Optimal Salinity Study to Support Surfactant Imbibition into the Bakken Shale

Abstract

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%.

A Literature Review of CO2, Natural Gas, and Water-Based Fluids for Enhanced Oil Recovery in Unconventional Reservoirs

“…Oil recovery using LSW in conventional formations can exceed that obtained using produced high-salinity brines . Laboratory-scale oil recoveries from ULR cores indicate that several mechanisms may be responsible for the oil recovery observed during the immersion of oil-rich shale cores in water or LSW. − Possible mechanisms of oil recovery by LSW include wettability alteration, ,− detachment of clays, multicomponent ion exchange, desorption of polar components from rock surfaces, − formation of cracks in shale due to LSW imbibition, − and osmosis …”

“…A study was conducted that compared fresh water, brine with 30% TDS, and aqueous solutions of anionic, cationic, and nonionic surfactants at 0.05−2 wt % in brine or formation brine at 30 wt % TDS with either no alkaline content or a dilute alkaline concentration (0.2−0.25%) (Table 6, entry 7). 252 Water and brine results were poor. Surfactant solutions were promising, with both IFT reduction and wettability alteration deemed to be important for EOR from Bakken cores.…”

Scaling Laboratory-Data Surfactant-Imbibition Rates to the Field in Fractured-Shale Formations

“…Mattax and Kyte (1962) first suggested a scaling group for a capillary-controlled imbibition. Later, it was proposed that oil recovery from spontaneous imbibition is affected by rock wettability (Zhou et al 1996), and a modified scaling group that accommodates various shapes was also suggested (Ma et al 1997(Ma et al , 1999Morrow and Mason 2001). These scaling models are very useful for our current spontaneous-imbibition studies.…”

Study of Enhanced Oil Recovery and Adsorption Using Glycerol in Surfactant Solution

“…The 2 wt. % KCl concentration was used to verify the better interaction of the displacing fluid solution with the reservoir's rock, since the reservoir water presents salinity, and this interferes with the CMC value of the surfactant by the competition of salt with the hydrophilic group of surfactants in water solubility, as well as rock wettability [10,[20][21][22][23].…”