Browsing by Author "Vavra, Eric"

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    A systematic approach to alkaline-surfactant-foam flooding of heavy oil: microfluidic assessment with a novel phase-behavior viscosity map
    (Springer Nature, 2020) Vavra, Eric; Puerto, Maura; Biswal, Sibani L.; Hirasaki, George J.
    The apparent viscosity of viscous heavy oil emulsions in water can be less than that of the bulk oil. Microfluidic flooding experiments were conducted to evaluate how alkali-surfactant-foam enhanced oil recovery (ASF EOR) of heavy oil is affected by emulsion formation. A novel phase-behavior viscosity map—a plot of added salinity vs. soap fraction combining phase behavior and bulk apparent viscosity information—is proposed as a rapid and convenient method for identifying suitable injection compositions. The characteristic soap fraction, XSorsoap, is shown to be an effective benchmark for relating information from the phase-viscosity map to expected ASF flood test performance in micromodels. Characteristically more hydrophilic cases were found to be favorable for recovering oil, despite greater interfacial tensions, due to wettability alteration towards water-wet conditions and the formation of low apparent-viscosity oil-in-water (O/W) macroemulsions. Wettability alteration and bubble-oil pinch-off were identified as contributing mechanisms to the formation of these macroemulsions. Conversely, characteristically less hydrophilic cases were accompanied by a large increase in apparent viscosity due to the formation of water-in-oil (W/O) macroemulsions.
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    Application of magnetic nanoparticles as demulsifiers for surfactant-enhanced oil recovery
    (Wiley, 2023) Zhang, Leilei; Bai, Chutian; Zhang, Zhuqing; Wang, Xinglin; Nguyen, Thao Vy; Vavra, Eric; Puerto, Maura; Hirasaki, George J.; Biswal, Sibani Lisa
    Nonionic surfactants are increasingly being applied in oil recovery processes due to their stability and low adsorption onto mineral surfaces. However, these surfactants lead to the production of emulsified oil that is extremely stable and difficult to separate by conventional methods. This research characterizes the stability of crude oil mixed with a nonionic surfactant, L24–22, in a brine solution. When subjected to gravity separation, a middle oil-rich and bottom water-rich emulsion are generated for various water–oil ratios. Thermal treatments can effectively break oil-rich emulsions, but the bottom water layer remains contaminated with micron-sized crude oil droplets. A magnetic nanoparticle treatment is shown to demulsify the crude oil emulsions, dropping the total organic carbon (TOC) in the water layer from 1470 to 30 ppm.
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    Measuring in-situ capillary pressure of a flowing foam system in porous media
    (Elsevier, 2022) Vavra, Eric; Puerto, Maura; Bai, Chutian; Ma, Kun; Mateen, Khalid; Biswal, Lisa; Hirasaki, George
    Hypothesis: Capillary pressure (Pc) is an intrinsic property of aqueous foams that has been demonstrated to play an important role in lamella rupture. Thus, directly measuring in-situ capillary pressure of a foam flowing through porous media has potential to greatly improve understanding of this complex process. Experiments: A capillary pressure probe was constructed and validated. Direct measurements of capillary pressure were made at ambient conditions during foam quality scan experiments in a transparent 1.41 × 10−10 m2 (143-Darcy) homogenous sand pack conducted at constant gas velocity. The foam texture was simultaneously visualized at the wall of the sand pack via microscope. Findings: In the low-quality regime, a plateauing trend in Pc was identified. In-situ microscopic visualization of the flowing foam revealed that gas bubbles were convecting with a fine discontinuous texture while Pc is at the plateau value Ppc. In the high-quality regime, the measured capillary pressures first decreased with increasing quality before increasing again at the driest qualities. These changes in Pc correlated with foam bubbles becoming coarser with increasing injected gas fractional flow before transitioning to continuous-gas flow at the slowest and driest injection conditions. These findings have been previously unreported for steady-state flow conditions and shall have significant implications for the general physical description of foam flow in porous media.