Effects of Oxide Particle Size, Type, and Polymer Incorporation Methods on the Performance of Fluid Loss Additives for High-Temperature and High-Salinity Drilling Fluids

In recent years, polymer–oxide composite materials have attracted significant research interest for high-temperature and high-salinity oil and gas reservoirs due to their unique interfacial regulation capabilities. However, existing studies have predominantly focused on the effects of oxide particles (mostly nanoparticles), with limited comparative analysis of variations in oxide particle composition, size distribution, and composite strategies. To address this gap, three types of fluid loss additives were synthesized using the NP-3 formulation to systematically evaluate the effects of oxide particle type (SiO2, ZnO, TiO2, CuO, MgO), size (20–500 nm), and polymer incorporation methods (physical encapsulation, chemical grafting, and physical blending) on drilling fluid performance. The structural evolution of both drilling fluids and fluid loss additives before and after hot-rolling was characterized using particle size distribution, zeta potential analysis, contact angle measurement, Fourier transform infrared spectroscopy (FT-IR), nuclear magnetic resonance hydrogen spectroscopy (1H NMR), scanning electron microscopy (SEM), and transmission electron microscopy (TEM). The results demonstrate that graft copolymerization significantly enhances thermal stability by forming covalent linkages between the polymer and modified oxide particles, preserving a functional network even after partial degradation at elevated temperatures. This network stabilizes the dispersed oxide particles. These particles, when optimally sized, effectively seal micropores in the filter cake and inhibit filtrate invasion. Notably, graft copolymerization combined with approximately 100 nm TiO2 or SiO2 yields the best high-temperature, high-pressure (HTHP) fluid-loss performance, resulting in filtrate volumes below 30 mL at 230 °C in 15 wt % NaCl; the TiO2-based additive achieved as low as 13.4 mL. Furthermore, when used with bentonite that has a high methylene blue capacity (CMBT-B > 25.2 mequiv/100 g), fluid stability was maintained even at 240 °C. These findings provide a robust foundation for the rational design of high-performance fluid loss additives tailored for deep and ultradeep well drilling.