Article pubs.acs.org/EF
Enhanced Heavy Oil Recovery Using TiO2 Nanoparticles: Investigation of Deposition during Transport in Core Plug Hamide Ehtesabi,† M. Mahdi Ahadian,*,† and Vahid Taghikhani†,‡ †
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Institute for Nanoscience and Nanotechnology (INST), Sharif University of Technology, P.O. Box 11155-1639, Tehran, 14588−89694 Iran ‡ Chemical and Petroleum Engineering Department, Sharif University of Technology, P.O. Box 11155-1639, Tehran, 14588−89694 Iran ABSTRACT: Although application of nanoparticles in enhanced oil recovery has been reported, understanding the transport and retention of nanoparticles in the oilfield reservoir is still a crucial issue. In this research, behavior of low concentration of TiO2 nanoparticles in core plug porous media and the mechanism of increasing oil recovery were investigated. Flooding test with a concentration of 0.01% TiO2 nanoparticles showed improvement in sweeping heavy oil from 41% to 55%. Inductively coupled plasma results on the exiting effluent of the flooding test with a concentration of 0.05% TiO2 nanoparticles showed the presence of only 0.5% of injected nanoparticles, which indicates high affinity of the nanoparticles for deposition in porous media. The total amount of deposited TiO2 extracted from different cross sections of the core plug was consistent with the difference of injected and exited TiO2 material. At the entrance side, the amount of deposited TiO2 was high but decreased significantly in 0.1 cm depth, and reduces linearly versus distance. On the basis of surface area estimation of the core plug, only about 1% of the internal surface was deposited by nanoparticles. The viscosity, interfacial tension, and contact angle measurements showed that the main mechanism for increasing oil sweeping is changing the wettability of the rock surface from oil-wet to water-wet due to deposition of TiO2 nanoparticles. The role of the low concentration nanofluid in rapidly displacing crude oil from the rock surface may be described by gradient pressure of nanoparticles in the three-phase contact wedge of oil, nanofluid, and rock surface.
1. INTRODUCTION Enhanced oil recovery (EOR) techniques are gaining more attention worldwide as the proved oil is declining and the oil price is hiking. Although many giant oil reservoirs around the world were already screened for EOR processes, the main challenges, such as low sweep efficiency, costly techniques, possible formation damages, transportation of huge amounts of EOR agents to the fields, especially for offshore cases, and the lack of analyzing tools in traditional experimental works, hinder the proposed EOR process.1 It has been shown that, recently, nanoparticles are attractive agents to enhance the oil recovery at the laboratory scale.2−12 The experiences on using nanoparticles to the EOR processes revealed solutions to some of the challenges associated with old EOR techniques. Many investigations have reported the promising results in increasing the oil recovery by injecting nanofluids due to increasing the viscosity of nanofluids, decreasing interfacial tensions, and changing the wettability of the cores from oil-wet to water-wet.8,10,11 TiO2 nanofluid as an inexpensive and environmentally friendly material can be used at low concentration, which was introduced in our latest report.11 In high pressure and elevated temperature, the structure of the introduced TiO2 nanoparticles will not change due to synthesizing without surfactants or polymers for modifying or coating the nanoparticles. Furthermore, photocatalytic characteristic of the remaining TiO2 nanoparticles in the exiting effluent helps degradation of oil pollutions under solar radiation. Although various applications of nanoparticles in the EOR have been reported, challenges in using nanoparticles in the © 2014 American Chemical Society
oilfield are expected due to complicated local conditions, such as high salinity, low permeability, and heterogeneous rock properties.13−16 The nanofluid should verify these conditions for EOR:16 (1) Stability in high salinity, elevated temperature, and high pressure without causing aggregation; (2) propagation into the reservoir in long distance between the injection and production wells; (3) adsorption onto desired critical sites of the reservoir such as the oil/water interface; and (4) deposition as one layer and prevent overdeposition, which this condition avoids plugging. Nevertheless, the oilfield conditions are significantly more complicated than most of the experiments and mathematical modeling, which have been performed under simple conditions.14 One of the crucial issues is understanding the transport and retention of nanoparticles in the oilfield reservoir. However, the transport of nanoparticles in porous media for oil recovery has been less investigated.13 Alaskar et al. conducted injection experiments with Ag nanowire, hematite nanorice, Sn-Bi nanoparticle, and silica microsphere injections to assess the parameters involved in nanoparticle mobility in a reservoir rock.17 They measured the quantity of the materials produced using fluorescence spectrometry, ultraviolet−visible spectroscopy, scanning electron microscopy (SEM), and optical microscopy. They showed that the size, shape, and surface charge of the particles were considered to be influential parameters leading the transport of nanoparticles through porous media. A series of nanoparticle Received: July 12, 2014 Revised: November 2, 2014 Published: November 24, 2014 1
