The solid particles in the produced fluids from the oil wells treated by compound flooding can greatly stabilize the strength of the interfacial film and enhance the stability of the emulsion, increasing the difficulty of processing these produced fluids on the ground. In this paper, the oil phase and the water phase were separated from the SPAN series emulsions by electrical dehydration technology and adding demulsifier agents. The changing trends of the current at both ends of the electrodes were recorded during the process. The efficient demulsification of the emulsion containing solid particles was studied from the perspective of oil-water separation mechanisms. Combined with the method of molecular dynamics simulation, the effect of the addition of a demulsifier on the free movement characteristics of crude oil molecules at the position of the liquid film of the emulsion were further analyzed. The results indicated that the presence of solid particles greatly increased the emulsifying ability of the emulsion and reduced its size. Under the synergistic effect of demulsifier and electric dehydration, the demulsification effect of the emulsion increased significantly, and the demulsification rate could reach more than 82%. The addition of demulsifiers changed the stable surface state of the solid particles. The free movement ability of the surrounding crude oil molecules was enhanced, which led to a decrease in the strength of the emulsion film so that the water droplets in the emulsions were more likely to coalesce and break. These results are of great significance for the efficient treatment of wastewater from oilfields, promoting the sustainability of environment-friendly oilfield development.

The mechanical strength of dispersed particle gels (DPGs), which can be directly characterized by Young’s modulus, is an important parameter affecting reservoir regulation performance. However, the effect of reservoir conditions on the mechanical strength of DPGs, as well as the desired range of mechanical strength for optimum reservoir regulation performance, have not been systematically studied. In this paper, DPG particles with different Young’s moduli were prepared and their corresponding migration performances, profile control capacities and enhanced oil recovery abilities were studied by simulated core experiments. The results showed that with increase in Young’s modulus, the DPG particles exhibited improved performance in profile control as well as enhanced oil recovery. However, only the DPG particles with a modulus range of 0.19–0.762 kPa could achieve both adequate blockage in large pore throats and migration to deep reservoirs through deformation. Considering the material costs, applying DPG particles with moduli within the range of 0.19–0.297 kPa (polymer concentration: 0.25–0.4%; cross-linker concentration: 0.7–0.9%) would ensure optimum reservoir control performance. Direct evidence for the temperature and salt resistance of DPG particles was also obtained. When aged in reservoir conditions below 100 °C and at a salinity of 10 × 10⁴ mg·L⁻¹, the Young’s modulus values of the DPG particle systems increased moderately with temperature or salinity, indicating a favorable impact of reservoir conditions on the reservoir regulation abilities of DPG particles. The studies in this paper indicated that the practical reservoir regulation performances of DPGs can be improved by adjusting the mechanical strength, providing basic theoretical guidance for the application of DPGs in efficient oilfield development.

Hydrogel has been widely used in reservoir regulation for enhancing oil recovery, however, this process can experience negative influences on the properties and effects of the hydrogels. Therefore, developing novel hydrogels with excellent environmental responsiveness would improve the formation adaptability of hydrogels. In this study, novel polyvinyl polyamine hydrogels were synthesized by a ring-opening addition reaction between polyvinyl polyamines and polyethylene glycol glycidyl ether. The results of atomic force microscopy and transmission electron microscopy showed that the polyvinyl polyamine gel had a porous and irregular bulk structure and was endowed with water storage. With the temperature rising from 30 °C to 60 °C, the transmittance of diethylenetriamine hydrogel decreased from 84.3% to 18.8%, indicating that a phase transition had occurred. After the polyvinyl polyamine hydrogel with low initial viscosity was injected into the formation in the liquid phase, the increase of the reservoir temperature caused it to turn into an elastomer, thereby migrating to the depth of the reservoir and achieving effective plugging. Polyvinyl polyamine hydrogel could improve the profile of heterogeneous layers significantly by forcing subsequent fluids into the low permeability zone in the form of elastomers in the medium temperature reservoirs of 40–60 °C. The novel environmentally responsive polyvinyl polyamine hydrogels, capable of phase transformation with temperature, exhibited superior performance in recovering residual oil, which was beneficial for applications in reservoir profile control and oilfield development.

High salinity and hardness in flowback fluids from tight reservoirs severely degrade the performance of conventional fracturing fluids, leading to formation damage and imposing major constraints on water recycling. An innovative in situ molecular interface regulation strategy that bypasses the need for costly pretreatment was proposed. A novel zwitterionic polymer was synthesized by grafting trimethylamine N-oxide (TMAO) onto hydrolyzed polyacrylamide. This hydrolyzed polyacrylamide grafted with trimethylamine N-oxide polymer (HPAMT) leverages zwitterionic TMAO groups to form a robust hydration layer approximately 0.25 nm thick on the polymer chains. Each TMAO group can immobilize up to 22.2 water molecules, effectively shielding the polymer from the detrimental effects of ions like Ca²⁺ and Na⁺, thereby preventing chain curling and preserving cross-linking sites. Experimental results demonstrate that HPAMT fracturing fluid prepared with untreated flowback fluids retains over 70% of its initial viscosity. The HPAMT fracturing fluid exhibits superior thermal and shear stability, maintaining more than 90% viscosity after exposure to 90 °C and the shear rate of 170 s⁻¹ for 60 min. Furthermore, HPAMT provides excellent proppant suspension, exceeding 60 min of static settling time. The broken gel viscosity remains below 5 mPa·s, enabling the direct reuse of flowback water. This technology overcomes the critical compatibility issue between traditional polymers and challenging brine chemistry, significantly reducing freshwater consumption and operational costs, thus presenting a viable and innovative solution for enhancing the environmental sustainability of unconventional resource development.

Conventional polymer gels for deep fluid diversion in moderate-temperature (40–60 °C) reservoirs are constrained by the chromatographic separation of crosslinkers and poor gelation controllability. In this work, a side-chain pendant decoupling molecular design strategy is proposed. Using cardanol glycidyl ether, diethylenetriamine (DETA), and polyethylene glycol diglycidyl ether (PEGO), a stepwise route exploits the differential reactivity of mono- versus di-epoxide groups to graft cardanol C15 alkyl chains as freely pendant side groups onto a PEGO/DETA covalent network. The covalent network provides a mechanical skeleton, while the pendant C15 chains act as independent thermoresponsive switches, liberating the C15 chains from topological constraints. This endows the hydrogel with a clear thermoresponsive transition around 40 °C, with G′ increasing to 980 Pa and the transmittance dropping from 28.9% to below 4%. Kinetic analysis indicated a transition from diffusion-controlled to chemically controlled network growth. The Avrami exponent n ranged from 0.85 to 1.28 across the tested temperatures. The poor linearity of the Arrhenius fits (R² = 0.62 and 0.35) indicates non-Arrhenius behavior, consistent with the proposed synergistic dual mechanism. Given the unavoidable salinity of formation water in actual reservoirs, the effect of salinity on gelation kinetics was further examined. At 45 °C, varying the NaCl concentration from 0 to 5000 mg/L affected gelation kinetics, while the measured plateau storage moduli remained similar under the investigated conditions. Physical simulation experiments showed a plugging rate of 96.1% at 60 °C in deionized water, and in situ gelation in the core under simulated reservoir brine led to a 99.98% permeability reduction within 60 min. This cardanol-derived hydrogel with engineered side chains establishes a molecular engineering principle in which pendant grafting liberates hydrophobic chains from topological constraints, offering a new paradigm for cardanol-derived intelligent oilfield chemicals in deep reservoir conformance control.