The application of fiber in the completion fluid can improve the rheological properties of the completion fluid and the plugging quality of the production layer by the completion fluid and reduce the damage of the filtrate to the reservoir formation. However, there are few studies on the influence of fibers on the rheological properties of completion fluids and the flow behavior in pores. In this paper, plant fiber, mineral fiber, and synthetic fiber are discussed. Carbon fiber, bamboo fiber, polypropylene fiber, and polyester fiber are selected as research objects. The dependence of the rheological property of polymer solution on fiber type, fiber concentration, temperature, and shear rate is evaluated. The evaluation is carried out by observing the microscopic state of the fiber through a microscope and a scanning electron microscope, testing the rheological property parameters of the fiber with an OFITE 900 rheological tester, and fitting with the Herschel–Bulkley model. The results show that polypropylene fiber and carbon fiber have the best dispersion in polymer solution. The higher the fiber content, the greater the influence of fiber on the rheological properties of the solution. Compared with the other three fibers, carbon fiber has the greatest influence on the rheological properties of polymer solution. When the temperature is lower than 70 °C, the influence of the fiber on the rheological properties of the solution is not affected by the temperature. When the temperature exceeds 70 °C, the carbon fiber and polypropylene fiber are affected by the temperature, and the viscosity of the polymer solution is increased. The flow behavior of fiber suspensions in pores varies with the flow factor n. Carbon fiber suspensions are most conducive to the transition of polymer solution to plate laminar flow, which can improve the bearing capacity of plugging materials.

Severe lost circulation frequently occurs in deep and ultra-deep wells under high-temperature/high-pressure (HPHT) conditions and in fracture-cavity composite loss channels. Conventional lost-circulation materials (LCMs) often fail because of premature loss of mobility, insufficient residence in loss paths, and irreversible failure after solidification. Cement-based sealing systems, owing to their ability to plug large leakage channels and their cost-effectiveness, have become the mainstream solution. To improve their performance under extreme downhole conditions, recent studies have focused on base-cement design, reinforcement phases, and property regulation strategies-including the use of granular/fibrous/nanoscale additives for bridging reinforcement, rheology and thickening control to enhance injectability and residence, and chemical/functional modifiers to improve compactness and durability of the hardened matrix. Significant progress has been achieved in terms of HPHT resistance, densification design, regulation of rheological properties and thickening behavior, and self-healing/responsive sealing functions. However, most existing studies still focus on improving individual properties and lack a cross-scale, holistic design and unified mechanistic perspective for fracture-cavity coupled flow and long-term sealing stability. Distinct from previous reviews that mainly catalogue material types or discuss single-performance optimization, this review is framed by fracture-cavity composite loss channels and long-term sealing requirements under HPHT conditions, systematically synthesizes the material design strategies, reinforcement mechanisms and applicability boundaries of cement-based plugging systems, builds cross-scale linkages among these aspects, and proposes future research directions toward sustainable plugging design.

Bridging plugging is the most used method of plugging in unconventional oil reservoirs, and many factors affect the effect of bridging and plugging. Since the laboratory cannot simulate the actual leakage size of the lost formation and the corresponding leakage plugging process at the drilling site, the laboratory experiment results cannot reflect the actual leakage plugging construction effect. Aiming at the problem of frequent fracture leakage during drilling in Chepaizi block, Xinjiang, China, this paper proposes a set of machine learning methods based on a neural network. Three types of factors and 14 parameters with a strong correlation with the leakage control effect were screened out. Three categories of factors include construction parameters, choice of plugging material, and fluid properties of the carrier fluid. The training was carried out based on the collected field data, the appropriate activation function was set, and the deep well network structure was optimized. By improving the field plugging measures in the later period, the model was verified by these actual cases, and the results showed that the established model produced the highest of 0.974, has a good fit, and predicts well.

