Visualization of Oil Mobilization in ASP Core Floods Using X-ray CT Imaging

Abstract

This paper describes a series of experiments that used X-ray computer tomography (CT) to visualize the mobilization of remaining oil by Alkaline Surfactant (AS) and Alkaline Surfactant Polymer (ASP) flooding after conventional waterflooding. The experiments were conducted in cores drilled from Gildehauser and Bentheimer sandstone outcrop material with diameters of approximately 7.55 cm and lengths of approximately 27 cm and one meter. Crude oil with in-situ viscosities of 1.3, 2.3 and 100 cP was used in the experiments. The changes in the fluid saturation distributions with time obtained with X-ray computer tomography are subsequently used to improve the conceptual understanding of the ASP process. In addition to pressure and effluent data collected during conventional core flood experiments, phase and saturation distributions in space and time are needed to more completely interpret the results of core floods. This additional information reveals underlying mechanisms, and assists the development of models that capture the physics of ASP that can ultimately be used to provide field scale predictions for ASP performance. One important observation from the experiments is that there exist a consistent fingering pattern in the zone upstream of the oil bank. Although fingering is often considered a bad sign for a displacement process the experiments also demonstrate that the fingering zone is contained in the area upstream of the oil bank and that the velocity of the front of the oil bank is significantly greater than that of the fingering zone. The production following the clean oil bank (tail) observed in many ASP core floods is a consequence of the formation of this fingering zone. Effluent analyses conducted on the produced fluids from the long core experiments showed a sharp, rapid build up in polymer viscosity that coincides with the beginning of the tail production while the surfactant concentration only gradually increases to its injection value during the tail production. Another important observation is that a characteristic self-similar cross-sectional averaged oil saturation profile develops during ASP injection after water flood in cores containing reactive crude oil with 100 cP viscosity and in non reactive light crude oil. The implications of the self-similarity of the saturation profiles in combination with the observation that the surfactant propagation is retarded with respect to the polymer propagation results in a polymer flood ahead of the ASP-slug and a corresponding characteristic oil production profile. The characteristics of this process can be captured with an extended fractional flow approach that utilizes three fractional flow curves: one for the ASP-slug, one for polymer, and the original fractional flow curve for oil-water.

Effect of In-situ Dual Surfactant Formulation on Spontaneous Oil Deformation: A Comprehensive Study from Mechanism Discovery to Oil Recovery Application

“…It is noteworthy that the chemical solution was directly injected to displace the oil phase without connate water conditions. That is, the STAC flooding was applied as the secondary oil recovery mode, which is different from the tertiary mode that has an initial water saturation . However, our objective in the macroscale displacement is to observe the good control of stable displacement using the STAC agent.…”

“…That is, the STAC flooding was applied as the secondary oil recovery mode, which is different from the tertiary mode that has an initial water saturation. 48 However, our objective in the macroscale displacement is to observe the good control of stable displacement using the STAC agent. Therefore, the secondary mode is enough to reach our end.…”

The effectiveness of computed tomography for the experimental assessment of surfactant-polymer flooding

“…For this reason, several authors have presented results including Computed Tomography (CT). They are Batenburg et al (2015) [8], London et al (2014) [9], Hove et al (1990) [10], Hunt et al (1988) [11], Wang et al (1984) [12], Wellington and Vinegar (1987) [13], Vinegar and Wellington (1987) [14], Withjack (1988) [15], Withjack et al (2003) [16], Wan et al (2019) [17], Ouali et al (2019) [18]. It is important to highlight that core-flooding tests allow calibrating field simulation models reducing uncertainties on rockfluids interactions.…”

Complex fluids with visco-elastic rheology for applications in oil & gas industry

“…3. Imaging an ASP experiment at the meter scale using a medical CT scanner [9][10][11][12] where residual oil present after water flooding (approx.. 40%) is displaced by alkaline surfactant polymer solution with ultralow interfacial tension, reveals that even when there is a viscosity match between displacing and displaced fluid, there is still viscous fingering present. The reason is most likely a relative permeability effect (the stability criteria for immiscible displacement in porous media is a matter of mobility ratio which is the ratio of relative permeability over viscosity, and not just viscosity ratio [13]).…”

“…Viscous fingering is present in the zone following the oil bank, but the profiles for different pore volume fractions of ASP solution collapse on top of each other suggesting still an overall stable displacement[9][10][11][12]. When the viscosity of the ASP solution has been increased 2× compared with crude oil (B), viscous fingering is now diminished with the saturation front between the fingering zone and the oil bank being sharper and the fingering zone itself shorter compared with (A)[9][10][11][12]. Figure modified from[9].…”