Alkyl polyglycoside (APG) is a green surfactant with excellent interfacial activity, emulsified ability, foaming performance and wettability, which has great potential in enhancing heavy oil recovery at high-temperature and high-salinity condition. In this paper, surface tension, interfacial tension, emulsifying ability, emulsion stability and emulsified oil droplet size were investigated for APG. Besides, the effect of temperature and salinity on interfacial activity and emulsification properties of APG was also studied. The results showed that APG had excellent interfacial activity and emulsification property among all these surfactants. Besides, the interfacial activity and emulsification properties of APG almost did not decrease, and even got better along with the increasing temperature or salinity, while those of other surfactants became worse in different degree. The incremental oil recovery by using APG at 90 °C and the salinity of 30 g/L can reach to 10.1% which is nearly two times higher than that of common EOR surfactants. These results indicated that APG is an efficient surfactant for enhancing heavy oil recovery at high-temperature and high-salinity condition.

Summary: For conventional particles used for conformance control in fractured-vuggy reservoirs, large-size particles easily plug the wellbore area but have difficulty plugging the zone far from the wellbore, while small-size particles easily move in depth. In this study, fiber balls for bridging in fractured-vuggy reservoirs were developed by wrapping the fiber in the precrosslinked gel. Due to the influence of temperature and salinity in the formation, the gel degraded and the filamentous fibers were released. Then, the released fibers bridged in the fractures while reducing the safety risk of the injection process. As a water plugging agent, the fiber balls can decrease the conductivity in high-permeability fractures and increase the conductivity in low-permeability fractures, thus improving waterflooding efficiency and enhancing oil recovery. The plugging performance of fiber balls was evaluated by coreflooding experiments. The experimental results show that the optimal formulation of fiber balls is 7% acrylamide (AM) + 3% polyamino acid ester + 0.75% potassium persulfate (K2S2O8) + 4% polypropylene fiber + 4% glass fiber + 0.15% polyethylene glycol diacrylate (PDA) + 0.08% N,N-dimethyl acrylamide (MBA) + 0.1% polyacrylamide (PAM). The release time of fibers from the external gel is 42 to 57 hours, meeting the requirements of conformance control. According to the results of the performance evaluation, the larger the fracture width, the worse the bridging effect of fibers. Besides, the rule of “3/2 bridging” fiber was proposed: When the fiber length is 3/2 times the fracture width, the fiber has the strongest bridging and plugging ability. With the increase in fracture width, the fiber concentration needs to be increased to have a good bridging performance. The results of this study can provide a new idea for the technology of conformance control in fractured-vuggy reservoirs.

Summary: To address the problems of steam channeling caused by the nonhomogeneity and fluid compatibility of the reservoir in heavy oil reservoirs and the permanent damage to the reservoir easily caused by traditional plugging agents, this study adopted polyaluminum chloride (PAC) as the main agent, urea as the coagulant promoter, and thiourea as the stabilizer and prepared a high-temperature-resistant (up to 350°C) degradable inorganic aluminum gel with excellent performance. Initially, scanning electron microscope (SEM) tests were conducted on gels with and without urea. Energy-dispersive X-ray spectroscopy (EDS)-mapping analysis of gels immersed in water with different mineralization levels for 5 days was then performed. The results revealed that the addition of urea led to a tighter and more complete crosslinked structure, significantly enhancing the mechanical strength of the gel. As water mineral content increased, the gel’s microstructure became denser and smoother. Metal cations on the cross-sectional surface increased gradually and distributed uniformly, further confirming the mechanism of the synergistic salt effect of soluble strong electrolytes and urea in strengthening the gel. Finally, the plugging and degradable properties of the gel were evaluated, and the results showed that the plugging percentage of the gel could still reach 97.6% after aging at 350°C for 30 days, and the gel had excellent plugging and diversion in dual sandpack experiments where the permeability ratio was less than 44. At 250°C, the degradation percentage of the gel was more than 98% at 5 days under the nonacid degradation system and 94% at 5 days under the acid degradation system. The gel showed good degradability and effectively reduced the damage to the reservoir.