Probing the Effect of Oil Type and Saturation on Foam Flow in Porous Media: Core-Flooding and Nuclear Magnetic Resonance (NMR) Imaging

Abstract

The success of foam displacement in porous media largely depends on its stability, which is adversely impacted by the presence of oil. In this study, we present the results of an experimental investigation into the effect of oil type and saturation on foam rheology in Berea sandstone using the nuclear magnetic resonance imaging technique. The results of foam quality scan in the presence of remaining hexadecane was compared with those from the oil-free case. We showed that the calculated apparent viscosity values in the presence of remaining hexadecane were higher than those in the absence of oil except at very high foam qualities. This was attributed to the dominance of relative permeability reduction and generation of oil-in-water emulsions over the foam-weakening effect of oil. A closer analysis of the fluid distribution further allowed us to quantify the relative significance of the identified oil displacement mechanisms, namely, the increased capillary number, and the micellar solubilization. Additionally, we correlated the foam strength with the oil saturation from the foam-oil co-injection tests. Because of the detrimental effect of oil on foam stability, it is found that the apparent viscosity first decreases with increasing oil (hexadecane and octane) saturation; then, due to oil emulsification, apparent viscosity increases with oil saturation (or more strictly with the oil fractional flow). Compared to octane, hexadecane resulted in less foam destabilization and higher oil emulsification. The co-injection experiment with crude oil exhibited a similar behavior to octane. Findings from this study suggest that, despite the destabilizing impact of oil on foam, the resulting steady-state apparent viscosities could be much larger than the viscosity of the in situ oil. This leads to a favorable mobility ratio during the oil-displacement process.

A systematic approach to alkaline-surfactant-foam flooding of heavy oil: microfluidic assessment with a novel phase-behavior viscosity map

“…Therefore, oil-in-water (O/W) emulsions could have a viscosity closer to that of the water than that of the oil 17 . In porous media, provided the oil saturation is below a certain value 18 , emulsifying the oil as an oil-in-water emulsion can similarly decrease apparent viscosities. Several researchers have demonstrated the promising process of recovering heavy oil as a low viscosity oil-in-water emulsion 13,[19][20][21][22] .…”

Exergy return on exergy investment analysis of natural-polymer (Guar-Arabic gum) enhanced oil recovery process

“…In Section "Case study: WAG, SAG and WAG + S" where the oil phase is present, function F oil is introduced to account for the effect of oil on foam. Oil can destabilize foam in porous media by varied mechanisms [15,25,33,63,64]. In this simulation, the parameter floil represent the oil saturation below which oil does not affect foam strength and F oil equals to 1, whereas the parameter fmoil represent the oil saturation above which foam is completely killed and F oil equals to 0.…”

Synergistic Effects between Anionic and Sulfobetaine Surfactants for Stabilization of Foams Tolerant to Crude Oil in Foam Flooding

“…On the other hand, foam flooding using conventional commercial surfactants has become another attractive technique and has been paid more attention recently (Amirmoshiri et al, 2018; Bashir et al, 2019; Chen et al, 2018; Da et al, 2018; Hosseini‐Nasab and Zitha, 2017; Hurtado et al, 2018; Jian et al, 2015; Lu et al, 2017; Manan et al, 2015; Pu et al, 2019; Rezvani et al, 2020; Risal et al, 2018; Wang et al, 2009, 2019; Xu et al, 2020; Yang et al, 2017; Yekeen et al, 2017; Zhu et al, 2004). Foam flooding greatly improved the efficiency of gas injection for enhanced oil recovery (EOR), which suffers from problems such as gas segregation, viscous fingering, and gas channeling through high‐permeability zones so that poor sweep efficiencies were usually obtained (Da et al, 2018; Hosseini‐Nasab and Zitha, 2017; Xu et al, 2020; Zhu et al, 2004).…”

“…However, the success of foam flooding depends strongly on foam stability (Amirmoshiri et al, 2018; Jian et al, 2015; Wang et al, 2019; Yang et al, 2017; Yekeen et al, 2017), which is correlated with the liquid drainage in lamellae, surface dilatational elasticity, and strength of the surfactant films (lamellae) (Wang et al, 2009), whereas the foam stability in porous medium is affected by several factors, including temperature, pressure, surfactants used, the presence of oils, electrolytes, polymers, and solid particulate materials (Chen et al, 2018; Hurtado et al, 2018). Many improved foaming systems for foam flooding have been reported in which the protocols for increasing foam stability include addition of nanoparticles (Bashir et al, 2019; Hurtado et al, 2018; Lu et al, 2017; Manan et al, 2015; Rezvani et al, 2020; Risal et al, 2018; Xu et al, 2020; Yang et al, 2017; Yekeen et al, 2017; Zhou et al, 2018), polymers (Bai et al, 2019; Jian et al, 2015; Sun et al, 2015a; Zhu et al, 2004), and alcohols (Chen and Zhao, 2015) and use of mixed surfactants (Hosseini‐Nasab and Zitha, 2017; Wang et al, 2016), branched surfactants (Wang et al, 2009), and fluorine‐containing surfactants (Jian et al, 2015; Wang et al, 2016) etc .…”

“…Among the factors to damage foam stability, the presence of oils is usually detrimental (Amirmoshiri et al, 2018; Chen et al, 2018; Hussain et al, 2019; Pu et al, 2019), which usually behave as excellent defoamers, although positive role of the oils to foam stability has also been reported when they are trapped in foam lamellae as emulsified oil droplets (Pu et al, 2019). As for the relationship between foam stability and oil displacement efficiency, some studies concluded that foam stability was not a necessary requirement in EOR (Pu et al, 2019) and no correlation between bulk foam stability and displacement efficiency was observed (Amirmoshiri et al, 2018), but more studies insisted that foams with high stability are in favor of enhancing oil recovery (Bai et al, 2019; Bashir et al, 2019; Chen and Zhao, 2015; Hosseini‐Nasab and Zitha, 2017; Hurtado et al, 2018; Jian et al, 2015; Lu et al, 2017; Manan et al, 2015; Pu et al, 2019; Rezvani et al, 2020; Risal et al, 2018; Sun et al, 2015; Wang et al, 2009, 2016; Xu et al, 2020; Zhang et al, 2019; Zhou et al, 2018; Zhu et al, 2004).…”