Shale gas development is key to the low-carbon transition of the global energy industry. However, wellbore instability caused by fluid-rock interactions remains a major technical bottleneck, resulting in significant economic losses worldwide. Conventional wellbore stabilization strategies have proven ineffective in mitigating the structural degradation of shale. This study proposes a novel approach that enhances wellbore stability through chemical cementation between invading fluids and the shale matrix. Using KH550, KH560, and sodium methyl silicate (SMS) as model compounds, the cementation mechanisms were systematically investigated. Multi-scale characterizations—including FTIR, XPS, TGA, SEM-EDS, low-temperature nitrogen adsorption, uniaxial compressive strength (UCS) testing, and ultrasonic measurements—revealed that these agents undergo condensation reactions with shale surface groups, forming rigid Si–O–Si and Al–O–Si frameworks within the pore-fracture network. The resulting organic–inorganic interfacial layer effectively seals micropores and mesopores, reducing total pore volume and specific surface area while smoothing pore surfaces (decreased D1) and simplifying pore network complexity (decreased D2). Macroscopic mechanical tests showed that chemical cementation significantly alleviates hydration-induced strength loss, with UCS increasing by 8.0%–51.6% and elastic modulus by 21.4%–46.2% compared to water-treated controls. Ultrasonic wave velocities increased and attenuation coefficients decreased, indicating structural densification. Cementation efficiency followed SMS > KH560 > KH550, consistent with molecular structure and reactivity. This study verifies the feasibility of the wellbore stabilization strategy that converts the hydration effect of drilling fluid on shale into chemical cementation to improve shale structure and strength. It also provides theoretical support and experimental basis for the subsequent development of new additives for water-based drilling fluids with chemical cementing performance.
Oil and gas transmission pipelines in landslide-prone areas are exposed to time-varying internal pressure, lateral soil loading, and geometric/material discontinuities at unequal-wall-thickness girth welds, making dynamic reliability assessment difficult. Existing magnetic test methods can capture stress-related responses without excavation, yet they still lack a physics-based and probabilistic mapping from measured magnetic signals to failure risk. This study proposes a physics-informed dynamic reliability framework for landslide-prone girth welds. A multi-zone forward model coupling landslide-pipeline mechanics, plane-stress magnetization, and magnetic dipole theory is established to quantify the relation between stress evolution and far-field magnetic gradient signals. Based on this measurement model, a Wiener-process-based state evolution model is used to represent signal growth during the landslide incubation stage, and time-dependent failure probability is evaluated through a signal-based limit-state function and first-passage theory. Experiments show that the forward model yields a deviation below 5%, and field monitoring confirms a magnetic stress sensitivity of 17.5 (nT/m)/MPa. In the case study, the predicted 7-, 14-, and 30-day failure probabilities are 0%, 0.81%, and 32.67%, respectively, supporting timely mitigation of the hazardous slope section. The framework provides a probabilistic route from non-contact magnetic monitoring to dynamic integrity management of landslide-prone pipeline sections.
Matrix acidizing is one of the most widely used stimulation techniques for deep carbonate oil and gas reservoirs. However, the rapid generation of CO2 during the acid-rock reaction often leads to simpler wormhole morphology, limited stimulation volume, and premature fluid breakthrough, thereby becoming a key factor restricting acidizing efficiency. Although previous studies have mainly explained wormhole formation in terms of acid strength, acid system, and injection parameters, a systematic understanding is still lacking of how CO2 generation and its phase behavior during the acid-rock reaction influence flow-path selection and wormhole evolution. To address this knowledge gap, this study proposes a strategy to improve wormhole formation efficiency during carbonate acidizing by mitigating CO2-induced gas-liquid two-phase flow and the associated capillary resistance. Based on this concept, a two-stage acidizing approach is developed, in which a chelating-agent pretreatment is first used to create a stable microfracture network and multichannel flow pathways, thereby reducing local reaction intensity and weakening the capillary resistance induced by rapid CO2 generation. This is followed by strong-acid injection, which promotes the development of more complex wormhole structures under more uniform flow conditions. Core-scale flow experiments combined with microfluidic visualization experiments were conducted to systematically investigate, from the macroscopic to the pore scale, the effects of CO2 generation rate and phase behavior on displacement pressure response, flow-path selection, and wormhole morphology evolution. The results show that rapid CO2 generation significantly intensifies pressure fluctuations and induces premature breakthrough, resulting in wormhole structures dominated by a single primary channel. In contrast, mitigating CO2-induced interference markedly improves flow stability and promotes wormhole branching and networked development. These findings provide new mechanistic insights into achieving efficient matrix acidizing in deep carbonate reservoirs and may also offer a useful reference for understanding CO2 multiphase flow and phase behavior in porous media within the broader CCUS context.
