Article pubs.acs.org/EF
Effects of the Initial Rock Wettability on Silica-Based NanofluidEnhanced Oil Recovery Processes at Reservoir Temperatures Luky Hendraningrat* and Ole Torsæter Department of Petroleum Engineering and Applied Geophysics, Norwegian University of Science and Technology, NTNU, NO-7491, Trondheim, Norway ABSTRACT: Coreflood experiments were conducted to evaluate the impact of the initial rock wettability on oil recovery during a tertiary oil recovery process using hydrophilic silica-based nanofluids at reservoir temperatures. An adopted scale of reservoir wettabilities (water-, intermediate-, and oil-wet systems) is used for the core plugs, which were prepared by aging processes. The relationships among temperature, initial wettability, and an additional oil recovery nanofluid flooding process were investigated. The results showed that the initial wettability affects oil recovery performance and showed a greater effect at higher temperatures, as represented by the reservoir temperature. An extended postflush nanoflooding was performed to evaluate incremental oil recovery, and this cycle shows great potential for field applications. By evaluating the contact angle and interfacial tension, it was found that wettability alteration plays a more dominant role in the oil displacement mechanism via nano-EOR. These results reveal a potential way to use silica-based nanofluid for enhanced oil recovery purposes for a wide range of reservoir wettabilities at a given reservoir temperature.
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they become hydrated.11 NPs easily aggregate because they have a large surface-area-to-volume ratio (due to the small particle size). Therefore, NPs possess a high surface energy that alters the wettability of the system.12 NPs consequently form into aggregates to minimize surface energy.13 In these studies, laboratory experiments were designed to establish the relationship between adopted scales of reservoir wettabilities (water-, intermediate- and oil-wet systems) and oil recovery due to nanofluids at reservoir temperatures. The reservoir rock (i.e., core plugs) used in this study was originally strongly water-wet (SWW). The crude oil, NPs, nanofluids and reservoir rocks were characterized. Aging processes were conducted to alter the wettability of the core plugs, which became intermediate- or oil-wet systems. A two-phase coreflood experiment was performed by injecting silica-based nanofluid as a tertiary process (nano-EOR) through Berea sandstone cores with various wettability systems at different temperatures. An injection cycle scheme was developed to show the great potential of using silica-based nanofluids in future EOR methods. The COBR interaction was observed using contact angle measurements in both water- and oil-wet systems on quartz plates, which were used as the solid-phase, to reveal the possible oil displacement mechanism. In addition, fluid−fluid interaction (oil/brine/nanofluid) experiments were performed using interfacial tension (IFT) measurements at various temperatures.
INTRODUCTION Understanding the relationships among wettability, capillary pressure, and the distribution of oil and water in pore spaces is critical for optimizing oil recovery and is a necessary, difficult step in quantifying wettability and its relation to oil recovery.1 These relationships are complex within crude oil/brine/rock (COBR) systems because of the complexity of pore structures and reservoir rocks mineralogy.1 Wettability also affects the relative permeability, which controls the flow and spatial distribution of fluids in a porous medium.2 However, wettability is not the only parameter that controls the relative permeability curves. Anderson2 stated that the relative permeability curves will also be affected by pore geometry, fluid distribution, saturation, and saturation history. Therefore, determining the reservoir wettability and its effect on oil recovery using methods involving core samples is referred to as advanced core analysis for wettability.1 In the past decade, most investigations have shown that nanoparticles (NPs) offer promise for future enhanced oil recovery (EOR) processes where silica-based NPs have been most commonly used.3−6 Although the oil displacement mechanism via NPs is not yet clearly understood, Wasan and Nikolov,7 Chengara et al.,8 and Wasan et al.9 concluded that the structural disjoining pressure is an important mechanism. The structural disjoining pressure is correlated to the fluid’s ability to spread along the surface of a substrate due to an imbalance of the interfacial forces among the solid, oil, and aqueous phases.8 The NPs create ordered structures (a wedge-film) near the three-phase contact line (wetting wedge) of a drop on a solid surface, which promotes spreading of the nanofluid along the surface as a monolayer of particles. The thickness of the structures is determined by a balance between the van der Waals attractive forces and repulsion by electrostatic and hydration forces.10 A zero contact angle of the aqueous phase means that the nanofluid has completely spread and has a notably large surface area. Most NPs tend to aggregate once © XXXX American Chemical Society
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EXPERIMENTS Crude Oil. A degassed light crude oil was used in this study, which had a density of 0.83774 g/cm3 (API gravity 38°) at 15.5 °C (60 °F) and 0.8260 g/cm3 at 22 °C. It has a viscosity of Received: June 12, 2014 Revised: August 25, 2014
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dx.doi.org/10.1021/ef5014049 | Energy Fuels XXXX, XXX, XXX−XXX
Energy & Fuels
Article
approximately 5.1 cP at 22 °C. This crude oil was characterized for its saturates, aromates, resins, and asphalthens (SARA), and the results are presented in Table 1. The total acid number Table 1. SARA Analysis at Room Condition sample
saturates
aromates
resins
asphalthens
1.88
0.41
(wt %) crude oil
75.12
22.59
(TAN) and base number (TBN) values were measured in a laboratory condition using an 809 Titrando titration system from Metrohm based on the standard procedure.14 The TAN and TBN were
