Here, we report a water-soluble shale inhibitor for inhibiting shale hydrate formation. The copolymer denoted as thermogravimetric analysis (TGA) was synthesized via triethanolamine, two maleic anhydrides, and glacial acetic acid. The infrared (IR) and gas chromatography (GC) results indicated that TGA is a low molecular weight polymer inhibitor (IR) and is the most commonly used method to identify compounds and molecular structures qualitatively. It is mainly used to study the molecular structure of organic substances and conduct qualitative and quantitative analyses of organic compounds. The main function of GC is for polymer molecular weight analysis. With the aid of shale rolling recovery experiments, particle size distribution experiments, triaxial stress experiment methods, bentonite slurry rate inhibition experiments, and thermogravimetric experiments to evaluate TGA inhibition characteristics, the inhibition effect of TGA is better than that of the traditional inorganic salt inhibitor KCl, polymer amine inhibitor UHIB, and organic cationic shale inhibitor NW-1. When the mass fraction is 0.2%, the cutting recovery rate increases from 18.3 to 94.1%. The compressive strength of the shale core after adding 1% TGA inhibitor is 177.9 MPa, which is close to the original core compressive strength of 186.5. The wet sodium montmorillonite crystal layer spacing after treatment with 0.5%, 1.5%, and 3% TGA aqueous solution is 1.38, 1.35, and 1.35 nm, respectively, and the sodium montmorillonite crystal layer spacing after diesel treatment is 1.34 nm, indicating that the inhibitory effect of TGA on sodium montmorillonite is equivalent to that of diesel and that TGA can effectively inhibit the hydration and dispersion of sodium montmorillonite. At the same time, the crystal layer spacing and the weight loss rate of sodium montmorillonite modified by TGA inhibitors did not change significantly after adsorption of deionized water, which proved that TGA inhibitors could be adsorbed in the crystal layer space of sodium montmorillonite to inhibit hydration and dispersion of sodium montmorillonite. Field test results show that TGA can significantly improve the inhibition performance of the field drilling fluid, and the effect is better than the strong conventional inhibition water-based drilling fluid system, which solves the problems of wellbore instability and considerable friction in horizontal shale sections and provides a new idea and method for efficient shale gas drilling.

In this paper, nano plugging agent AMPS/AM was prepared, and its plugging performance was evaluated by a microfracture simulation experiment and a shale pressure resistance experiment. The pressure loss decreased by 66.09% compared with the top pressure of 6.9 MPa, and the average core indentation hardness increased 58.12% with 3% AMPS/AM blocking mud. The experiments indicate that AMPS/AM can effectively seal the shale micropore and nanopore structure and greatly improve the stability of fractured shale well wall. The field application results of the YS129H well in the Zhaotong block show that the water-based drilling fluid with nano plugging agent AMPS/AM as the key agent has strong plugging performance. The well mud is of high temperature and pressure water loss < s4 mL, mud cake permeability reduction rate of 85.67%, which indicates that the drilling fluid system has good sealing properties and well wall stability.

Despite the current demand for shale gas development, there is no means to evaluate nanoscale microfracture plugging technologies for ultra-low permeability formations. In this paper, we expand upon previous research and develop new means to create artificial fractures in model mud cake. By controlling the mud cake quality and strength, we developed mud cake with permeability that approached that of real mud shale. Low-permeability mud cake was prepared from barite powder, calcium carbonate, polyacrylamide, sodium polyacrylate, water, silica, a polycarboxylate comb macromolecule, a double sparse inhibitor, a film-forming agent and a mud cake curing agent. The mud cake permeability reached 5.9 × 10^–4 mD and increased with soaking time to 1.3 × 10^–3 mD (240 h). The equivalent opening of a single fracture did not change greatly and remained in the range from 3.93 × 10^–5 m to 4.93 × 10^–5 m. Plugging performance was evaluated by simulating microfractures and low-permeability environment of the formation. This method provides very important guidelines for the selection and development of nanoscale and microscale plugging agents and the evaluation of the plugging effect. It is also applicable to the evaluation of plugging performance in other fractured formations.

