrating Boit’s effective stress theory, an analytical solution for the stress field around a wellbore in fractured formations has been derived. A method for calculating collapse pressure and predicting instability zones is also proposed, utilizing the Newton–Raphson iterative algorithm. The results demonstrate that fracture systems markedly alter the anisotropic characteristics of wellbore stress. While the collapse pressure contour in intact formations exhibits bilateral symmetry (25.5–30 MPa), in formations with four fractures, the pressure increases to 29–37 MPa and the symmetry is lost. Furthermore, the instability zone in vertical wells evolves from a “crescent-shaped” pattern in homogeneous formations to a “quadrilateral-shaped” expansion. Notably, the instability area in horizontal wells is significantly smaller than in vertical wells. These outcomes offer theoretical guidance for optimizing the drilling fluid density window and well trajectory design in fractured formations. Full article

Axial–torsional coupled impact drilling (ATCID) technology represents a promising solution for overcoming the drilling challenges posed by conglomerate formations, which are characterized by strong heterogeneity, high abrasiveness, and poor drillability. However, the optimal parameter matching relationships and their influence patterns on mechanical specific energy (MSE) remain unclear. This study employed self-developed true triaxial impact rotary rock breaking equipment with conglomerate cores from the Junggar Basin to systematically investigate the effects of weight on bit (WOB), rotational speed (RPM), axial impact frequency, and torsional impact frequency on MSE through orthogonal experimental design. The results demonstrate that the parameter influence ranking on MSE is as follows: torsional impact frequency > WOB > RPM > axial impact frequency, with torsional impact frequency exhibiting the largest range value (87.5 MPa). ANOVA reveals that the interaction between axial and torsional impact frequencies is the dominant controlling factor, contributing 22.8% to MSE variation with high statistical significance. The optimal parameter combination yields the minimum MSE (103 MPa): 19 kN WOB, 20 r/min RPM, 20 Hz axial impact frequency, and 20 Hz torsional impact frequency, representing a 69.1% reduction compared to the maximum value. Response surface analysis revealed that increasing WOB significantly reduces MSE, RPM exhibits positive correlation with MSE, and synergistic effects occur when both impact frequencies reach high values simultaneously. A nonlinear MSE prediction model incorporating main effects, quadratic terms, and interaction effects was established with R² = 0.8240 and a mean absolute percentage error of 9.26%. The research findings provide an essential theoretical foundation for parameter optimization and engineering applications of ATCID technology, offering significant implications for enhancing drilling efficiency in conglomerate and other challenging hard rock formations. Full article

This study analyzes the lacustrine hydrocarbon source rocks of the Lower Cretaceous in the Erdengsumu sag of the Erlian Basin, evaluating their characteristics and identifying areas with oil resource potential, while also investigating the ancient lake environment, material source input, and controlling factors, ultimately developing a sedimentary model for lacustrine hydrocarbon source rocks. The findings suggest the following: (1) The lower Tengger Member (K₁bt₁) and the Aershan Formation (K₁ba) are the primary oil-producing strata, with an effective hydrocarbon source rock exhibiting a lower limit of total organic carbon (TOC) at 0.95%. The Ro value typically remains below 0.8%, indicating that high-maturity oil production has not yet been attained. (2) The oil generation threshold depths for the Dalestai and Sayinhutuge sub-sags are 1500 m and 1214 m, respectively. The thickness of the effective hydrocarbon source rock surpasses 200 m, covering areas of 42.48 km² and 88.71 km², respectively. The cumulative hydrocarbon generation intensity of wells Y1 and Y2 is 486 × 10⁴ t/km² and 26 × 10⁴ t/km², respectively, suggesting that the Dalestai sub-sag possesses considerable petroleum potential. The Aershan Formation in the Chagantala sub-sag has a maximum burial depth of merely 1800 m, insufficient to attain the oil generation threshold depth. (3) The research area’s productive hydrocarbon source rocks consist of organic matter types I and II₁. The Pr/Ph range is extensive (0.33–2.07), signifying a reducing to slightly oxidizing sedimentary environment. This aligns with the attributes of small fault lake basins, characterized by shallow water and robust hydrodynamics. (4) The low ratio of ∑nC₂₁₋/∑nC₂₂₊ (0.36–0.81), high CPI values (>1.49), and high C₂₉ sterane concentration suggest a substantial terrestrial contribution, with negligible input from aquatic algae–bacterial organic matter. Moreover, as sedimentation duration extends, the contribution from higher plants progressively increases. (5) The ratio of the width of the deep depression zone to the width of the depression in the Erdengsumu sag is less than 0.25. The boundary fault scale is small, its activity is low, and there is not much input from the ground. Most of the source rocks are in the reducing sedimentary environment of the near-lying gently sloping zone. Full article