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were done on a ZEISS ΣIGMA. X-ray diffraction (XRD) data were collected with a Stoe Stadi-P. For determining the temperature stability of TiO2 nanoparticles, TGA and DTA were performed using an STA PT1600 from Linseis Company in an air atmosphere with a heating rate of 10 °C/min. In order to identify the mechanism of the nanoparticles’ effect in EOR, we measured the viscosity using a DV-E viscometer from Brookfield. Pendant drop from Fars EOR Technology was used to determine the IFT of oil in 5000 ppm brine and nanofluid medium. Contact angle measurements were done using an instrument manufactured by Fars EOR Technology. A thin cross section of the core plug was aged, and the contact angle of an oil drop in brine and nanofluid was measured at room temperature. 2.3. Water Flooding Experiments. EOR experiments were carried out based on the water flooding method using the three-phase relative permeability apparatus from Alberta Research Council. System pressure, temperature, and injection rate were about 1500 psi, 75 °C, and 0.5 mL/min, respectively. Before conducting EOR experiments, core plug washing by a Soxhlet extractor (using toluene and methanol solvent) and core plug drying in an oven at 70 °C for 4 h were carried out. The dimensions of the core plug were measured to be 3.7 cm in diameter and 6.3 cm in length with a volume of 71.8 cm3. The pore volume was found to be 23 cc. XRF results showed 73.1% CaCO3, 19.4% SiO2, 1.3% Al2O3, 3.8% Fe2O3, 0.8% MgO, 1.1% Na2O, and 0.3% K2O as the components of the core plugs. An SEM image of the core plug before water flooding is shown in Figure 1.
transport experiments in core plugs and in packed columns were conducted by Zhang et al.18 They estimated the mass of nanoparticles within the column by the difference of the injected and the eluted mass. Their analysis indicated that the adsorption capacities are typically much less than monolayer coverage but cannot be considered as an intrinsic property of a porous medium nor of the nanoparticle. Instead, they are influenced by operating conditions. Hendraningrat et al. used metal oxide-based nanoparticles for EOR recovery in different wettability conditions.19 They identified the particle adsorption during the transport process from effluent analysis. The pH and surface conductivity of the effluent were analyzed. On the basis of the measurements, the pH value and surface conductivity of injected brine were altered in cores before and after injection of nanoparticles. The effluent became more acidic (lower pH) and the surface charge increased, which may have occurred due to adsorption of nanoparticles during transport through the porous medium, resulting in wettability alteration. Yu et al. performed static experiments to study nanosilica adsorption.13 They poured the core samples into different nanosilica flasks. The flasks were placed into a mechanical shaker and agitated continuously. A sample was removed from the flask at every designated interval. The collected sample was filtered, and silicon concentration in the liquid was determined by inductively coupled plasma (ICP). The concentration differences between the stock and the sample were used to evaluate nanoparticle adsorption behavior. Nevertheless, a lack of understanding of the nanoparticle’s amount in different parts of the core plug during flooding hinders the suggestion of a more accurate model of the nanofluid flooding mechanism in EOR. Material balance of the nanoparticles can get more information about the nanoparticles’ behavior during EOR studies. In the presented study, developing a characterization method based on analyzing the nanoparticle amount in the rock medium and effluent are conducted to investigate the material balance of nanoparticles in flooding tests. For the mass balance equation, TiO2 amounts in the effluent and different places of the core plugs were analyzed using ICP tests. Transmission electron microscopy (TEM), thermal gravimetric analysis (TGA), and differential thermal analysis (DTA) were done as the complementary characterization of the synthesized nanoparticles. The viscosity, interfacial tension (IFT), and contact angle measurements were performed to find the main mechanism in increasing the oil sweeping efficiency. Our findings contribute to the basic understanding of the enhanced wetting behavior of nanofluids. This study may provide more insight into understanding the adsorption, transport, and retention properties of the nanoparticles for improvement in EOR applications.
