Owing to the simultaneous improvement of swept volume and oil displacement, foam flooding is one of the techniques that has been proven successfully in increasing EOR (Enhanced Oil Recovery). However, foam flooding in a harsh condition has not been fully addressed in the previous studies. The objective of this paper is to investigate the high-temperature and high-salinity resistant foam agents as a displacing chemical for improving the efficiency of oil recovery in harsh conditions. Firstly, the foam agents with excellent performances under harsh reservoir conditions were developed by screening and mixing. Then, the foam properties changing with temperature were studied under high pressure in the oil-free/oil-bearing environments. Finally, based on simulating reservoir formation conditions, a series of researches on the flooding characteristics of nitrogen foam were conducted. Results indicated that the optimum foam agents with low surface tension and high interfacial viscoelastic modulus performed excellently under high-temperature and high-salinity. Foam stability increased remarkably as pressure increased, and also largely affected by temperature. Higher concentration and pressure were in favor of foam properties in the presence of crude oil. In foam flooding experiments, the mobility reduction of foam was observed to be larger in the conditions of high pressure and low oil saturation, and nitrogen foam could significantly control the water cut and improve the oil recovery which were subject to the influencing factors (i.e., initial water cut, injected slug, foam quality, injected volume and foam stability).

The mobility disparity between oil and water accounted for the poor water swept efficiency. Previous research has testified that nitrogen foam can increase sweep area and control water and gas mobility. However, the former studies have largely covered the mobility control ability performance in some conventional reservoir rather than that under high temperature and high salinity. This paper presents the results of a laboratory study of nitrogen foam at the experimental condition (113 °C and 21.28 × 10 4 mg/L) on its mobility control ability investigation, including different gas-to-liquid ratio, injection rate and core permeability; additionally, a novel method on studying the stability of mobility control ability of foam was utilized. Nitrogen foam injection was conducted in core holder to investigate the shape discrepancy of each resistance factor and residual resistance curve. The results showed that the most moderate gas-to-liquid ratio and injection rate were 2:1 and 1 mL/min, respectively; foam performed more significant mobility control ability with the increase in permeability. After 5 days’ aging, nitrogen foam still got enough mobility control ability to block water channeling. The above results demonstrate that, under high temperature and high salinity condition, nitrogen foam still can act as a promising economical method for improving the mobility difference between water and oil by applying appropriate injection parameters.

This article is designed for the application of Cocamidopropyl hydroxyl sulfobetaine (CHSB) in the nitrogen foam flooding under the high-temperature and high-salinity environments. Firstly, foam properties of CHSB were evaluated at different temperatures and varying salinity, as well as the effect of concentration on foam properties, and the long-term foam properties of CHSB were developed under different concentration. Then, a series of researches on controlling mobility of nitrogen foam were conducted in the sand-packs. Finally, nitrogen foam flooding was carried out in the sand-model and oilfield site. Results indicated that high-temperature was unfavorable to foam stability, and high-salinity could favor its stability. When CHSB was used as foaming agent at the concentration of 0.2wt%, it showed excellent performance at the temperature of 120°C and the salinity of 22×104mg/L and good long-term stability after aging for 60 days. The foam flooding experiments showed that mobility reduction factor of foam increased with the residual oil saturation decreased or as the permeability declined in the high-temperature and high-salinity, and the residual resistance factor of foam during the subsequent waterflooding with 5 days shut-in was 3.8, which was obviously higher than that without shut-in or with shut-in in oil-free environment. The displaced area in sand-model was lager and wider in the presence of 5 days’ shut-in than that in the absence of shut-in, and the water cut could be reduced to 38% and the enhanced oil recovery was about 17.8% after 5 days’ shut-in. The oilfield test showed that the validity period of high oil production rate was more than half year and 2400t of crude oil was produced in all.

Explored the effects of high temperature and crude oil on foam properties from the point of microscopic visualization.