Sulfur particle deposition and wellbore blockage significantly hinder the productivity of high-sulfur gas wells, necessitating accurate prediction of the critical gas flow velocity to prevent deposition. This study presents a comprehensive force-based model to determine the critical gas flow velocity in vertical wells, explicitly incorporating adhesion, boundary layer effects, and particle detachment mechanisms. Through detailed analysis, the forces acting on sulfur particles of varying sizes and flow velocities, as well as the key factors influencing the critical gas flow velocity, were examined. The results demonstrated strong agreement with the experimental data, with a mean absolute percentage error of 6%, while revealing significant deviations from the conventional critical gas suspension velocity, validating the model’s enhanced accuracy and its necessity. This study identified adhesive forces as dominant for small particles (<100 µm) at low velocities (≤10 m/s), whereas gravitational and inertial forces prevailed for larger particles. Key parameters such as the particle size, sphericity, Hamaker constant, friction coefficient, and rolling arm length ratio critically influenced the deposition velocity and detachment mechanisms. These findings provide fundamental insights into sulfur deposition dynamics and establish a scientific basis for optimizing wellbore operations to mitigate sulfur accumulation and improve production efficiency in high-sulfur gas wells. Full article

This study addresses the critical challenge of maintaining drilling fluid performance and wellbore stability in high-pressure, high-temperature (HPHT) environments, where conventional water-based drilling fluids often fail. This research investigates whether the integration of single- and dual-nanomaterial systems into base fluids can significantly enhance rheological behavior and shale inhibition potential. Using secondary experimental datasets and computational modeling, five nanomaterials—SiO₂, Al₂O₃, TiO₂, Fe₂O₃, and Fe₃O₄—were evaluated individually and in dual combinations with polymers. Key performance metrics, including plastic viscosity, fluid loss, and shale recovery, were analyzed and fitted to the Herschel–Bulkley rheological model. The results showed that single-nanomaterial systems modestly improved viscosity and fluid loss control, with SiO₂ and Fe₂O₃ offering the best standalone performance. Dual systems—particularly SiO₂–Al₂O₃ and Fe₃O₄–polymer combinations—demonstrated superior rheological performance with reduced viscosity (down to 19 cP), minimized fluid loss (<4 mL/30 min), and enhanced shale recovery (>90%). These improvements suggest synergistic effects between nanomaterials, supporting their use in designing advanced, thermally stable drilling fluids for extreme HPHT wells. Full article

The abnormal swab pressure resulting from packer unsetting poses a great threat to the collapse resistance of production casings in deep high-pressure and high-temperature (HPHT) oil wells. This paper proposes an analytical model to predict the transient swab pressure in the A-annulus after packer unsetting based on a U-type tube and an iterative method. The model can further evaluate the collapse failure risk of the production casing in the whole wellbore. An example study and sensitivity analysis were carried out to reveal the variation characteristics of the transient swab pressure in the A-annulus and the failure risk of the production casing after packer unsetting. Furthermore, some preventative measures are proposed. The largest swab pressure occurs at the initial time of packer unsetting, which will lead to sudden collapse failure of the deeper production casing. A smaller width of the annular clearance between the packer rubber and production casing and a larger initial liquid level depth in the A-annulus can reduce the swab pressure in the A-annulus after packer unsetting and collapse failure risk of the production casing. In the example, when the width of the annular clearance decreased from 2.97 to 2 mm, the maximum swab pressure decreased from 88.71 to 27.4 MPa, a decrease of 69.1%. When the initial liquid level depth in the A-annulus increased from 700 to 900 m, the maximum swab pressure decreased from 122 to 57.05 MPa, a decrease of 53.2%. When the width of annular clearance was 2.97 mm, the collapse resistance safety factors for the production casing were less than 1.1 and may suffer from collapse failure for well depth between 3610 m and 6100 m. When the initial liquid level depth in the A-annulus was 700 m, the production casing will suffer from collapse failure for well depth between 2869 m and 6100 m. When the width of the annular clearance was less than 2.5 mm and the initial liquid level depth in the A-annulus was larger than 900 m, the collapse resistance safety factors for the production casing were all greater than 1.1 and the whole production casing was safe. To lower the collapse failure risk of the production casing because of packer unsetting, a packer rubber with a reasonable larger outer diameter and good deformation recovery ability is recommended, and the initial liquid level depth in the A-annulus should be controlled reasonably. The research results are of great significance for preventing the collapse failure of production casings during packer unsetting. Full article