Figure 1. SEM image of the core plug before water flooding experiment. The core plug was fixed in a stainless steel core holder and evacuated using a vacuum pump for 4 h. Then, the core plug was saturated with brine of 5000 ppm of NaCl. In the next step, heavy oil was injected with rate of 0.5 mL/min until no more water exited. Oil in place was calculated from the volume of outlet water and dead volume. The 5000 ppm brine was used for the first water flooding test. The results of adding 0.01% and 0.05% TiO2 anatase nanoparticles to the brine were obtained afterward. The total amount of recovered oil was calculated from the ratio of measured recovered oil to total oil in place. In addition, the properties of the used oil in EOR experiments for this study were: density, 0.92 g/cm3; kinematic viscosity, 44.79 cSt; dynamic viscosity, 41.21 cP; and asphaltene content, 6.5%. 2.4. Ti Mass Balance in Core Plug. Material balance of Ti was measured using ICP from Spectro (model Arcos) with an argon source. Low concentration brine (5000 ppm) was selected to increase the accuracy of the ICP measurements to prevent line interference and
2. MATERIALS AND METHODS 2.1. Synthesis and Fabrication of Nanofluids. A colloidal suspension of TiO2 nanoparticles was synthesized by mixing titanium tetra-isopropoxide, H2O2, and H2O with volume proportions of 12:90:200, respectively. Suspension of amorphous nanoparticles was obtained for this procedure, which is applicable for EOR without further treatment. The resulting solution was refluxed for 10 h to promote the crystallinity.20 All chemicals were purchased from Merck. 2.2. Characterizations. To identify the core components, X-ray fluorescence spectroscopy (XRF) was used from Spectra Company (Xepos model). TEM from Phillips (model CM30) was employed for observing the shape and the size of nanoparticles. SEM measurements 2
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reduce the effect of NaCl impurities. The concentration of nanoparticles was 0.05% in these experiments to ensure detection of Ti. For measurement of the exiting nanoparticles, samples were collected from the outlet fluid during flooding tests in different pore volume injections. To investigate the concentration of deposited nanoparticles, cross sections of a core plug with a 0.1 cm thickness were prepared and powdered. Fresh piranha solution was prepared as a 3:1 mixture of concentrated sulfuric acid to hydrogen peroxide solution for extracting TiO2 nanoparticles from the core plug. A 5 mL aliquot of the piranha solution was poured on the 0.2 g of the section’s powder. After 24 h, the solution was filtered for ICP test to determine the amount of deposited TiO2 on the rock.
3. RESULTS AND DISCUSSION 3.1. Characterization of Nanofluid. Figure 2 shows a typical TEM image of the particles. The nanoparticles are
Figure 4. TGA and DTA results of TiO2 nanoparticles in an air atmosphere.
water flooding tests. Table 1 shows the results of water flooding tests. The recovery factors of oil were 41 ± 1%, 55 ± 1%, and Table 1. Recovery Factor Results after the Flooding Test with Different Injection Materials
brine 5000 ppm 0.01% TiO2 0.05% TiO2
Figure 2. TEM image of synthesized TiO2 nanoparticles.
oil in place (%)
connate water saturation (%)
recovery factor (%)
87 85 80
13 15 20
41 55 51
elongated with average long and short axis sizes of 54 and 15 nm. The XRD pattern shows the anatase crystalline phase (Figure 3). On the basis of the Debye−Scherrer equation, the size of crystallite was calculated to be about 58 nm, which is in agreement with TEM result.
Figure 5. Recovery factor of flooding tests in different pore volume injections.
51 ± 1%, respectively. Figure 5 shows outlet oil during different pore volumes of brine injection. According to these results, breakthrough occurred at about 0.5 pore volume during brine injection and the addition of nanoparticles did not have a significant effect on it. The difference of oil recovery in brine and nanofluid flooding appeared from the initial stages of injection, and the effectiveness of nanoparticles in oil recovery increased as the injected pore volume increased. During brine injection, oil recovery saturated in two pore volumes, while, in nanofluid injection, oil recovery continued. Figure 6 presents the differential pressure along the core plug in different pore volumes during flooding tests. Two-phase flow occurs from the beginning of injection and increases the
Figure 3. XRD pattern of TiO2 nanoparticles indicating anatase phase.
