# Using Low Salinity Waterflooding to Improve Oil Recovery in Naturally Fractured Reservoirs
## 1 Introduction  
Carbonate reservoirs in the Middle East hold a significant proportion of remaining conventional oil reserves, most of which are classified as naturally fractured [1; 2]. These reservoirs are well known for their low recoveries compared with their counterpart clastic unfractured reservoirs [3]. Most of these reservoirs have already produced for several decades using natural depletion mechanisms or undergone secondary conventional waterflooding projects. However, developing fractured reservoirs requires an affordable technique that is able to sweep the oil and improve recoveries, as well as controlling the early breakthrough of water that is often observed in conventional waterflooding. It is often the case that enhanced oil recovery techniques are not feasible due to the high cost of such projects. Low salinity waterflooding is a promising low-cost technique to increase oil recovery. Experimental outcomes have proven a significant improvement in oil recovery when low salinity waterflooding schemes were applied [4]. During low salinity waterflooding, multiple recovery mechanisms have been attributed to be responsible for the increment in oil recoveries, such as cation exchange [5; 6], an increase in the pH [7; 8; 9], changes of the charges at the rock surfaces [10], wettability alteration [11; 12; 13; 14],fine migration [14], a reduction in the interfacial tension [15], a micro-dispersion [16], and the osmosis [17]. Therefore, the increment in oil recovery may be due to one or more of the mentioned recovery mechanisms. Various impacts of low salinity corefloods were observed on both sandstone and carbonate samples, such as wettability alteration, a reduction in residual oil saturation, and interfacial tension (e.g., [18; 19; 20; 21; 22]). This impact has been attributed to the chemical interactions between the injected low salinity brine, crude oil, and rock surfaces. [PERSON] et al. have referred to the in-situ forming of surfactants due to the saponification reaction between the elevated pH of the low salinity brine and the acid or polar components in the crude oil [23]. Acidity increment (i.e., pH) occurred from the reaction between the low salinity water and natural minerals of the reservoir, which generated hydroxyl ions and increased the pH up to 10 or more. As a result, the system wettability was shifted to a more water-wet state. In addition, a reduction in both residual oil saturation and interfacial tension occurred. Alteration to the system wettability has been reported at ambient temperature [18]. A laboratory experiment was carried out under these conditions to measure the contact angle of a sessile oil droplet, as well as the interfacial tension and the potential at various temperatures, using limestone and dolomite samples. The outcome was an apparent alteration of the wettability towards a more water-wet system. Furthermore, the chemistry of the crude oil, the rock type, and particularly clay minerals are among the factors that control the system's wettability and residual oil saturation [19]. These factors also influence how wettability and residual oil may change. When present, heavier asphaltene components tend to stain the rock surfaces and make the system strongly oil-wet. Therefore, using the low salinity scheme in an asphaltenic oil system can lead to less oil recovery compared with a low asphaltenic oil system. It has been reported that, in this case, the wettability does not change significantly with the use of low salinity methods [19]. During low salinity water injection, the high salinity formation water tends to form as a waterfront due to its high mobility, followed by the low salinity injected brine [24]. A mixing salinity region (i.e., dilution region) often forms between the formation water and the injected brine. The dilution region is essential for the chemical interaction between the low salinity brine and crude oil/rock to take place. Moreover, there is a range of salinity in which the wettability, fluid mobility, and residual oil saturation can change [25; 26].