The ocean harbors vast potential for oil and gas resources, positioning offshore drilling as a critical approach for future energy exploration. However, high-temperature and high-pressure offshore reservoirs present formidable challenges, as conventional water-based drilling fluids are prone to thermal degradation and rheological instability, leading to wellbore collapse and stuck-pipe incidents. Offshore oil-based drilling fluids (OBDFs), typically water-in-oil emulsions, offer advantages in wellbore stability, lubricity, and contamination resistance, yet their stability under extreme high-temperature conditions remains limited. This study reveals the enhancement of offshore OBDFs performance in harsh conditions by employing nano-SiO₂ to synergistically improve emulsion film stability and non-Newtonian rheological behavior while systematically elucidating the underlying mechanisms. Nano-SiO₂ forms a composite film with emulsifiers, reducing droplet size, enhancing mechanical strength, and increasing thermal stability. Optimal stability was observed at an oil-to-water ratio of 7:3 with 2.5% nano-SiO₂ dispersion and 4.0% emulsifier. Rheological analyses revealed that nano-silica enhances electrostatic repulsion, reduces plastic viscosity, establishes a network structure that increases yield stress, and promotes pronounced shear-thinning behavior. Macroscopic evaluations, including fluid loss, rheological performance, and electrical stability, further confirmed the improved high-temperature stability of offshore OBDFs with nano-SiO₂ at reduced emulsifier concentrations. These findings provide a theoretical basis for optimizing offshore OBDFs formulations and their field performance, offering breakthrough technological support for safe and efficient drilling in ultra-high-temperature offshore reservoirs.

Deep acidic gas reservoirs have emerged as promising geological CO2 storage sites, driven by global carbon neutrality goals and advancements in carbon capture, utilization, and storage technologies. However, during drilling operations in these reservoirs, water-based drilling fluids are frequently contaminated by acidic gases like CO2, leading to severe rheological and filtration abnormalities that jeopardize wellbore stability. As the dispersion state of bentonite governs the performance of such fluids, this study investigates the structural and colloidal stability of bentonite suspensions under CO2-thermal coupling conditions, simulating contamination at 0.2–1 MPa and temperatures of 80–150 °C. Macroscopic fluid performance, colloidal stability, surface chemistry, and microstructural evolution were systematically analyzed. Results reveal a two-stage evolutionary mechanism: under mild CO2 intrusion, slight protonation of particle surfaces enhances the three-dimensional network, improving rheological and filtration properties. In contrast, severe contamination disrupts electrostatic equilibrium, triggering particle aggregation dominated by van der Waals forces and causing performance deterioration—a process exacerbated by elevated temperatures that accelerate particle migration. These findings elucidate the microstructural degradation pathways of bentonite under CO2-thermal coupling, offering theoretical insights for designing contamination-resistant drilling fluids in deep acidic gas reservoirs.

The Ordovician No. 6 fault zone reservoir in the Shunbei Oilfield exhibits ultra-deep-burial, high-pressure, and high-temperature conditions. Its pronounced tectonic control and significant heterogeneity render traditional in situ stress prediction methods—based on linear elasticity and anisotropy assumptions—inadequate for accurately characterizing the evolution and uncertainty of carbonate reservoir stiffness. Therefore, quantitatively predicting the development patterns and distribution characteristics of the Shunbei No. 6 structural fault zone is crucial for the exploration and development of Ordovician carbonate reservoirs in the Shunbei region. This study integrates wave impedance inversion with high-confining-pressure PFC particle flow biaxial test results to establish a constitutive calibration system consistent with seismic and experimental data. It introduces a nonlinear weakening function incorporating higher-order derivative constraints to fuse structural fracture and effective stress weakening effects, enabling dynamic correction of elastic parameters. This approach establishes a novel in situ stress prediction model. Simulation results indicate a predicted range for maximum horizontal principal stress between 201 and 261 MPa, with minimum horizontal principal stress ranging from 124 to 173 MPa. Predicted stress values for three key wells exhibit measurement errors within 6.92% compared to actual logging data, displaying a zoned spatial distribution consistent with regional tectonic stress evolution patterns. Simultaneously, sensitivity analysis reveals that the Young’s modulus fitting accuracy improved from 0.89 to 0.95, with a 43% reduction in mean square error, with the proportion of outliers reduced to below 1%. This significantly enhances response continuity and numerical stability in high-gradient disturbance zones and stiffness drop regions. The new model explicitly incorporates the nonlinear coupling between fracture geometry and pore pressure disturbance into the parameter field, eliminating systematic bias along fracture zones. Higher-order derivative constraints suppress numerical oscillations in high-gradient areas, stabilizing variance and preventing anomaly propagation. Residual distributions exhibit enhanced symmetry and reduced spatial autocorrelation, effectively suppressing numerical oscillations and divergence in complex fracture zones while significantly improving stress prediction accuracy for the study area. Overall, this research provides novel methodologies for predicting in situ stresses in ultra-deep carbonate reservoirs, offering engineering guidance and parameterization references for scheme deployment in complex fractured karst systems.