The stability of nanoparticles in brine was confirmed up to 48 h using optical transmission as presented in our previous work.11 The TGA result of TiO2 nanoparticles in air indicated that, up to 500 °C, the nanofluid has temperature stability without degradation or decomposition (Figure 4). These results confirm the stability of the nanofluid in reservoir conditions. TGA−DTA analysis also showed that all the nanoparticles are not in the crystalline phase and partially amorphous nanoparticles exist in the sample. 3.2. Nanofluid Flooding Results. We used 5000 ppm brine, 0.01% TiO2 nanofluid, and 0.05% TiO2 nanofluid for 3
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To investigate the concentration of deposited nanoparticles in one gram of the core, ICP results on different cross sections of the core plug after flooding test using 0.05% TiO2 nanofluid were measured (Figure 8). At the entrance side, the amount of
Figure 6. System pressure versus pore volume injection.
differential pressure along the core. The differential pressure decreases drastically at about 0.35 pore volume for water and nanofluid flooding, which means that the breakthrough time did not change by adding the nanoparticles. The breakthrough measured based on the pressure drop is in agreement with the calculated breakthrough from the recovery factor graph (Figure 5) and outlet water (Figure 7). These results are in agreement with viscosity measurement data, which show no significant increase in viscosity by adding nanofluid.
Figure 8. Results of ICP test on different cross sections of core plug in 0.05% nanofluid injection. The concentration of Ti is calculated for 1 g of each cross section.
Ti is 0.81 mg/g, but it decreases drastically to 0.13 mg/g in 0.1 cm distance from the entrance side. In the middle of the core plug, the Ti amount is 0.12 mg/g, and at the exit side, it equals to 0.08 mg/g. These results show that the nanoparticles can diffuse through the length of core plug and the concentration does not decrease noticeably versus length (except entrance side). Inside the core, the concentration of nanoparticles decreased smoothly versus the distance from the entrance, in agreement with suggested models. Ju et al. presented a twophase flow mathematical model considering wettability control by nanoparticles.21 They showed that the concentration of nanoparticles decreased linearly along the distance of porous media after a few pore volume nanofluid injections. The total amount of Ti in the injection of 0.05% nanofluid is about 21 mg. According to the data, which is presented in Figure 7, Ti in the entire outlet water is about 0.04 mg. On the basis of the results in Figure 8, deposited Ti in the core is estimated to be about 21 mg. These results indicate that the amount of Ti in the outlet fluid is negligible and most of the Ti is deposited onto the rock surface. Because of the importance of understanding the coverage of nanoparticles onto the rock surface, we estimated the internal surface area of the rock from an empirical equation.21 Based on core plug volume (71.8 cm3), the internal surface area of the rock was estimated to be about 100 000 cm2. If we calculate the surface area that is covered by one layer of injected nanoparticles, we find 5000 cm2 for 0.05% nanoparticle injection. This means that only 5% of the internal surface is covered by nanoparticles in this concentration (1% for 0.01% concentration). On the basis of this calculation, it seems that there are enough rock surfaces as a place for deposition of nanoparticles on it which causes the high affinity of nanoparticles for depositing on the rock surface. Alteration of the whole surface is not necessary for EOR, and local surface alteration in some important sites may detach the oil. Zhang et al. reported that the adsorption capacities were typically much less than one layer coverage, which is in agreement with our results.18 They reported that adsorption capacities were not an intrinsic property of the porous medium nor of the nano-
Figure 7. Amount of recovered water (blue rhomb) and TiO2 amount (red square) in outlet fluid in different pore volume injections.