In enhanced oil recovery (EOR), various processes have specific requirements concerning surfactant surface activity. High surface activity is essential during the oil production, whereas low or even negligible surface activity is required during the oil separation process. CO₂-responsive surfactants can regulate their surface activity through the addition or removal of CO₂ in their aqueous solutions. This property makes them suitable for the formulation of CO₂-responsive displacement systems, including CO₂-responsive foam, emulsion, and hydrogel systems. These three systems hold significant application value within the realm of enhanced oil recovery. This paper reviews the structure, types, synthesis methods, applications in EOR technology, and the effects of EOR in both field and laboratory settings. This method is both environmentally friendly and efficient for enhancing oil recovery. Furthermore, the application of CO₂-responsive surfactants facilitates carbon capture, utilization, and storage, contributing to the achievement of carbon neutrality and the carbon peak. Full article

The novel martensitic stainless steel 13CrU was developed based on 13CrS by adding trace alloying elements, such as Mo, Ni, and Ta. This study compares the mechanical and corrosion resistance properties of the two martensitic stainless steels to assess the effect of these alloying elements on 13CrU’s performance. Experimental results show that increasing Mo by 0.67 wt% and Ni by 1.13 wt% improves the yield strength of 13CrU by 11.6% compared to 13CrS. The addition of Ta enhances the corrosion resistance of 13CrU beyond that of 13CrS. Overall, the addition of trace alloying elements significantly improves the mechanical properties of 13CrU and enhances its resistance to CO₂ corrosion. Full article

Wellbore instability caused by hydration during the development of shale gas reservoirs poses significant challenges to drilling engineering. In this study, a novel and environmentally friendly shale inhibitor, TIL-NH₂, was synthesized via free radical polymerization using 1-vinylimidazole and N-(2-bromoethyl)-1,3-propanediamine dihydrobromide as the main raw materials. The molecular structure of TIL-NH₂ was characterized by infrared spectroscopy and nuclear magnetic resonance. Incorporating imidazole cations and amino bifunctional groups, TIL-NH₂ exhibits excellent inhibitory performance and environmental friendliness. Its performance was systematically evaluated through linear swelling tests, shale cuttings rolling recovery tests, permeability recovery experiments, and dynamic adsorption analyses. The results indicate the following: (1) At a concentration of 1.2 wt%, TIL-NH₂ reduced the linear swelling height of shale by 65.69%, significantly outperforming traditional inhibitors like KCl and NW-1. (2) Under conditions of 140 °C, the cuttings rolling recovery rate of TIL-NH₂ reached 88.12%, demonstrating excellent high-temperature resistance. (3) Permeability recovery experiments showed that at a concentration of 2.0 wt%, TIL-NH₂ achieved a permeability recovery rate of 90.58%, effectively mitigating formation damage. (4) Dynamic adsorption experiments indicated that at a concentration of 2.5 wt%, the adsorption capacity tended toward saturation, reaching 26.00 mg/g, demonstrating stable adsorption capability. Additionally, environmental friendliness evaluations revealed that TIL-NH₂ has a degradation rate exceeding 90% within 28 days, and its acute toxicity is significantly lower than that of traditional inhibitors like KCl (the LC₅₀ of TIL-NH₂ is 1080.3 mg/L, whereas KCl is only 385.4 mg/L). This research provides a high-efficiency and environmentally friendly new inhibitor for green drilling fluid systems in horizontal shale gas wells, offering important references for technological advancements in unconventional energy development. Full article