High-molecular-weight polyacrylamide (PAM) has been widely used in chemically enhanced oil recovery (EOR) processes under mild conditions, but its poor tolerance to high temperature and high salinity impeded the use in severe oil reservoirs. To overcome the inadequacies of PAM, thermoviscosifying polymers (TVPs) whose viscosity increases upon increasing temperature and salinity were developed in recent years. In this work, comparative studies with PAM and TVP, having more similar molecular weights, were performed with regard to their rheological behaviors, thermal stability, and core flooding feasibility. It was found that the TVP aqueous solution exhibited thermothickening ability, even at a polymer concentration of 0.2 wt % with a total dissolved solids ratio (TDS) of 101 000 mg L–1 upon increasing temperature, while PAM only showed a monotonic decrease in viscosity under identical conditions. Remaining viscosity of TVP was higher than that of PAM after aging at 45 or 85 °C for one month. Core flooding tests demonstrated both polymers show good transportation in porous media, and a higher oil recovery of 16.4% and 15.5% can be attained by TVP at 45 and 85 °C, respectively, while those of PAM are only 12.0% and 9.20%.

On-demand initiation of dual- and multi-component microreactions inside liquid marbles (LMs) was developed by coalescing contacting patchy LMs containing separate reagents through CO2-induced wetting transition of the interface between the LMs.

Inter-salt shale oil reservoirs located between two salt layers are always accompanied by high temperature and high salinity. However, the present commonly used water-soluble polymers in fracturing fluids suffer from poor tolerance to high temperature and high salinity. Thermoviscosifying polymers (TVP) whose aqueous solution shows viscosity increase upon increasing temperature and salt concentration have received considerable attention recently, which is promising for utilization in fracturing fluids to overcome these problems. In this work, both the salt-induced viscosifying property and mechanism of a TVP solution were investigated and the performance of TVP used as fracturing fluid based on the conditions of the Jianghan inter-salt shale oil reservoir in China was evaluated. It is found that the salt-induced viscosifying property of the TVP solution decreases with temperature and shear rate, but increases with polymer concentration. The number of intermolecular hydrophobic domains increases with the salt concentration contributing to the strengthening of a 3D network structure, which results in an increase in viscosity. In addition, the TVP fracturing fluid formulated with saturated brine exhibits excellent temperature and shear resistance, sand-suspending performance, and gel-breaking performance. Its viscosity remains above 50 mPa s after being sheared for 1 h even at a high temperature of 140 °C and the sand-suspending stability can be maintained for more than 1 week at 100 °C. Furthermore, the fracturing fluid can be easily broken down within 12 h using 0.2 wt%-0.3 wt% potassium persulfate without residue.