What type of surfactants should be used to enhance spontaneous imbibition in shale and tight reservoirs?

Spontaneous imbibition is a very important mechanism for the mass transfer between fracture and matrix in shale and tight reservoirs. To enhance this spontaneous imbibition, surfactants are added in imbibing fluids such as fracturing fluid and injection fluid. However, it has been observed in field applications that one group of wells having surfactants added in the fracturing fluid may not outperform another group of wells having no surfactants added. Oil operators start to ask: what types of surfactants should be used; what are the functions of the surfactants? Surfactants have two main functions: wettability alteration and reduction in interfacial tension (IFT). Which function is more important? This question needs to be answered so that we can choose the right types of surfactants to be added. This paper is to discuss the mechanisms of spontaneous imbibition and to answer this question. In this paper, we use simulation approach combined with theoretical analysis and published experimental results to investigate the mechanisms of spontaneous imbibition, and to compare the effects of capillary pressure, IFT reduction, diffusion and gravity. Particularly, we compare the effects of wettability alteration and IFT reduction. We find that the initial wettability is the most important factor to control imbibition. When a shale or tight rock is initially water-wet, the imbibition velocity is fast and the imbibition oil recovery is similar (about 10% lower in a simulated case) to that from a conventional rock. In that case, no surfactant is needed and thus the IFT is high oil-water IFT (20 mN/m in the models). When a shale or tight rock is initially oil-wet, a surfactant is added to change the wettability from oil-wet to water-wet, and the IFT is reduced to 0.008 mN/m). The imbibition velocity is found to be unrealistically slow. To achieve an oil recovery factor similar to that in the initially water-wet core plug in the lab scale, one million days of imbibition are needed. This results from the slow diffusion process. However, if the wettability is changed from oil-wet to water-wet and the IFT is maintained at a high value (20 mN/m), the oil recovery factor is similar to that from the initially water-wet core plug. These results show that the surfactant must be able to change wettability but to maintain high IFT to enhance the imbibition in a shale or tight reservoir. Further studies of the effects of IFT reduction without wettability alteration, diffusion and gravity indicate that these mechanisms are not practically effective in shale and tight reservoirs, because either the viscous force cannot be overcome or the processes are too slow. The findings of this paper provide a guide regarding what type of surfactants should be used to enhance the fracture-matrix mass transfer by spontaneous imbibition. [ABSTRACT FROM AUTHOR]