The blowout preventer (BOP) is critical for ensuring oil and gas well safety, but its main sealing components are susceptible to crack-type leakage during well shut-in, posing significant risks. Limited research on temporary plugging using particle injection has hindered process development. Based on the actual blowout conditions (10–70 MPa) and the size of BOP, this paper establishes a simulation model and builds an experimental platform to analyze the effects of particle concentration, size, shape, elastic modulus, friction coefficient and well pressure on the plugging effect. The results show that the plugging process primarily depends on a small amount of strong chains to withstand fluid drag. Furthermore, conventional downhole plugging theories (D50 and D90) are not fully applicable to wellhead conditions. At 70 MPa, single-particle bridging shows optimal plugging performance. The research results provide theoretical support for the process parameters and plugging formula of particle plugging.
During the drilling of deep and ultra-deep oil and gas wells, fracture leakage under high temperature and high pressure conditions often involves large flow channels and low sealing reliability. Conventional mineral bridging materials usually have high density, tend to settle easily, and lack sufficient thermal and mechanical resistance, which limits their field application. To overcome these problems, a low-density and high-strength rigid epoxybased plugging material named HHN was developed through melt polymerization. Bisphenol A epoxy resin HYA was used as the matrix, while epoxy crack sealant component HYB and 1,8-diaminonaphthalene served as curing agents. The structure, performance, and microscopic sealing mechanism of the prepared material were systematically investigated. FT-IR analysis showed that the characteristic epoxy peak at 915 cm(-1) disappeared, while new absorption peaks corresponding to N-H at 3338 cm(-1) and C-N at 1232 cm(-1) appeared. XPS results further revealed the presence of C-N, C-O, and hydroxyl-related peaks. These findings confirm that the epoxy and amine groups underwent a ring-opening reaction, leading to the formation of a cross-linked network structure. The density of the material is 1.12 g per cubic centimeter. Uniaxial compression testing demonstrated a peak compressive strength of 110 MPa. Even at a strain of approximately 30.45 percent, no obvious fragmentation was observed, indicating both high strength and good toughness. Thermogravimetric analysis showed that significant thermal degradation began at 323.36 degrees C, suggesting satisfactory thermal stability for high-temperature environments. Sedimentation tests indicated that fine particles in size grades C and D showed almost no settling in the base slurry, while type A particles achieved a suspension rate of 83.3 percent. In addition, when added at concentrations between 1 percent and 4 percent, the material caused only minor changes in the rheological properties of the drilling fluid, demonstrating good compatibility with the fluid system. Scanning electron microscopy revealed that the particles had a multi-faceted rhombic shape with rough surfaces. This morphology favors mechanical interlocking within fractures and contributes to the stable formation of a sealing layer. Furthermore, a multi-level fracture migration and bridging model was established using CFD-DEM simulation. The results indicate that stable bridging occurs when the particle diameter D satisfies condition 0.67W less than D less than W, where W represents the fracture width. This relationship provides guidance for particle size design under multi-scale fracture conditions. Overall, HHN combines low density, good heat resistance, and high compressive strength. It offers a promising new material option and theoretical support for controlling hightemperature and high-pressure fracture leakage in deep wells.
