Addressing the high friction and torque challenges encountered in drilling processes for high-displacement wells, horizontal wells, and directional wells, we successfully synthesized OAG, a high-temperature and high-salinity drilling fluid lubricant, using materials such as oleic acid and glycerol. OAG was characterized through Fourier-transform infrared (FTIR) spectroscopy and thermogravimetric analysis (TGA). The research findings demonstrate the excellent lubricating performance of OAG under high-temperature and high-salinity conditions. After adding 1.0% OAG to a 4% freshwater-based slurry, the adhesion coefficient of the mud cake decreased to 0.0437, and at a dosage of 1.5%, the lubrication coefficient was 0.032, resulting in a reduction rate of 94.1% in the lubrication coefficient. After heating at 200 °C for 16 h, the reduction rate of the lubrication coefficient reached 93.6%. Even under 35% NaCl conditions, the reduction rate of the lubrication coefficient remained at 80.3%, indicating excellent lubrication retention performance. The lubricant OAG exhibits good compatibility with high-density drilling fluid gel systems, maintaining their rheological properties after heating at 200 °C and reducing filtration loss. The lubrication mechanism analysis indicates that OAG can effectively adsorb onto the surface of N80 steel sheets. The contact angle of the steel sheets increased from 41.9° to 83.3° before and after hot rolling, indicating a significant enhancement in hydrophobicity. This enhancement is primarily attributed to the formation of an extreme-pressure lubricating film through chemical reactions of OAG on the metal surface. Consequently, this film markedly reduces the friction between the drilling tools and the wellbore rocks, thereby enhancing lubrication performance and providing valuable guidance for constructing high-density water-based drilling fluid gel systems.

Modified starch and other natural polymer materials have found extensive applications in drilling fluids. However, conventional modification methods offer limited scope for further enhancing their temperature resistance, typically with the applicable temperature being below 140 °C. This paper presents the preparation of composite plant phenols using walnut shells, peanut shells, straw, and lignin, which are rich in the fundamental “three elements” of plants. To explore the improvement of the temperature resistance of cellulose-based drilling fluid additives, this study investigated the apparent viscosity, dynamic shear force, filtration performance, and adhesion coefficient of water-based drilling fluids supplemented with composite plant phenols. Additionally, the mechanism of action of the composite in drilling fluids was analyzed via infrared spectroscopy. The results revealed that the combined use of starch and composite plant phenols elevated the temperature resistance limit of starch from 160 °C to 180 °C. After aging at 180 °C, the filtration loss of the drilling fluid formulation containing composite plant phenols dropped to 3.6 mL, while the apparent viscosity climbed from 3.1 mPa·s to 13.6 mPa·s. This clearly demonstrates the excellent high-temperature resistance and filtration-reducing capabilities of composite plant phenols. When the addition of cassava starch was 2%, the filtration loss of the drilling fluid system reached a minimum of 6.2 mL. A positively charged gel was identified as the optimal high-temperature-resistant cutting agent. At a dosage of 1%, the dynamic plastic ratio of the formulation increased from 0.51 to 2.11. Tannin extract emerged as the ideal high-temperature-resistant and environmentally friendly drilling fluid treatment agent. After its addition, the apparent viscosity of the drilling fluid system increased from 2.4 mPa·s to 7.3 mPa·s, and the filtration loss decreased from 140 mL to 14.6 mL.

Conventional fracturing fluids, while essential for large-volume stimulation of unconventional reservoirs, often induce significant reservoir damage through water retention and capillary trapping. To address this problem, this study developed a novel superhydrophobic nano-viscous drag reducer (SN-DR), synthesized through a multi-monomer copolymerization and silane modification strategy, which enhances structural stability and minimizes reservoir damage. The structure and thermal stability of SN-DR were characterized by FT-IR, ¹H NMR, and TGA. Rheological evaluations demonstrated that the gel fracturing fluid exhibits a highly stable three-dimensional network structure, with a G′ maintained at approximately 3000 Pa and excellent shear recovery under cyclic stress. Performance tests showed that a 0.15% SN-DR achieved a drag reduction rate of 78.1% at 40 L/min, reduced oil–water interfacial tension to 0.91 mN·m⁻¹, and yielded a water contact angle of 152.07°, confirming strong hydrophobicity. Core flooding tests revealed a flowback rate exceeding 50% and an average permeability recovery of 86%. SEM and EDS indicated that the gel formed nanoscale, tightly packed papillary structures on core surfaces, enhancing roughness and reducing water intrusion. The study demonstrates that gel fracturing fluid enhances structural stability, alters wettability, and mitigates water-blocking damage. These findings offer a new strategy for designing high-performance fracturing fluids with integrated drag reduction and reservoir protection properties, providing significant theoretical insights for improving hydraulic fracturing efficiency.

