Drilling cuttings from the rock formation generated during the drilling process are generally smashed to fine particles through hydraulic cutting and grinding using a drilling tool, and then are mixed with the drilling fluid during circulation. However, some of these particles are too small and light to be effectively removed from the drilling fluid via solids-control equipment. These small and light solids are referred to as low gravity solids (LGSs). This work aimed to investigate the effect of LGSs on the performance of oil-based drilling fluid (OBDF), such as the rheological properties, high-temperature and high-pressure filtration loss, emulsion stability, and filter cake quality. The results show that when the content of LGSs reached or even exceeded the solid capacity limit of the OBDF, the rheological parameters including the plastic viscosity, gel strength, and thixotropy of OBDF increased significantly. Furthermore, the filtration of OBDF increases, the filter cake becomes thicker, the friction resistance becomes larger, and the stability of emulsion of OBDF also decreases significantly when the concentration of LGSs reached the solid capacity limit of OBDF (6–9 wt% commonly). It was also found that LGSs with a smaller particle size had a more pronounced negative impact on the drilling fluid performance. This work provides guidance for understanding the impact mechanism of LGSs on drilling fluid performance and regulating the performance of OBDF.

Shale hydration dispersion and swelling are primary causes of wellbore instability in oil and gas reservoir exploration. In this study, inulin, a fructo-oligosaccharide extracted from Jerusalem artichoke roots, was modified by acylation with three acyl chlorides, and the products (C10-, C12-, and C14-inulin) were investigated for their use as novel shale hydration inhibitors. The inhibition properties were evaluated through the shale cuttings hot-rolling dispersion test, the sodium-based bentonite hydration test, and capillary suction. The three acylated inulins exhibited superb hydration-inhibiting performance at low concentrations, compared to the commonly used inhibitors of KCl and poly (ester amine). An inhibition mechanism was proposed based on surface tension measurements, contact angle measurements, Fourier-transform infrared analysis, and scanning electron microscopy. The acylated inulin reduced the water surface tension significantly, thus, retarding the invasion of water into the shale formation. Then, the acylated inulin was adsorbed onto the shale surface by hydrogen bonding to form a compact, sealed, hydrophobic membrane. Furthermore, the acylated inulins are non-toxic and biodegradable, which meet the increasingly stringent environmental regulations in this field. This method might provide a new avenue for developing high-performance and ecofriendly shale hydration inhibitors.

Wellbore instability caused by the invasion of drilling fluids into formations remains a significant challenge in the application of oil-based drilling fluids (ODFs). In this study, carbon nanospheres (CNSs) were synthesized using glucose as the carbon source through a microwave-assisted method. The effects of the reaction temperature, carbon source concentration, and reaction time on the particle size of CNSs were systematically investigated. The results revealed that under optimal conditions, CNSs with an average particle size of 670 nm were successfully synthesized, exhibiting high sphericity and excellent dispersibility. CNSs demonstrated stable dispersion in mineral oil when lecithin was used as a dispersant. The plugging performance of CNSs in ODFs was evaluated through low-pressure filtration and high-temperature, high-pressure (HTHP) filtration tests. After aging at 180 °C for 16 h, the addition of 2% CNSs reduced the filtration volume from 10.6 mL to 2.5 mL on standard filter paper (average pore size: 3 μm) and from 8.5 mL to 1.6 mL on microporous membranes (average pore size: 0.5 μm). Additionally, the HTHP filtration volume decreased from 73 mL to 18 mL, and the permeability of the filter cake formed during HTHP filtration was reduced from 26.5 × 10⁻³ mD to 1.2 × 10⁻³ mD. Furthermore, CNSs improved the rheological properties and emulsion stability of ODFs. With excellent compatibility and applicability, CNSs offer a promising solution for enhancing the performance of oil-based drilling fluids.

The instability of wellbore in hard and brittle shale formations is a key bottleneck constraining the safety and efficiency of drilling engineering. Traditional studies focused on drilling fluid density, particle plugging, and chemical inhibition; however, there is a lack of in-depth analysis on the precise control mechanism of wellbore stability by the rheological properties of drilling fluids. Specifically, while traditional methods are limited in addressing mechanical instability in hard brittle shales with pre-existing micro-fractures, rheological control offers a potential solution by influencing pressure transmission within these fractures. To address this research gap, this study aims to reveal the influence of drilling fluid rheological parameters (specifically viscosity and yield point) on the pressure transmission behavior of the micro-fracture network in hard and brittle shale and to clarify the intrinsic mechanism by which rheological properties stabilize the wellbore. Micro-structure analysis confirmed interconnected micro-fractures (0.5–30 μm). A micro-fracture flow model and simulations evaluated viscosity and yield point effects on pressure transmission. A higher viscosity significantly increased the pressure drop (ΔP) near the wellbore, with limited transmission distance effects. The yield point was minimal. The study reveals that optimizing rheology, particularly increasing viscosity, can suppress pore pressure, reduce collapse pressure, and improve stability. The findings support rheological parameter optimization for safer, economical drilling. In terms of rheological parameter optimization design, this study suggests emphasizing the increase in drilling fluid viscosity to effectively manage wellbore stability in hard brittle shale formations.

Fluid-loss additives play a critical role in maintaining the stability and filtration-control performance of water-based drilling fluids during deep and high-temperature drilling operations. However, the development of microgel-based additives with both exceptional thermal stability and strong salt tolerance remains a major challenge under harsh drilling conditions. In this study, a covalently micro-crosslinked anionic copolymer-based microgel (PAAN) was synthesized via free-radical copolymerization of acrylamide, 2-acrylamido-2-methylpropane sulfonic acid, and N-vinylpyrrolidone using N,N′-methylenebisacrylamide as the crosslinking agent. The chemical structure of PAAN is consistent with the design, with excellent thermal stability, and the starting temperature for thermal decomposition of polymer molecular chains is 297 °C. The weight average molecular weight of PAAN is 1.3396 × 10⁶ g/mol. After aging at 220 °C in the presence of 15 wt% NaCl, the PAAN-containing drilling fluid exhibited a high-temperature high-pressure filtration loss of only 15.6 mL. Even after prolonged aging for 168 h, the filtration loss remained at a relatively low level of 46.0 mL, indicating outstanding thermal stability and salt tolerance. Mechanistic analysis indicated that PAAN adsorbed onto bentonite surfaces through electrostatic interactions and hydrogen bonding, promoting clay-particle dispersion and colloidal stability. Moreover, the microgel network facilitated the formation of a compact and low-permeability filter cake, contributing to effective fluid-loss control under harsh conditions. These results demonstrate that microgel structural design is an effective strategy for improving the high-temperature and salt-resistant filtration-control performance of WBDFs, and PAAN shows strong potential for deep and ultra-deep drilling applications.