ABSTRACT
Surface wettability has a crucial impact on drop splashing, emulsion dynamics, slip flow for drag reduction, fluid-fluid displacement, and various microfluidic applications. Targeting enhanced oil recovery (EOR) applications, we experimentally investigate the effect of matrix wettability on the invasion morphology and sweep efficiency of viscous oil displaced by different aqueous floods using microfluidics, whose porous network mimics a sandstone structure. For comparison, systematic experiments of the same oil-flood pair are done in both hydrophilic and hydrophobic microfluidic chips. The results show that the hydrophilic microfluidic rock has a remarkable increase in oil recovery by a factor of ≈1.44, compared to the hydrophobic case. In addition, we observe a more pronounced lateral growth of the displacing pattern of aqueous flood for the hydrophilic surface. Finally, we quantitatively explain the increasing factor in the recovery rate and finger width for the hydrophilic vs. hydrophobic rock-liked porous networks by incorporating the contact angle into a scaling analysis.
Subject(s)
MicrofluidicsABSTRACT
Microfluidics methods offer possibilities for visual observations of oil recovery processes. Good control over test parameters also provides the opportunity to conduct tests that simulate representative reservoir conditions. This paper presents a setup and procedure development for microfluidic oil recovery tests at elevated temperature and pressure. Oil recovery factors and displacement patterns were determined in single- or two-step recovery tests using two crude oils, high salinity salt solutions and low salinity surfactant solutions. Neither the displacement pattern nor the recovery factor was significantly affected by the pressure range tested here. Increasing temperature affected the recovery factor significantly, but with opposite trends for the two tested crude oils. The difference was justified by changes in wettability alteration, due to variations in the amounts and structure of the acidic and basic oil fractions. Low salinity surfactant solutions enhanced the oil recovery for both oils.
ABSTRACT
The goal of this article is to test the potential application of lignosulfonates (LSs) in crude oil production and processing. Three LS samples of varying hydrophobicity and average molecular weight were considered. First, the interfacial tension between brine and xylene and interfacial dilational rheology properties of LS samples were measured. It was found that the most surface-active LS sample has the lowest molecular weight in agreement with the results from the literature. In the presence of asphaltenes, all three LS samples were able to compete with asphaltenes, the most polar crude oil component, at the interface and form mixed LS-asphaltene interfaces. However, only the most surface-active LS sample among the three tested could fully desorb asphaltenes at the highest tested LS concentration (500 ppm). Second, three possible applications were screened. LSs were tested to prevent the formation of w/o crude oil emulsions or to break these. However, the opposite effect was observed, that is, stabilization of water-in-crude oil emulsions. The potential application of LS in produced water (PW) clarification was furthermore considered. The kinetics of PW clarification was found unaffected by the presence of LS, even at very high concentrations (1000 ppm). Finally, the potential of LS for enhanced oil recovery was assessed. The LS flood changed the surface wettability toward water wetness for one of the samples, yet LS injection did not recover additional oil beyond brine recovery. It was concluded that LS has interesting properties, such as the potential to compete with crude oil indigenous components at the oil/water interface. The stabilization action of LS was dominant over any destabilization effect, which led to the conclusion that LSs are more efficient for stabilizing emulsions rather than destabilizing.
ABSTRACT
Microfluidics is an appealing method to study processes at rock pore scale such as oil recovery because of the similar size range. It also offers several advantages over the conventional core flooding methodology, for example, easy cleaning and reuse of the same porous network chips or the option to visually track the process. In this study, the effects of injection rate, flood volume, micromodel structure, initial brine saturation, aging, oil type, brine concentration, and composition are systematically investigated. The recovery process is evaluated based on a series of images taken during the experiment. The remaining crude oil saturation reaches a steady state after injection of a few pore volumes of the brine flood. The higher the injection rate, the higher the emulsification and agitation, leading to unstable displacement. Low salinity brine recovered more oil than the high salinity brine. Aging, initial brine saturation, and the presence of divalent ions in the flood led to a decrease in the oil recovery. Most of the tests in this study showed viscous fingering. The analysis of the experimental parameters allowed to develop a reliable and repeatable procedure for microfluidic water flooding. With the method in place, the enhanced oil recovery test developed based on different variables showed an increase of up to 2% of the original oil in place at the tertiary stage.