Due to the low permeability of shales, drilling fluid filtrate is very likely to intrude into the formation along the nanomicron pore joints of shale, leading to microfracture expansion and causing a well wall destabilization phenomenon. Based on the characteristics of the formation shale, a new nano plugging agent, styrene (St)/2-acrylamido-2-methylpropanesulfonic acid (AMPS)/ethyl acrylate (EA), was synthesized by emulsion polymerization using St, EA, and AMPS as reaction monomers. The analysis results using infrared spectroscopy and transmission electron microscopy showed that the product met the expected design. The particle size of the nano plugging agent St/AMPS/EA was mainly concentrated in the range of 50–130 nm. Thermogravimetric analysis revealed that the initial thermal decomposition temperature of St/AMPS/EA is 363.8 °C, indicating strong thermal stability. At a 3% concentration, the permeability of the mud cake decreased by 87.35%, and the maximum differential stress of the shale increased from 141.7 to 174.4 MPa. Stability analysis showed that the plugging agent maintained good plugging performance under various pH values and salinity conditions with fluid loss consistently around 3.2 mm. This nano plugging agent significantly improves wellbore stability, making it suitable for drilling in the Longmaxi Formation shale with developed microfractures, and provides valuable insights for similar formations.

Hypothesis: Poor interfacial bonding and wetting incompatibility limit the performance of degradable liquid plugs under high-pressure conditions. It is hypothesized that silane-induced interfacial engineering can build a multiscale structure that enhances adhesion via coupled wetting, penetration, and interlocking mechanisms. Experiments: A C18 silane-modified steel surface was constructed and tested for its bonding behavior with an epoxy-based degradable plug. Interfacial strength, compressive capacity, and microstructure were analyzed using mechanical tests, SEM, AFM, and contact angle measurements. Surface energy was calculated via the Owens–Wendt model. Findings: The silane-treated interface exhibited a significant enhancement in interfacial bonding strength (up to 445%) and shear strength (73.8% increase), attributed to the formation of a 391.6 nm thick infiltrated interlayer and strong chemical anchoring (Si–O–Fe bonds). Contact angle decreased from 74.0° to 53.6°, with interfacial energy increasing by 26.2%, confirming improved wettability and energy compatibility. A triadic enhancement pathway of “wetting–penetration–interlocking” was established, supported by microstructural imaging and theoretical modeling. This work provides mechanistic insights and practical guidance for the design of robust liquid plug systems in complex wellbore environments.

In this study, a novel semi-liquid gel material based on bisphenol A-type epoxy resin (E51), methylhexahydrophthalic anhydride (MHHPA), and epoxidized soybean oil (ESO) was developed for high-performance wellbore sealing. The gel system exhibits tunable gelation times ranging from 1 to 10 h (±0.5 h) and maintains a low viscosity of <100 ± 2 mPa·s at 25 °C, enabling efficient injection into the wellbore. The optimized formulation achieved a compressive strength exceeding 112.5 ± 3.1 MPa and a breakthrough pressure gradient of over 50 ± 2.8 MPa/m with only 0.9 PV dosage. Fourier transform infrared spectroscopy (FTIR) confirmed the formation of a dense, crosslinked polyester network. Interfacial adhesion was significantly enhanced by the incorporation of 0.25 wt% octadecyltrichlorosilane (OTS), yielding an adhesion layer thickness of 391.6 ± 12.7 nm—approximately 9.89 times higher than that of the unmodified system. Complete degradation was achieved within 48 ± 2 h at 120 °C using a γ-valerolactone and p-toluenesulfonic acid solution. These results demonstrate the material’s potential as a high-strength, injectable, and degradable sealing solution for complex subsurface environments.