3.3. Ti Mass Balance. The material balance of injected nanofluid was conducted using ICP experiments. First, we checked water-soluble material from the rock by using distilled water and pure NaCl (from Merck) for flooding tests. The ICP results of the outlet fluid showed the amount of Ca, Mg, and K to be 13, 1, 1.6 ppm, respectively. There is no Ti dissolved from the core, and the amounts of other cations are too low to change the stability of nanoparticles. A water flooding experiment using a 0.05% concentration of TiO2 nanoparticles (equal to 300 mg/L of Ti) was carried out, and the results of ICP on different outlet fluid injections are presented in Figure 7. ICP results show that the amounts of exited nanoparticles are less than 2.5 mg/L of Ti, which means 0.005 of injected nanoparticles exited from the core, while more than 99% are trapped. 4
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particle; instead, they were influenced by operating conditions, i.e., injection concentration and flow rate. By increasing the flow rate, the possibility of nanoparticle adsorption reduces and transport of nanoparticles inside the core is more possible, which decrease oil recovery.18,22 3.4. Mechanism Investigation of Nanofluid in EOR. There are three main mechanisms for EOR by adding nanoparticles to the injected fluid: increasing the viscosity, decreasing the interfacial tension between the oil and injected fluid, and changing the wettability of the rock surface from oilwet to water-wet. To check the mechanism of recovery factor improvement, first, the viscosity of injected nanofluid was measured. Viscosity measurements in different rpm showed that the nanofluid with a concentration up to 2% is Newtonian and the dynamic viscosity of the fluid increased from 1.24 to 1.70 cP for a 1% concentration of TiO2 nanoparticles. Therefore, the viscosity of injected nanofluid in a low concentration of TiO2 nanoparticles does not change significantly and cannot explain the change in EOR. Second, IFT measurements for brine and nanofluid with different concentrations indicate that IFT decreases from 23 mN/m for brine to 18 mN/m for 1% nanoparticles concentration. This indicates that adding nanoparticles decreases the interfacial tension, but the amount is not enough to cover the measured enhanced oil recovery factor in low concentration flooding experiments. As IFT does not change significantly by using nanoparticles, the combination of surfactant and nanoparticles or using modified nanoparticles with hydrophobic and hydrophilic heads may enhance oil sweeping by changing the rock surface wettability and decreasing interfacial tension. Contact angle measurements of oil droplets in brine medium and low concentration nanofluid showed that addition of TiO2 nanoparticles increases the contact angle from 53° to 99° after a short time (Figure 9). This quick change indicates the significant role of nanoparticles in spreading of brine beneath the oil droplet. SEM images from the entrance side of the core plug after the flooding test with 0.01% TiO2 nanoparticles confirm the coating of the rock surface with nanoparticles (Figure 10a−c). Anyhow, it should be emphasized that, at the entrance side, the amount of deposited TiO2 nanoparticles is 1 order of magnitude higher than the other parts of the core plug. Diffusion through porous media may not be affected by less than one layer deposition of nanoparticles in low concentration of nanofluids, but in high concentration of nanofluid, it is influenced significantly due to overdeposition of nanoparticles, especially at the entrance side.11 These results clearly indicate that the main mechanism occurs between the oil droplet and the rock surface induced by nanoparticles. Deposition of these hydrophilic nanoparticles onto the rock surface can alter wettability, but at first, the nanofluid should spread beneath the oil droplet. Therefore, first, we need a mechanism for explaining the dynamic process of nanofluid spreading between the rock surface and the oil. After this stage, deposition of nanoparticles promotes changing the interface of solid/brine to partially water-wet due to the hydroxyl groups on the surface of TiO2 nanoparticles, and detaching of the oil droplet occurs. Wasan et al. observed that nanoparticles formed ordered structures in the three-phase contact line of the oil droplet on the solid surface, which further facilitates the spreading of the nanofluid film and the efficient removal of the oil droplet from the solid surface.23−26 They showed that complete wetting and
Figure 9. Contact angle measurement for aqueous phase on the rock surface at room temperature after a short time for (a) 5000 ppm brine and (b) TiO2 nanoparticles in 0.01% concentration.
spontaneous spreading of the nanofluid as a film on a solid surface became possible by manipulating the nanofluid concentration, nanoparticle size, and interfacial tension.27 This dynamic process was driven by the structural disjoining pressure gradient induced by nanoparticles. Recently, they employed the structural disjoining pressure mechanism to the crude oil displacement from the rock samples.28 Dynamic wetting and dewetting of nanofluid droplets on solid substrates were studied by Sefiane et al.29 The contact line velocity was found to increase with concentrations up to 1 wt %. In addition to the structural disjoining pressure, the friction reduction due to nanoparticle adsorption on the solid surface can be another reason for the observed enhancement in the spreading of nanofluids.18 Wang et al. employed molecular dynamics (MD) simulations to study the dynamic process of oil droplet detachment from a solid substrate immersed in aqueous suspensions containing charged nanoparticles.30 They observed a significant enhancement in the oil removal efficiency using nanofluids with charged nanoparticles. Moreover, when the charge on each particle exceeds a threshold value, the oil droplet could detach from the solid surface spontaneously and completely. Their MD results also reveal that the dynamic detachment of the oil droplets is sensitive to the charge quantity and the surface wettability of each particle. The dynamic description of an oil droplet detaching from the rock surface requires a repulsive disjoining pressure induced by nanoparticles at the contact line of oil/water/rock. To our 5
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Figure 11. Schematics of the presented model for the effect of nanoparticles in separating oil layer from the rock surface: (a) initial stage, (b) spreading of nanofluid stage, and (c) deposition and sweeping oil stage.
