The reservoir in the Central Tarim Basin is a typical high-pressure fracture-vuggy carbonate reservoir with high temperatures, which easily leads to drilling fluid losses and the high-temperature carbonate. The conventional lost circulation materials (LCMs) cannot meet the reservoir. To resolve this problem, a rigid particle with high-temperature resistance, high acid solubility, and high rigidity was developed, tested, and evaluated. According to bridge rules of 1/2–2/3 opening degree of formation fracture, the formulation experiments of GZD and other lost circulation materials were conducted and a novel composite lost circulation material (LCM) was completed. Lastly, we investigated the compatibility of LCM and mud in site though compatibility experiment, analyzed the plugging effect of the system for fracture and vuggy by laboratory static lost circulation simulation and evaluation and sand-bed plugging experiments, respectively. The results show that compared with the conventional rigid lost material, the value of high-temperature resistance is more and acid solubility is over 98%. Also, it can work well with other fiber materials (E), variable filling particles (F and G), and superfine filling particles (H) and form a novel plugging material, named MGY-I, whose temperature resistance value is more than 473.15 K, the bearing strength is over than 9 MPa, the mud filtrate invasion depth of sand bed made from coarse particles (10∼20 mesh) is only 3.0 cm within 30 minutes, and the invasion depth is less than 1 cm within 30 minutes when the sand bed is made from 80∼100 mesh. The optimal concentrations of rigid granule, lignin fiber, elastic particle, and superfine calcium carbonate are 8% (A : B : CD = 2 : 1 : 1), 0.5%, 6%, and 1%, respectively. And, the plugging function of “GZD-rigidity bridge and filling, fiber network and deformable filing” is better exerted on the formation fracture with a high loading capacity and a high-temperature resistance.

Hydroxyethyl cellulose (HEC) is widely used in water-base drilling fluid as tackifier because of its good fluidity, stability, prop-carrying capacity, and good reservoir protection, while it has insufficient rheological property under higher temperature. In order to make use of its advantages and improve thermal stability, an innovative method that HEC was dissolved in the emulsion was proposed. Research indicated that compared with traditional water solution, the oil-water emulsion as solution could effectively improve the rheological properties and thermal stability. The oil-water ratio has an obvious effect on rheological properties. Firstly, with the decrease in the oil-water ratio, the apparent viscosity and shear stress were decreased; secondly, under constant oil-water ratio or temperature, the larger the shear rate, the lower the apparent viscosity, and the greater the shear strength; lastly under extremely low shear rate, HEC emulsion’s viscosity peaked at more than 50000 mPa·s, which can effectively solve the problem of sand carrying difficulty and being easy to form sand bed in horizontal well and high angle hole. In addition, the emulsifying stability was degradative with the increase in the oil-water ratio. The degradation was not obvious when the oil-water ratio was less than 30 : 70. On the contrary, the performance deteriorated drastically when the oil-water ratio was greater than 30 : 70. The separator liquid was more than 2 cm and was even about 1/3 when the oil-water was 50 : 50. On the basis of analysis of the experimental results, we can see that oil-water emulsion could effectively improve the rheological stability and thermal stability of HEC and the optimal oil-water ratio was 30 : 70. This study provided a new thought for application of HEC or other polymers in drilling fluid.

The stability of the plugging zone has a great impact on lost circulation control and gas invasion prevention in fractured reservoirs. In this work, the concept of “cavitation‐induced shear failure” is put forward based on the analysis of the flow field characteristics, and the failure mechanism is discussed. The strength physical model of a fractured plugging zone is formed based on the analysis of the characteristic parameters of LCMs and the failure mechanism. And then the simulation experiments of cavitation‐induced shear failure, gas invasion prevention, pressure bearing, and tight plugging are carried out. The research shows that (1) the fractured plugging zone is a dense granular matter system, and the contact forces and quid bridge force are dominant in its internal; (2) the cavitation‐induced shear failure is one of the main failure modes of the plugging zone in a fractured gas reservoir, and the failure process includes three steps: gas diffusion‐dilution damage, confluence and carry damage, and displacement dislocation shear failure; (3) the strengthening model of the plugging zone, “rigid bridging+elastoplastic filling+lacing wire of fiber+film‐forming seal,” is a better model, and experiments prove that it can form a tight pressure‐bearing plugging zone, preventing drill‐in fluid loss. The research results provide a theoretical and technical basis for the lost circulation control of fractured gas formations.