Fracture-induced loss poses severe challenges to drilling operations, particularly under high-temperature and high-salinity conditions encountered in deep wells. Conventional plugging materials, characterized by relatively large particle sizes and poor structural integrity, often exhibit insufficient thermal stability and salt tolerance under extreme drilling conditions, making them prone to structural degradation and loss of adhesion, which ultimately leads to drilling fluid deterioration and downhole complications. To address this issue, a core–shell-structured microgel, ANDT-70 (named after the acronyms of 2-acrylamido-2-methylpropane sulfonic acid, N-vinyl-2-pyrrolidinone, N, N-dimethylacrylamide, dimethyl diallyl ammonium chloride, and titanium dioxide nanoparticles), was synthesized and systematically evaluated for its thermal stability, salt resistance, and interfacial adhesion capabilities. The structural evolution, dispersion behavior, and colloidal stability of the microgel were thoroughly characterized using scanning electron microscopy (SEM), transmission electron microscopy (TEM), atomic force microscopy (AFM), Raman spectroscopy, and Zeta potential analysis. Experimental results indicate that ANDT-70 exhibits excellent thermal stability and resistance to salt-induced degradation at 260 °C, maintaining its fundamental structure and performance under harsh high-temperature and high-salinity conditions, with a viscosity retention of 81.10% compared with ambient conditions. Compared to representative materials reported in the literature, ANDT-70 exhibited superior tolerance to ionic erosion in saline conditions. AFM analysis confirmed that ANDT-70 significantly improves bentonite slurry dispersion and reduces salt sensitivity risks. ANDT-70 stably adsorbs onto bentonite lamellae via the synergistic action of electrostatic interactions and hydrogen bonding, thereby forming a dense cementation network that markedly enhances the structural stability and adhesion of the system. This network significantly enhances the cohesion and structural integrity of drilling fluid systems under extreme conditions. In conclusion, ANDT-70 demonstrates strong potential as a high-performance functional microgel for enhancing the stability and effectiveness of advanced drilling fluids under complex geological environments.

The fracturing development of low-permeability and ultra-low-permeability oil and gas reservoirs urgently requires a fracturing fluid that combines high performance and low damage. To overcome this challenge, this study synthesized a novel polyamine boron crosslinker (PBC) suitable for 0.2% guar gum. The molecular structure was characterized by Fourier transform infrared spectroscopy (FT-IR) and nuclear magnetic resonance hydrogen spectroscopy (¹H NMR). Meanwhile, this study introduced the response surface methodology and established a second-order regression model to determine the optimal synthesis conditions (polyetheramine 10.8 g, n-butanol 7.4 g, and ethylene glycol 20.7 g) with a model prediction error of only 0.7%. The results indicated that PBC exhibited excellent performance in 0.2% guar gum. The viscosity of crosslinked gel fracturing fluid remained stable at approximately 100 mPa·s under 60 °C and 100 s⁻¹ shear. The wall forming filtration coefficient was 2.30 × 10⁻⁴ m/s^1/2, and the initial filtration was 1.30 × 10⁻³ m³/m². The static settling rate was 2.4 cm·min⁻¹, demonstrating good suspended sand capacity. Furthermore, the synergistic interaction between borate ester bond and polyetheramine in the PBC conferred dynamic reversible crosslinking and uniform network formation. This enabled high-strength, low-damage crosslinking effects at low concentrations. This study provides an efficient crosslinker solution for 0.2% guar gum, holding both theoretical and engineering significance for advancing the low-cost development of fracturing fluid.