[Editor's note: A version of this story appears in the August 2020 edition of E&P. It was originally published Aug. 3, 2020. Subscribe to the magazine here.] 

EOR is challenging in carbonate reservoirs, which hold more than 60% of the world’s oil reserves. Carbonate reservoirs are oftentimes oil-wet, meaning that oil prefers to tightly associate with the mineral surface and thus cannot be efficiently displaced by primary oil recovery methods such as water injection. Tremendous strides have been made in the industry to alter the carbonates to be less oil-wet to improve oil recovery. “Smart water” has emerged as a low-cost and promising technology to achieve wettability alteration.

R&D efforts

Smart water typically refers to a low-salinity brine with a specified composition that can alter rock wettability and enhance oil recovery. Unlike other EOR methods, such as chemical injection, smart water is simpler and requires a much lower capital investment. This approach has started to receive much attention for carbonate reservoirs after a surprisingly high oil recovery was reported when seawater was injected into the Ekofisk oil field in the North Sea in the 1990s. The salinity of seawater is much lower than the formation brine in the reservoir, and the low salinity is considered a key reason for the success.

Although several successes have been reported in both laboratories and oil fields, the effectiveness of smart water was found to be inconsistent. Many researchers have reported smart water as ineffective in improving oil recovery. Moreover, the underlying working mechanism of smart water remains controversial.

Study results

Research conducted at Rice University in Houston was motivated by the need to effectively evaluate the benefits of smart water injection for any crude oil as well as gain a clearer understanding of the fundamental working mechanism of smart water EOR. After performing a comprehensive evaluation of crude oil samples from multiple oil fields, it was determined that IOR (%) by smart water is correlated to certain physicochemical properties of the oil.

In recent work, Rice researchers fully characterized and tested six crude oils from various carbonate reservoirs around the world: the Middle East, the Gulf of Mexico and Malaysia. A model oil with added asphaltenes was developed to compare as a control case. The properties of the crude oils that were measured include total acid number, saturate-aromatic-resin-asphaltene fractionation, asphaltene instability, zeta potential in brines, interfacial tension in brines, water-in-oil content and water-soluble organics content. Furthermore, spontaneous imbibition tests were performed in high- and low-salinity brines to investigate how effective the low-salinity brine was for each of the seven oils.

Seven Indiana limestone cores were saturated and aged with the oils. Then the cores were immersed first in 22.6% sodium chloride (NaCl) (high salinity), then in 1% NaCl (low salinity) at 194 F for spontaneous imbibition.

The correlations between the oil recovery via spontaneous imbibition and different oil characteristics were analyzed. The degree of electrostatic repulsion between the oil-rock interface in low-salinity brines has been a popular hypothesized mechanism as the key parameter governing smart water EOR. Surprisingly, no correlation was found between additional oil recovery and oil zeta potential, which characterizes the electrostatic repulsion between the crude oil and rock surface. However, the oil interfacial activity in the low-salinity water is found to affect the low-salinity-induced wettability alteration process (Figure 1).


Source: Rice University
Source: Rice University
FIGURE 1. Additional oil recovery in low-salinity water (compared to high-salinity water) correlates with the oil interfacial tension for the seven tested oils. The cryo-TEM image shows emulsified water droplets in crude oils that respond favorably to low-salinity water injection. (Source: Rice University)

This observation also is supported by studying two other properties: water-in-oil content and the content of water-soluble organics. Both measurements should be higher for more surface-active oils. As expected, similar correlations to the additional oil recovery also were found for those two oil properties. Interestingly, emulsified water droplets were observed via cryogenic transmission electron microscopy (cryo-TEM) in oils that exhibited high oil recovery factors in smart water. This confirms the importance of the physicochemical properties of the crude oil in determining the effectiveness of smart water. With these findings, companies can quickly screen and estimate the smart water potential of a specific oil field by testing the oil interfacial tension or the water- in-oil content using smart water. Expenses associated with screening oilfield candidates for smart water applications can be significantly reduced.