surface and change the rock surface to partially water-wet. In this stage, the oil droplet is detached easily (Figure 11c). To describe the behavior of nanoparticles in EOR, first, we should clarify transport and deposition of nanoparticles in core porous media to obtain the amount of nanoparticles (deposited onto rock surface and remained in nanofluid) in a specific place and time. On the basis of these data, we can obtain contact angle and gradient pressure of nanoparticles, which could be used to predict detaching oil droplet from the rock surface. For a comprehensive model, some other parameters should be concerned. The composition of oil (i.e., asphaltene and resin content) is an important parameter due to their effect in changing the wettability of the rock surface and their adsorption onto the surface of nanoparticles.31 The catalytic effect of nanoparticles on changing the characteristic of the produced oil should be checked.32,33 In addition to TiO2, the remaining oil distribution in the core can provide clues for better understanding of the flooding. This study is the first step for the mentioned approach, and further work is under study.
Figure 10. SEM images of core plug after flooding with 0.01% nanoparticles: (a) 10 μm scale, (b) 200 nm scale, and (c) 100 nm scale.
knowledge, structural disjoining pressure gradient is the only presented model of EOR application of nanoparticles. On the basis of the suggested model by Wasan et al., 27 TiO2 nanoparticles accumulate in the three-phase contact region of oil, nanofluid, and rock surface. The presence of TiO2 nanoparticles in this wedge should be noticeable even in low nanofluid concentration (Figure 11a). The pressure gradient of these nanoparticles moves the interface of oil−water, and the nanofluid spreads beneath the oil drop (Figure 11b). Furthermore, after a nanofluid layer appears between the oil and the rock surface, TiO2 nanoparticles deposit onto the rock
4. CONCLUSIONS In this paper, the diffusion and the deposition of TiO2 nanoparticles in core plug porous media and the mechanism of increasing oil recovery in low concentration of nanoparticles were studied. TiO2 nanoparticles in low concentration (0.01% and 0.05%) were shown to enhance heavy oil recovery in flooding experiments on a laboratory scale. We analyzed the Ti amounts in the effluent and different cross sections of the core plugs using ICP tests for mass balance of Ti. ICP results show 6
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(8) Karimi, A.; Fakhroueian, Z.; Bahramian, A.; Khiabani, N. P.; Darabad, J. B.; Azin, R.; Arya, S. Wettability alteration in carbonates using zirconium oxide nanofluids: EOR implications. Energy Fuels 2012, 26, 1028−1036. (9) Hashem, R.; Nassar, N. N.; Alma, P. P. Enhanced heavy oil recovery by in situ prepared ultra dispersed multimetallic nanoparticles: A study of hot fluid flooding for athabasca bitumen recovery. Energy Fuels 2013, 27, 2194−2201. (10) Giraldo, J.; Benjumea, P.; Lopera, S.; Cortés, F. B.; Ruiz, M. A. Wettability alteration of sandstone cores by alumina-based nanofluids. Energy Fuels 2013, 27, 3659−3665. (11) Ehtesabi, H.; Ahadian, M. M.; Taghikhani, V.; Ghazanfari, M. H. Enhanced heavy oil recovery in sandstone cores using TiO2 nanofluid. Energy Fuels 2014, 28, 423−430. (12) Hendraningrat, L.; Torsæter, O. Unlocking the Potential of Metal Oxides Nanoparticles to Enhance the Oil Recovery. In Proceeding of the Offshore Technology Conference Asia; Kuala Lumpur, Malaysia, March 25−28, 2014; DOI: 10.2118/24696-MS. (13) Yu, J.; An, C.; Mo, D.; Liu, N.; Lee, R. Study of Adsorption and Transportation Behavior of Nanoparticles in Three Different Porous Media. In Proceedings of the SPE Improved