Improving the chemical structure of the cross-linker is a potential method for reducing reservoir pollution and enhancing the fracturing efficiency of shale reservoirs. In this investigation, a three-dimensional (3-D) spherical cross-linker comprising branched chains was synthesized, and the 3-D structure of the cross-linker was analyzed through scanning electron microscopy (SEM). Furthermore, we constructed a multifunctional coupled collaborative evaluation device that can be used to evaluate numerous properties associated with water-based fracturing fluids, including fluid viscosity, adsorption capacity, and water pollution. Meanwhile, the influence of varying reservoir conditions and cross-linker content on the fluid viscosity of water-based fracturing fluids and the potential for reservoir contamination has been evaluated and elucidated. The results indicated that the synthesized cross-linker exhibited a superior environmental protection of the shale reservoir and an enhanced capacity for thickening fracturing fluids in comparison to commercial cross-linkers. Moreover, cross-linker content, reservoir temperature, reservoir pressure, and fracture width can affect fluid viscosity and reservoir residual in different trends. The addition of 0.3% nano-cross-linker (Synthetic products) to a water-based fracturing fluid resulted in an apparent viscosity of 160 mPa·s at 200 °C, and the adsorption capacity and water content of the shale reservoir were only 0.22 µg/m³ and 0.05 µg/L, respectively. Additionally, an elevation in reservoir temperature resulted in a reduction in the adsorption capacity. However, the cross-linker content in groundwater underwent a notable increase, and the cross-linker residue in water increased by 0.009 µg/L. The impact of reservoir pressure on fluid viscosity and groundwater pollution potential exhibited an inverse correlation compared to that of reservoir temperature, and the above two parameters changed by +18 mPa·s and −0.012 µg/L, respectively. This investigation provides basic data support for the efficient fracturing and reservoir protection of shale reservoirs.

This study developed a bio-based fluid loss reducer based on itaconic acid-grafted corn starch (IACS) for water-based drilling fluid systems. The product was synthesized through free radical graft copolymerization and characterized by FTIR, TGA, and SEM. In bentonite-based mud systems, IACS demonstrated excellent filtration control performance significantly superior to that of conventional fluid loss reducers such as PAM, CMC, and PAC. IACS exhibited outstanding temperature resistance, salt tolerance, and calcium contamination resistance. Particle size analysis revealed that IACS effectively dispersed bentonite particles to the nanoscale at elevated temperatures, preventing thermal aggregation. Mechanistic studies indicated that carboxyl groups introduced by the grafting reaction endowed IACS with strong adsorption capacity and hydration ability, forming a dense polymer network layer on clay particle surfaces. Environmental evaluation confirmed that IACS possessed moderate biodegradability and extremely low toxicity, meeting green drilling fluid additive requirements. This study provides new insights for developing high-performance, environmentally friendly fluid loss reducers.

To overcome the limited mechanical strength and poor stability of conventional gels in high-temperature, high-salinity oilfield environments, a novel nanocellulose-reinforced hydrogel (AM/AA/PCNF) was developed through a multistep chemical modification strategy. Nanocellulose served as a rigid backbone and was successively modified via epoxide ring-opening, methacryloyl esterification, and polydopamine functionalization, forming a three-dimensional network with multiple dynamic crosslinking interactions. The resulting composite hydrogel exhibited outstanding comprehensive properties when the PCNF content was 3 wt%: a tensile strength of 2.6 MPa, fracture energy of 8.95 MJ/m³, and compressive strength of 360 kPa—all markedly superior to those of conventional hydrogel systems. Under simulated downhole conditions (120 °C, 6 MPa, and 5 wt% salinity), the hydrogel demonstrated excellent plugging performance across sand beds of varying particle sizes (60–80 mesh to 20–40 mesh), maintaining cumulative fluid loss within 28.4–42.5 mL. Mechanistic investigations indicate that the enhanced performance stems from the synergistic combination of a rigid nanocellulose scaffold and multiple dynamic interactions, which facilitate a self-adaptive plugging mechanism. The study delivers both theoretical and practical foundations for designing advanced plugging systems.

Maintaining wellbore stability in deep and ultra-deep formations demands plugging agents capable of sealing nano- to micro-scale pores under high-temperature conditions. A core–shell nano-plugging agent (CSP) was synthesized via emulsion polymerization using KH-570-modified nano-SiO₂ as the rigid core and a poly(styrene-co-butyl acrylate-co-methyl methacrylate) terpolymer as the deformable shell. CSP particles had a mean diameter of 196.5 nm (polydispersity index, PDI = 0.183) and an onset decomposition temperature of 342 °C. Compatibility tests at 180 °C confirmed that 3 wt% CSP caused no adverse changes in the rheology or emulsion stability of the oil-based drilling fluid (OBM). At 180 °C, CSP reduced the high-temperature high-pressure (HTHP) filtrate loss by 64.4% and the permeability plugging apparatus (PPA) filtrate loss by 66.1%. Sand-disk tests elevated the breakthrough pressure from 1.5 to 9.2 MPa. Core displacement on sandstone cores achieved a plugging rate of 98.30%, and pressure transmission tests on natural shale cores extended the 50% equalization time by 7.8-fold. Comparative evaluation confirmed that the core–shell architecture consistently outperformed nano-SiO₂ alone, polymer alone, and their physical blend. Low-temperature N₂ adsorption provided direct evidence of pore sealing, with the treated-shale Brunauer–Emmett–Teller (BET) surface area and total pore volume reduced by about 62% (12.6 to 4.8 m²/g and 0.0325 to 0.0121 cm³/g, respectively). Scanning electron microscopy of the shale surface before and after treatment further provided direct visual evidence of pore sealing, showing the open, porous matrix being converted into a dense, compacted filter cake. Filter-cake thickness measurements are consistent with a proposed three-stage plugging mechanism—bridging, deformation filling, and thermal compaction—driven by the complementary roles of the rigid core and the deformable shell. These findings indicate that CSP merits further evaluation as a high-temperature plugging agent for wellbore stabilization in deep shale formations.