The in situ emulsification synergistic self-profile control system has wide application prospects for efficient development on offshore oil reservoirs. During water flooding in Bohai heavy oil reservoirs, random emulsification occurs with superimposed Jamin effects. Effectively utilizing this phenomenon can enhance the efficient development of offshore oilfields. This study addresses the challenges hindering water flooding development in offshore oilfields by investigating the emulsification mechanism and key influencing factors based on oil–water emulsion characteristics, thereby proposing a novel in situ emulsification flooding method. Based on a fundamental analysis of oil–water properties, key factors affecting emulsion stability were examined. Core flooding experiments clarified the impact of spontaneous oil–water emulsification on water flooding recovery. Two-dimensional T1–T2 NMR spectroscopy was employed to detect pure fluid components, innovating the method for distinguishing oil–water distribution during flooding and revealing the characteristics of in situ emulsification interactions. The results indicate that emulsions formed between crude oil and formation water under varying rheometer rotational speeds (500–2500 r/min), water cuts (30–80%), and emulsification temperatures (40–85 °C) are all water-in-oil (W/O) type. Emulsion viscosity exhibits a positive correlation with shear rate, with droplet sizes primarily ranging between 2 and 7 μm and a viscosity amplification factor up to 25.8. Emulsion stability deteriorates with increasing water cut and temperature. Prolonged shearing initially increases viscosity until stabilization. In low-permeability cores, spontaneous oil–water emulsification occurs, yielding a recovery factor of only 30%. For medium- and high-permeability cores (water cuts of 80% and 50%, respectively), recovery factors increased by 9.7% and 12%. The in situ generation of micron-scale emulsions in porous media achieved a recovery factor of approximately 50%, demonstrating significantly enhanced oil recovery (EOR) potential. During emulsification flooding, the system emulsifies oil at pore walls, intensifying water–wall interactions and stripping wall-adhered oil, leading to increased T2 signal intensity and reduced relaxation time. Oil–wall interactions and collision frequencies are lower than those of water, which appears in high-relaxation regions (T1/T2 > 5). The two-dimensional NMR spectrum clearly distinguishes oil and water distributions.

The accurate extraction of pore-throat information, particularly in pore-throat size, pore connectivity, and pore morphology, is of great significance for the physical transport of porous media. However, traditional methods for pore-throat information extraction often rely on petrophysical methods, exhibiting evident weakness in achieving visual and quantitative characterization. In this article, an integrated analysis of petrography, micro-computed tomography (CT), and conventional petrophysical methods (X-ray diffraction, casting thin section, and scanning electron microscopy) was combined to realize visual and quantitative characterization of pore structure in tight sandstone reservoirs. Based on CT and image processing technology, a three-dimensional (3D) digital core model was reconstructed. Characteristic parameters describing pore morphology, shape factor, sphericity, and equivalent diameter were defined, and the quantitative classification of 3D pore morphology was carried out. The results reveal that the predominant pore types in the study area are primary intergranular pores, intergranular dissolved pores, intra-granular dissolved pores, and inter-crystalline pores, and typical types of throats are necked, lamellar, and lamellar curved throats. Moreover, the pore structure of tight sandstone consists of both isolated pores and interconnected pores, and the volume of interconnected pores accounts for 83.47% of the total pore volume, while the volume of isolated pores accounts for an average of 16.53% of the total pore volume. In addition, the pore–throat ratio is mainly distributed between 2 and 7, and the coordination number is mainly distributed between 1 and 5. Besides, the pore morphologies of tight sandstone are classified into spherical pores, triangular pores, banded pores, and harbor-like pores. Specifically, spherical pores and triangular pores dominate in pore number, but minimally in pore volume and surface area. In contrast, banded pores and harbor-like pores together constitute the majority of the pore volume (>80.64%) of the Penglaizhen Formation in the Sichuan Basin. This study enables accurate characterization of microscopic pore-throat features in tight sandstone reservoirs and provides a strong theoretical support for the subsequent research on physical transport in tight sandstone reservoirs.

Directional drilling trajectory interpretation is critical for real-time steering control and post-drilling evaluation. However, existing automated methods often fail to maintain physical consistency with realistic trajectories due to measurement noise and the inability of point-by-point classifiers to enforce sequential constraints. This study proposes a physical constraint-based keypoint detection framework that integrates ensemble learning with a globally constrained dynamic programming (DP) decoder. Specifically, a leakage-free feature engineering module is developed to capture multi-scale geometric dynamics and a priori engineering designs. An ensemble of XGBoost and LightGBM models is then employed to estimate the probability of critical points. To address the problem of critical point fragmentation assessment, physical ordering, trend consistency, and local smoothness constraints are specified for critical point identification by introducing a DP-based decoding algorithm that converts the local probabilities into optimal “build-hold-drop” sequences. In the experimental part of this paper, the results obtained from 5-fold GroupKFold cross-validation with five different methods on a real oilfield dataset of 64 wells show that the framework proposed in this paper significantly outperforms heuristic baselines and standard machine learning models. Notably, the integration of a physically-aware DP decoder improves the tolerance-based Macro-F1 score by more than 12% and effectively eliminates logical violations in trajectory interpretation. These results indicate that the system provides a reliable solution for automated drilling trajectory threshold evaluation.