Yong Li

High-pressure water injection (HPWI) refers to injecting water into the formation under conditions where the injection pressure is higher than or close to the formation fracture pressure. This technique can effectively improve the water absorption capacity of low-permeability reservoirs and maintain the formation pressure above the bubble point. It is a key technology for solving the problem of “difficult injection and difficult recovery” in low-permeability reservoirs, thereby achieving increased injection and enhanced production. However, due to the lack of a unified understanding of the mechanisms of dynamic micro-fractures and the mechanism of pore volume expansion and permeability enhancement during HPWI, the technology has not been widely promoted and applied. Based on an in-depth analysis of the mechanism of high-pressure water injection and by building a geological model for an actual oilfield development block, the “compaction–expansion” theory of rocks is used to characterize the variation in reservoir properties with pore pressure. This model is used to simulate the reservoir’s pore volume expansion and permeability enhancement effects during high-pressure water injection. The research results show the following: (1) HPWI can increase the effective distance of injected water by changing the permeability of the affected area. (2) During HPWI, the effective areas in the reservoir are divided into three regions: the enhanced-permeability zone (EPZ), the swept zone without permeability enhancement, and the unswept zone. Moreover, the EPZ expands significantly with higher injection pressure, rate, and volume. However, the degree of reservoir heterogeneity will significantly affect the effect of HPWI. (3) Simulation of two production modes—“HPWI–well soaking–oil production” and “simultaneous HPWI and oil production”—shows that under the first production mode, the degree of uniformity of the production wells’ response is higher. However, in the production wells in the EPZ, after a certain stage, an overall water flooding phenomenon occurs. In the second mode, the production wells in the water channeling direction show an alternating and rapid water-flooding phenomenon, while the production wells in the non-water channeling areas are hardly affected. Meanwhile, for local production wells with poor effectiveness of high-pressure water injection, hydraulic fracturing can be used as a pilot or remedial measure to achieve pressure-induced effectiveness and improve the sweep efficiency of the injected water. The results of this study explain the mechanisms of volume expansion and permeability enhancement during high-pressure water injection, providing guiding significance for the on-site application and promotion of high-pressure water injection technology in low-permeability reservoirs.

To examine how reaction media influence the copolymerization processes of acrylamide-based copolymers, [BMIM]Oac and water were utilized as the reaction media. Four copolymers P(AM-SSS) (H₂O), P(AM-UA) (H₂O), P(AM-SSS) (ILs), and P(AM-UA) (ILs) were synthesized using the soluble monomer sodium p-styrene sulfonate (SSS), the insoluble monomer 10-undecylenoic acid (UA), and acrylamide (AM). The properties of the copolymers were characterized using infrared spectroscopy and ¹H NMR, and the copolymerization rates of the monomers and the segment sequences of the copolymers were calculated. The results indicated that copolymerization of SSS in ionic liquids could reduce the length of the continuous units of AM in the copolymer’s molecular chain from 231.2866 to 91.1179, with a more uniform distribution within the molecular chain. The thermal stability and micro-morphology of the copolymers were tested using a synchronous thermal analyzer and scanning electron microscopy, and the resistance of the copolymer solutions to temperature, salt, and shear were evaluated. Comparisons revealed that the three-dimensional spatial structure formed by the copolymers in ionic liquids is robust and loose. When AM and SSS polymerize in [BMIM]Oac, the resulting copolymer exhibits a higher viscosity retention rate in temperature and shear resistance tests, with a thermal decomposition temperature reaching 260 °C. Conversely, when AM and UA polymerize in [BMIM]Oac, the copolymer demonstrates good salt resistance, maintaining a viscosity retention rate of 259.04% at a Na⁺ concentration of 200,000 mg/L. Therefore, the ionic liquid [BMIM]Oac can enhance the various application performances of copolymers formed by monomers with different solubilities and AM.

Residual crude oil production from low-permeability reservoirs has become a huge challenge because conventional recovery techniques are inefficient. Nanofluids as a new type of oil-displacement agent have become a hot topic in recent years to enhance oil recovery (EOR) in reservoirs. However, the imperfection of agglomeration, dissolution, and instability of nanofluids in reservoir environments limit their ability to drive oil. Here, a novel “microbial-nanofluid” composed of petroleum hydrocarbon-degrading bacteria (PHDB, namely Bacillus cereus) and SiO₂ nanoparticles was proposed as a potential new technology for enhancing residual oil recovery. The micromodel displacement test results showed that the optimum composite concentration of “microbial-nanofluids” were PHDB (7.0%, v/v) and SiO₂ nanoparticles (100 mg/L), and the residual oil recovery was increased by 30.1% compared with waterflooding (68.8%). Moreover, the morphological characteristics of residual oil mobilization after “microbial-nanofluid” flooding were mainly small and dispersed oil droplets in the excessive areas, and the dead-end areas were almost clean with mobilization. Furthermore, the cooperation mechanism of four kinds of “microbial-nanofluids” to enhance the residual oil recovery in low-permeability reservoirs was preliminarily clarified, namely the co-emulsification of oil, working together to unclog oil clog, microbial-nanofluid self-assembly, and structural disjoining pressure. This study demonstrated that PHDB-SiO₂ nanoparticle composite flooding technology provided a significant potential for the EOR from low-permeability reservoirs.

Interfacial interactions within a multi-phase polymer solution play critical roles in processing control and mass transportation in chemical engineering. However, the understandings of these roles remain unexplored due to the complexity of the system. In this study, we used an efficient analytical method—a nonequilibrium molecular dynamics (NEMD) simulation—to unveil the molecular interactions and rheology of a multiphase solution containing cetyltrimethyl ammonium chloride (CTAC), polyacrylamide (PAM), and sodium salicylate (NaSal). The associated macroscopic rheological characteristics and shear viscosity of the polymer/surfactant solution were investigated, where the computational results agreed well with the experimental data. The relation between the characteristic time and shear rate was consistent with the power law. By simulating the shear viscosity of the polymer/surfactant solution, we found that the phase transition of micelles within the mixture led to a non-monotonic increase in the viscosity of the mixed solution with the increase in concentration of CTAC or PAM. We expect this optimized molecular dynamic approach to advance the current understanding on chemical–physical interactions within polymer/surfactant mixtures at the molecular level and enable emerging engineering solutions.