The ice sheet and subglacial geological environment in Antarctica have become the focus of scientific exploration. The development of Antarctic drilling technology will serve as a crucial safeguard for scientific exploration. However, the extremely ultra-low temperatures and intricate geological conditions present substantial obstacles for drilling operations in Antarctica, and the existing drilling fluid technology cannot satisfy the requirements of efficient and safe drilling. To ameliorate the wettability and rheology of ultra-low-temperature drilling fluids, a new amide material (HAS) was prepared using dodecylamine polyoxyethylene ether, azelaic acid, and N-ethylethylenediamine as raw materials. Experiments using infrared spectroscopy, nuclear magnetic hydrogen spectroscopy, and contact angle indicated that the target product was successfully synthesized. Performance evaluation showed that 2% HAS could achieve a yield point of 2.5 Pa for drilling fluid at −55 °C, and it also gave the fluid superior shear-thinning characteristics and a large thixotropic loop area. This indicated that HAS significantly enhanced the rheological properties of the drilling fluid, ensuring that it can carry cuttings and ice debris. In addition, 2% HAS could also increase the colloidal rate from 8% to more than 76% at −55 °C in different base oils. Meanwhile, the colloid rate was maintained above 92.4% when the density was 0.92~0.95 g/cm³. Mechanism studies showed that HAS increased the zeta potential and decreased the particle size of organoclay. At the same time, it changed the organoclay state from a clustered state to a uniformly dispersed state, and the particle size decreased. It was found that HAS formed a weak gel grid structure through interactions between polar groups, such as amide and imino groups with organoclays particles, thus improving the rheology and wettability of drilling fluid. In addition, HAS is an environmentally friendly high-performance material.

With the continuous expansion of ultra-deep and deep well drilling toward complex geological formations, the performance stability of water-based drilling fluids and wellbore stability under ultra-high temperature and high-salinity conditions have become critical challenges. High temperature and salt contamination can induce the degradation or failure of drilling fluid additives, while the development of pores and fractures in complex formations further increases the risk of filtrate invasion. Conventional polymer and inorganic plugging agents often suffer from insufficient thermal stability, poor salt tolerance, or limited adaptability to complex pore structures. In this study, an organic–inorganic hybrid gel microsphere plugging agent (HGP) with a core–shell structure was developed by in situ polymerization of AMPS, styrene (St), and sodium styrene sulfonate (SSS) on KH570-modified nano-SiO₂. The hybrid microspheres consisted of a rigid SiO₂ core and a flexible polymer shell, providing synergistic thermal stability, mechanical strength, and deformation capability. Structural characterization confirmed the successful formation of the designed organic–inorganic hybrid structure. After aging at 240 °C, HGP maintained stable morphology and dispersion characteristics, while exerting minimal influence on drilling fluid rheological properties. The addition of 3 wt% HGP reduced API fluid loss by approximately 30% and decreased sand bed invasion by approximately 50% after high-temperature aging. Under 35 wt% NaCl and 5 wt% CaCl₂ contamination, HGP maintained effective filtration control, reducing fluid loss by more than 50% compared with the base fluid. Furthermore, HGP achieved core plugging efficiencies above 94% and reduced mud cake permeability by over 70%, demonstrating superior plugging performance compared with polymer microspheres NF-1 and SiO₂ particles. The enhanced performance was considered to arise from the synergistic effects of stable dispersion, pore-throat bridging, deformation filling, and structural stabilization. This study provides a rigid–flexible hybrid strategy for designing high-performance plugging agents for ultra-high temperature and high-salinity water-based drilling fluids.

Polymeric gel fluid-loss reducers for water-based drilling fluids often undergo performance deterioration under combined high-temperature and high-salinity conditions. In this study, an organic–inorganic nanocomposite gel fluid-loss reducer, SiO₂@P-DAS, was synthesized through aqueous free-radical polymerization using N,N-dimethylacrylamide, 2-acrylamido-2-methylpropane sulfonic acid, sodium styrene sulfonate, and KH-570-modified nano-SiO₂. The corresponding polymer gel without nano-SiO₂, P-DAS, was used as the control. FTIR results were consistent with the presence of modified nano-SiO₂ in the composite gel. Thermogravimetric analysis showed that its initial decomposition temperature increased from 245 °C for P-DAS to 252 °C for SiO₂@P-DAS. At a concentration of 3.0 wt%, the post-aging API filtrate volume of SiO₂@P-DAS was 3.8 mL, compared with 4.8 mL for P-DAS after aging at 220 °C for 16 h. Under HTHP conditions of 220 °C and 3.5 MPa, the corresponding filtrate volumes were 33.33 and 49.67 mL, respectively. SiO₂@P-DAS also maintained lower fluid loss under NaCl and CaCl₂ contamination. At 5 wt% CaCl₂, its post-aging API filtrate volume was 6.8 mL, 58.0% lower than that of P-DAS. In weighted drilling fluids with densities of 1.4–2.0 g/cm³, the post-aging API and HTHP filtrate volumes remained within 2.4–3.2 and 24.6–26.2 mL, respectively. Zeta-potential, particle-size, and filter-cake observations suggest that polymer adsorption and hydration, together with the contribution of modified nano-SiO₂ to particle packing and filter-cake continuity, improve filtration control. These results demonstrate the potential of SiO₂@P-DAS as a nanocomposite gel fluid-loss reducer for high-temperature and salt-contaminated water-based drilling fluids.