Dynamic Interfacial Tensions and Contact Angles of Surfactant-in-Brine/Oil/Shale Systems: Implications to Enhanced Oil Recovery in Shale Oil Reservoirs

Abstract

Unconventional shale oil resources have emerged as a significant source of fossil fuels in recent years. The oil contained in shales is held in natural microfractures, micropores, and inside nanopores of the organic matter. The strong capillary forces in these pores can bind the oil to the surface with strengths that are inversely proportional to the pore radius. In order to recover more oil from these pores, it is beneficial to reduce the capillary pressure by manipulating the interfacial tension and contact angle of oil/brine/shale systems using surfactant solutions. The main consideration in surfactant flooding is to optimize brine salinity and surfactant concentration while minimizing their adsorption on rock surfaces. Although the effect of some surfactants on recovery in shale oil reservoirs has been studied in the past, the mechanism is still unclear. Moreover, the limited data available in the literature is not representative of the actual reservoir conditions. The objective of this study is to elucidate the oil displacement mechanisms in shale oil by surfactant flooding. The phase behavior of several anionic surfactants was studied in the presence of crude oil at reservoir temperature (i.e. 80 °C). The results of these tests were used to screen the best surfactants. Dynamic interfacial tensions (IFT) and contact angles (CA) of selected surfactant-in-brine/oil/shale systems were measured by the rising/captive bubble technique using a state-of-the-art IFT/CA apparatus. The apparatus was thoroughly validated with various systems using the axisymmetric drop shape analysis technique. Using the same methodology, the effects of surfactant concentration (0.01 to 0.1 wt%) and brine salinity (0.1 to 5 M NaCl) on IFT and CA at ambient and reservoir conditions (i.e. 80 °C and 3000 psig) were studied. Surfactant adsorption on shale samples was also measured in brines at ambient conditions. Our data reveal that the most effective surfactant was able to reduce the oil-brine IFT from its original value (23 mN/m) down to 0.3 mN/m at reservoir condition. A reduction in the IFT value and an increase in the dynamic contact angle of oil drop on polished shale surface were observed with the addition of surfactant and salt to the system. A trend between these parameters, pressure, and temperature was also reported.

Status of surfactant EOR technology

“…The literature on shale oil rocks indicates that they are most likely oil-wet (Phillips et al, 2007;Wang et al, 2011;Mirchi et al, 2014). Shuler et al (2011) did some surfactant spontaneous imbibition tests.…”

“…Takahashi and Kovscek (2010) studied the wettability of a low-permeability siliceous shale at different pH values and found that the shale samples became more water-wet at very low or very high pH. Mirchi et al (2014) observed that adding surfactants in brine reduced the interfacial tension between brine and oil and increased the dynamic contact angle of oil drops (became more water-wet).…”

Introductory Chapter: Developments in the Exploitation of Unconventional Hydrocarbon Reservoirs

“…Surfactants are amphiphilic organic chemicals comprising hydrophobic and hydrophilic compounds. When injected into ultra-low permeability hydrocarbons rocks, they reduce the oil viscosity, pore capillary forces and the interfacial tension between water and oil and decrease oil-wet wettability [7][8][9].…”

Investigation of the kinetics of water uptake into partially saturated shales

“…[] investigated the wettability of organic shale samples and concluded that the samples are strongly oil‐wet in the presence of air. They further mentioned that deionized (DI) water causes the highest contact angle on the sample surface and that highly saline solutions lead to the lowest contact angle whereas another study [ Mirchi et al ., ] suggests that the contact angle increases with salinity. Furthermore, the amount of water uptake by spontaneous capillary imbibition was calculated using an analytical solution [ Birdsell et al ., ].…”

“…Therefore, it is likely that organic shales will have mixed hydrocarbon‐water wet surfaces in both organic and inorganic pores and thus the bulk wettability is defined by the phase dominating the wetting behavior. This is why the contact angles of organic‐rich shales vary significantly with different ionic strength solutions on different samples [ Engelder et al ., ; Mirchi et al ., ; Roshan et al ., ; Xu and Dehghanpour , ]. It should therefore be noted that parameters such as pressure, temperature, and ionic strength can significantly contribute to variations in contact angle e.g., when a fracturing fluid invades the organic shale matrix, the rock wettability can alter because of change in pressure and temperature or the reaction of clay minerals with the ions in the injected solution in the invaded zone.…”