Article pubs.acs.org/EF
Enhanced Oil Recovery (EOR) Using Nanoparticle Dispersions: Underlying Mechanism and Imbibition Experiments Hua Zhang, Alex Nikolov, and Darsh Wasan* Department of Chemical and Biological Engineering, Illinois Institute of Technology, Chicago, Illinois 60616, United States S Supporting Information *
ABSTRACT: This paper presents the results of imbibition tests using a reservoir crude oil and a reservoir brine solution with a high salinity and a suitable nanofluid that displaces crude oil from Berea sandstone (water-wet) and single-glass capillaries. The Illinois Institute of Technology (IIT) nanofluid is specially formulated to survive in a high-salinity environment and is found to result in an efficiency of 50% for Berea sandstone, compared to 17% using the brine alone at a reservoir temperature of 55 °C. We also present a direct visual evidence of the underlying mechanism based on the structural disjoining pressure for the crude oil displacement using IIT nanofluid from the solid substrate in high-salinity brine. These results aid our understanding of the role of the nanofluid in displacing crude oil from the rock, especially in a high-salinity environment containing Ca2+ and Mg2+ ions. Results are also reported using Berea sandstone and a nanofluid containing silica nanoparticles.
1. INTRODUCTION Emerging nanotechnologies, such as nanofluids composed of liquid suspensions of nanoparticles, may soon allow for the accelerated recovery of hydrocarbons and stimulation fluids from oil and gas reservoirs.1 Recently, Suleimanov et al.2 reported the results of an experimental study of nanofluids comprising aqueous suspensions of nonferrous metal nanoparticles (70−150 nm) dispersed in an aqueous solution of an anionic surfactant (sulfanole-alkyl aryl sodium sulfonate), which resulted in an increase in the efficiency of the oil displacement by 35%, compared to that obtained using a surfactant solution alone in a homogeneous porous medium and 17% in a heterogeneous porous medium at a temperature of 25 °C. They used a pure hydrocarbon in their tests. These investigators concluded that the increase in enhanced oil recovery (EOR) was due to the decrease in the interfacial tension and change in the flow characteristic of nanofluids moving from a Newtonian to non-Newtonian state. They also observed that the oil wettability practically remained unchanged with the nanofluids. Babadagli et al.3 investigated capillary imbibition as an oil recovery mechanism using different surfactants and polymer solutions as they believed that the reduction in the interfacial tension between the aqueous phase and oil was the cause of faster and greater oil recovery. Karimi et al.4 reported that the increase in the oil recovery using nanofluids composed of zirconium oxide nanoparticles (24 nm) and a nonionic surfactant (ethoxylated nonylphenol) resulted primarily from the wettability alteration of the carbonate rocks from strongly oil-wet to strongly water-wet. However, they showed that the wettability alteration requires at least 2 days, while the maximum oil recovery rate occurs shortly after contact between the nanofluids and core plugs. In summary, two classic mechanisms of EOR using nanofluids have been proposed, namely, the lowering of the interfacial tension between the aqueous phase and oil phase, and the rock wettability alteration. In some instances, both mechanisms are believed to be operating.5−7 © XXXX American Chemical Society
More recently, a new view of oil displacement from a solid substrate using nanoparticle dispersions (nanofluid) with a wetting agent has been proposed by Wasan and Nikolov.8 The experiment results and theoretical calculations first reported in their paper published in the journal Nature are based on a novel concept of nanoparticle structuring (layering) in the wedge film. They showed that the nanoparticle (or surfactant micelles) form two-dimensional (2-D) layered structures in the confines of the three-phase (solid−oil−aqueous phase) contact region of a wedge film formed between an oily soil and the solid substrate (see Figure 1). The nanoparticle structuring phenomenon gives rise to the structural disjoining pressure (a force normal to the interface) in the wedge film and the structural disjoining pressure is higher near the tip of the wedge than that in the bulk meniscus (Figure 2). As a result of the pressure increase, the oil/ nanofluid interface moves forward and the nanofluid spreads over the solid surface, detaching the oily soil (Figure 1). The magnitude of this pressure depends on the effective nanoparticle volume fraction, particle size, polydispersity, and particle charge. Kao et al.9 observed two distinct contact lines: an outer one (between the oil, solid, and water film) and an inner one (between the oil, solid, and mixed oil/water film). Wasan and Nikolov and their co-workers10−14 further noted that the dynamics of the contact line are dependent on the combination of the nanoparticle formulation, contact angle, and the capillary pressure. A suitable combination of these factors accelerates the spreading of the nanofluid on the solid surface, thereby detaching the oily soil from the substrate. Funded in part by FracTech Service, LLC, an exploratory project was carried out in Dr. Wasan’s laboratory at Illinois Institute of Technology (IIT), in which the performance of the Received: January 28, 2014 Revised: April 14, 2014
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dx.doi.org/10.1021/ef500272r | Energy Fuels XXXX, XXX, XXX−XXX
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Article
Figure 1. Oil−solid displacement driven by film tension gradient and the role of structural forces.
