Most shale reservoirs (e.g., Bakken Shale and Eagle Ford) have a low permeability, low porosity, and oil-wet character with natural fractures. As a result, the oil recovery factors are very low, only a few percent of original oil in place. Injection of water into oil-wet reservoirs (i.e., water flooding) is not effective due to small or negative capillary pressure. In this study, various surfactants (non-ionic, cationic, anionic, and amphoteric) were studied for spontaneous imbibition into oil-wet shale cores. Surfactant imbibition into Eagle Ford shale outcrop cores and Bakken reservoir cores increased oil recovery compared to brine only. Oil recovery can be seen for surfactants that alter the reservoir from oil-wet to water-wet. For example, the incremental oil recovery was about 24% % for 0.1% cationic surfactant and 57% for 0.1% nonionic surfactant. The goal of this work is to investigate the effect of salinity, surfactant concentration, electrolyte concentration, and temperature on the wettability alteration and provide mechanisms. Contact angles and interfacial tensions (IFT) were measured and correlated with spontaneous imbibition. Wettability alteration from oil-wet to water-wet (i.e., low contact angle) appeared to be more important than a low interfacial tension in increasing the oil recovery rate from fractured oil-wet reservoirs, especially for nonionic surfactants and amphoteric surfactants. Wettability alteration is maximum and IFT is minimum for anionic and cationic surfactants at an optimal salinity. However, as the reservoir salinity increases, the maximum wettability alteration decreases and IFT increases.

In our previous study of Bakken shale imbibition, a group of surfactant formulations were examined. These surfactants consistently altered the wetting state of Bakken cores toward water-wet, and appeared to have a substantial potential to improve oil recovery from the Bakken Formation compared to brine water alone. To advance this development, this paper investigates the optimal salinities of surfactant solutions by phase behavior and IFT studies using Bakken formation water and oil. The ultimate objective of this research is to determine the potential for surfactant formulations to imbibe into and displace oil from shale, and also examine the viability of a field application.Using glass tube and encased-pipette methods, as well as a spinning drop tensiometer, dilute surfactant formulations were studied with various surfactants molecular structures (anionic, nonionic, cationic, and amphoteric). In most cases, optimal salinities obtained by phase behavior and IFT study aid surfactant imbibition into the Bakken Shale. In other cases, surfactant formulations were effective in imbibing into and displacing Bakken oil from Bakken cores, even though there were no obvious optimal salinities observed-suggesting that wettability alteration was a more dominant mechanism than IFT reduction in the imbibition process. Where optimal salinity behavior was obtained, the IFT between surfactant water and crude oil were reduced by one to two orders of magnitude with alkaline formulations. Under the same conditions, the inverse Bond number N B -1 which dominates the displacement mechanism, could be decreased below a value of 1 in cores from the Middle member of the Bakken.Based on phase behavior and IFT measurement at optimal salinity, we found: for Bakken reservoir conditions, (1) at lower concentrations (0.1%), of an anionic surfactant, internal olefin sulfonate shows a fast imbibition rate but lower oil recovery compared with a higher concentration surfactant (2%) with same molecular structure. (2) With 0.1% concentration, nonionic surfactants with an ethoxylated alcohol molecular structure exhibit a fast imbibition rate and strong effect on oil recovery at reservoir temperature (~120°C). (3) A cationic surfactant with a large carbon number and ethoxylated tallow amine structure at 0.1 % concentration has a favorable effect on oil production at high temperature. (4) An amphoteric surfactant with dimethyl amine oxide structure shows a stronger effect on oil recovery at 0.1% concentration. (5) At optimal salinity, the incremental oil recovery (during imbibition into Bakken cores at 120°C) can be up to 18% OOIP higher than seen during comparable experiments using formulations with 15～30% TDS, and the average instantaneous imbibition rate increased up to 45%.