The development of a new drilling fluid system with hydrate inhibition is of great significance for drilling safety in gas hydrate-bearing sediments. Considering the importance of the selection of a suitable thickener for drilling fluid systems under weak and strong driving forces, the hydrate inhibition of 0.1–0.5 wt% modified starch (MS), carboxymethylcellulose sodium (CMC), and xanthan gum (XG) aqueous solutions was studied. The applicability of these three thickeners were investigated through hydrate formation experiments, mesostructure observations, water activity tests, bubble retention observations, and rheological property tests. The results show that (1) under weak driving force, 0.3 wt% or higher concentration CMC and 0.3 wt% XG can almost completely inhibit hydrate formation due to the interactions between relatively small amounts of free water and CH₄ molecules. Furthermore, the hydrate inhibition of higher XG concentrations was decreased due to their strong foam stability, leading to good contact between free water and CH₄ molecules. Meanwhile, the hydrate inhibition of MS was weaker when compared with that of CMC and XG at the same concentrations. (2) Under strong driving force, the existence of the three 0.1–0.5 wt% thickeners could only slow down the hydrate formation rate, and hydrate inhibition due to XG was slightly better than that of the other two. This result implies that the effects of the different mesostructures on hydrate formation were severely weakened. Finally, (3) the tackifying effect of CMC was found to be stronger than that of XG and MS, and the rheological properties of the CMC solution were shown to be relatively weak compared to those of the XG and MS solutions; the CMC solution showed a more significant increase in viscosity with decreasing temperature, which is related to the differences in the mesostructures. Therefore, when the driving force of hydrate formation is relatively low, CMC is a good choice for the drilling fluid system when there is no requirement for cooling, while XG is more applicable for a system that needs cooling. In the case of a stronger driving force, XG is the optimal choice irrespective of whether the drilling fluid system needs cooling or not.

To address the issues of traditional gels in high-temperature reservoir leakage plugging, such as injection–retention imbalance, poor high-temperature stability, and insufficient thixotropy, this study developed a thixotropic polymer gel system via molecular design and component optimization, aiming to achieve excellent thixotropy, high strength, and wide temperature adaptability (80–140 °C) while clarifying its gelation mechanism. First, the optimal polymer was selected by comparing the high-temperature stability and crosslinking activity of AM/AMPS copolymer (J-2), low-molecular-weight acrylamide polymers (J-3, J-4), and AM/AMPS/NVP terpolymer (J-1). Then, the phenolic crosslinking system was optimized: hexamethylenetetramine (HMTA) was chosen for controlled aldehyde release (avoiding poor stability/dehydration) and catechol for high crosslinking efficiency (enhancing strength via dense crosslinking sites). Urea–formaldehyde resin (UF) was introduced to form a “polymer-resin double network,” improving high-temperature compression resistance and long-term stability. Cyclic shear rheological tests showed the gel system had a larger hysteresis area than the polymer solution, indicating excellent thixotropy before gelation. It gelled completely at 80–140 °C (gelation time shortened with temperature). At 120 °C, its viscosity was 7500 mPa·s, storage modulus (G′) 51 Pa, and loss modulus (G″) 6 Pa, demonstrating good shear thixotropy. The final system (1% J-1, 0.3% catechol, 0.6% HMTA, 15% UF) is suitable for high-temperature reservoir leakage plugging.

Shale inhibitor is an additive for drilling fluids that can be used to inhibit shale hydration expansion and dispersion, and prevent wellbore collapse. Small molecular quaternary ammonium salt can enter the interlayer of clay crystal, and enables an excellent shale inhibition performance. In this paper, a novel ionic shale inhibitor, triethylammonium acetate (TEYA), was obtained by solvent-free synthesis by using acetic acid and triethylamine as raw materials. The final product was identified as the target product by Fourier transform infrared spectroscopy (FT-IR). The inhibition performance of TEYA was studied by the mud ball immersion test, linear expansion test, rolling recovery test and particle size distribution test. The results demonstrated that the shale inhibitor shows a good shale hydration inhibition performance. The inhibition mechanism was studied by FT-IR and X-ray diffraction (XRD), respectively; the results showed that triethylammonium acetate TEYA could enter the crystal layer of clay and inhibit it through physical adsorption.

The stability of deep marine shale wellbores is influenced by both bedding anisotropy and drilling fluid intrusion. Existing models fail to adequately account for the coupled effects of intrusion depth and strength degradation. This study, targeting Longmaxi Formation shale, established a collapse pressure prediction model incorporating drilling fluid intrusion depth through direct shear tests and nuclear magnetic resonance (NMR) techniques. Experimental results indicate that shear strength reaches its minimum at β = 45°, decreasing by approximately 60% compared to β = 0° or 90°. Intrusion causes exponential decay in bedding plane strength, with the cohesion degradation coefficient λ_c = 0.158 mm⁻¹ significantly exceeding the internal friction angle degradation coefficient λ_φ = 0.089 mm⁻¹. Sensitivity analysis indicates that bedding angle and invasion depth rank third (±3%) and fourth (±1.5%), respectively, in influencing collapse pressure. Field validation confirmed excellent model prediction accuracy (R² = 0.956; RMSE = 0.55 MPa; MAPE = 1.05%), with all errors below 4%. This model accurately predicts the time-varying characteristics of collapse pressure, providing a theoretical basis for optimizing the design of drilling fluid density.