Table 1. Crude Oil Properties property
value
asphaltene content acid number density at 25 °C viscosity of oil at 25 °C viscosity of oil at 50 °C
2.54% 2.14 0.94 (g/cm3) 94.88 cP 24.58 cP
2.1.2. Brine Solution. Brine was prepared by dissolving different salts in deionized (DI) water based on the composition of seawater. The density of brine was 1.02 ± 0.01 g/cm3 and pH 8.5 ± 0.5 at 25 °C. Table 2 lists the composition of the brine used in this study.
Table 2. Brine Composition Figure 2. Pressure on the walls of the wedge for a contact angle of 0.5° at the vertex as a function of the radial distance. Particle volume fraction, φ = 0.36; particle diameter, d = 10 nm.
IIT nanosized hydrophilic silica dioxide particles (19 nm in diameter, 10 volume percent in concentration) and Texas crude oil (33° API) were compared with the microemulsion additive used in industry. The nanofluid formulation utilizing the novel mechanism of the structural disjoining pressure by nanoparticle structuring in the wedge film outperformed the microemulsion additive by 20% in crude recovery when applied using the same percentage by volume. Based on these preliminary results, FracTech (with Holcomb, Wasan, and Nikolov) filed a patent application on October 15, 2009.15 FracTech has subsequently explored the use of nanoparticle dispersions in some other treatments such as paraffin, asphaltene, slurry removal, and recovery hydrocarbon from tar sands.16,17 The objective of the present research effort at IIT is to develop nanoparticle formulations that will enhance oil recovery from the petroleum reservoir. The specific aim of the work reported here is to develop the nanoparticle formulation to survive in a high-salinity environment containing Ca2+ and Mg2+ ions and observe directly the underlying mechanism based on the structural disjoining pressure concept using the reservoir crude oil and high salinity brine. The paper presents the results of the imbibition experiments using two types of nanofluids: silica nanofluid and IIT nanofluid,18 and crude oil presaturated Berea sandstone. We also present the results of the imbibition experiments performed using single glass capillaries to visualize the oil displacement process.
component
concentration (g/L)
NaCl KCl MgCl2·6H2O CaCl2 Na2SO4 NaHCO3
18.83 0.609 0.584 0.139 0.109 0.203
2.1.3. Silica Nanofluid. A colloidal dispersion of silicon(IV) oxide in water (40 wt %, Alfa Aesar) was diluted with deionized (DI) water to prepare the 10 vol % silica nanofluid that had a nominal (geometric) diameter of 20 nm, with a density of 1.15 g/cm3 and pH of 9.7. 2.1.4. IIT Nanofluid. Since most reservoirs are at a high temperature, high pressure, and high salinity, silica nanoparticles dispersions are often unstable and agglomerate in such harsh environments. IIT nanofluid (patent applied) is not sensitive to electrolytes or temperature and is stable in the harsh reservoir environment, which we can choose to formulate the nanofluid. IIT nanofluid was dissolved in the brine solution to prepare nanoparticle dispersion. We optimized the wetting characteristics of the solid surface by using an appropriate amount of a wetting agentsodium dodecyl sulfatein the IIT nanofluid in order to decrease the solid/ nanofluid/crude oil three-phase contact angle and maximize the structural force resulting from the confinement of the nanoparticles in the wedge film. 2.1.5. Berea Sandstone. Berea sandstone (length × width × thickness: 7.6 cm × 2.8 cm × 0.6 cm) was obtained from FracTech with a porosity of 20% and permeability of 400 md. 2.2. IIT Nanofluid Characterization. In order to optimize the nanofluid formulation and enhance the effect of the structural disjoining pressure on the crude oil recovery process, the nanofluid composition was selected using a multistep process. First, the nanofluid needed have a small nanoparticle size and have a low polydispersity. High polydispersity results in a decreased value for the structural disjoining pressure. For example, Chu et al. indicated that a 20% polydispersity in particle size can result in a 30% decrease in the structural disjoining pressure.19 Second, the formulated nanofluid should have a high osmotic pressure (e.g., higher than ∼200 Pa for a 10 vol % nanofluid). Trokhymchuk et al.20 developed an analytical expression for the
2. EXPERIMENTAL SECTION 2.1. Materials. 2.1.1. Crude Oil. Crude oil was used for all tests without further treatment. Properties of the crude oil are given in Table 1. B
dx.doi.org/10.1021/ef500272r | Energy Fuels XXXX, XXX, XXX−XXX
Energy & Fuels
Article
2.2.2. Osmotic Pressure Measurement. The osmotic pressure of the IIT nanofluid is calculated using the value of the second virial coefficient. The second virial coefficient is calculated based on the turbidity and refractive index measurement of the nanofluid, which is represented as Debye plots. Turbidity measurements were made using the Hach Model 2100A turbidimeter at a temperature of 25 ± 1 °C. The instrument was calibrated using an aqueous solution of a nonionic surfactant, NEODOL 25−12, obtained from Shell Chemical. The calibration is shown as a Debye plot in Figure 4.
structural disjoining pressure (Πst), based on a solution of the Ornstein−Zernike statistical mechanics equation:
⎧ 0