Oil Recovery Symposium; Tulsa, Oklahama, April 14−18, 2012; DOI: 10.2118/153337-MS. (14) Yu, J.; Berlin, J. M.; Lu, W.; Zhang, L.; Kan, A. T.; Zhang, P.; Walsh, E. E.; Work, S. N.; Chen, W.; Tour, J. M.; Wong, M. S.; Tomson, M. B. Transport Study of Nanoparticles for Oilfield Application. In Proceedings of the SPE International Conference On Oilfield Scale; Aberdeen, United Kingdom, May 26−27, 2010; DOI: 10.2118/131158-MS. (15) Caldelas, F.; Murphy, M. J.; Huh, C.; Bryant, S. L. Factors Governing Distance of Nanoparticle Propagation in Porous Media. In Proceedings of the SPE Production and Operations Symposium; Oklahoma City, Oklahoma, March 27−29, 2011; DOI: 10.2118/ 142305-MS. (16) Yu, H.; Kotsmar, C.; Yoon, K. Y.; Ingram, D. R.; Johnston, K. P.; Bryant, S. L.; Huh, C. Transport and Retention of Aqueous Dispersions of Paramagnetic Nanoparticles in Reservoir Rocks. In Proceedings of the SPE Improved Oil Recovery Symposium; Tulsa, Oklahama, April 24-28, 2010; DOI: 10.2118/129887-MS. (17) Alaskar, M.; Ames, M.; Connor, S.; Liu, C.; Cui, Y.; Li, K.; Horne, R. Nanoparticle and Microparticle Flow in Porous and Fractured Media - An Experimental Study. In Proceedings of the SPE Annual Technical Conference and Exhibition; Denver, Colorado, Oct 30−Nov 2, 2011; DOI: 10.2118/146752-MS. (18) Zhang, T.; Murphy, M.; Yu, H.; Bagaria, H. G.; Yoon, K. Y.; Nielson, B. M.; Bielawski, C. W.; Johnston, K. P.; Huh, C.; Bryant, S. L. Investigation of Nanoparticle Adsorption during Transport in Porous Media. In SPE Annual Technical Conference and Exibition; New Orleans, Louisiana, Sept 30−Oct 2, 2013; DOI: 10.2118/166346-MS. (19) Hendraningrat, L.; Torsæter, O. Metal oxide-based nanoparticles: Revealing their potential to enhance oil recovery in different wettability systems. Appl. Nanosci. 2014, DOI: 10.1007/s13204-0140305-6. (20) Hosseini, Z.; Taghavinia, N.; Sharifi, N.; Chavoshi, M.; Rahman, M. Fabrication of high conductivity TiO2/Ag fibrous electrode by the electrophoretic deposition method. J. Phys. Chem. C 2008, 112, 18686−18689. (21) Ju, B.; Fan, T.; Li, Z. Improving water injectivity and enhancing oil recovery by wettability control using nanopowders. J. Petrol. Sci. Eng. 2012, 86−87, 206−216. (22) Hendraningrat, L.; Li, S.; Torsæter, O. Effect of Some Parameters Influencing Enhanced Oil Recovery Process Using Silica Nanoparticles: An Experimental Investigation. In Proceedings of the SPE Reservoir Characterisation and Simulation Conference and Exhibition; Abu Dhabi, United Arab Emirates, Sept 16−18, 2013; DOI: 10.2118/165955-MS. (23) K. Kondiparty, K.; Nikolov, A. D.; Wasan, D.; Liu, K. Dynamic spreading of nanofluids on solids. Part I: Experimental. Langmuir 2012, 28, 14618−14623.
that the amount of exited nanoparticles is about 0.5 mg/L, which means that less than 1% of injected nanoparticles exited from the core, while the others are trapped. At the entrance side, the amount of Ti is too high, but it decreases drastically, and then it reduces linearly versus the distance from the entrance side. The calculated total amount of deposited Ti is equal to the difference of the outlet from the injected. The estimated coverage of nanoparticles on the rock surface is on the order of 1%, which is in agreement with the other reports. We performed the viscosity, IFT, and contact angle measurements to find the main mechanism in increasing the oil sweeping efficiency. The results showed that TiO2 nanoparticles do not change significantly the viscosity and the interfacial tension. On the basis of the contact angle tests, the wettability of the rock surface changed from oil-wet to waterwet due to deposition of nanoparticles. The structural disjoining pressure gradient may explain the effect of nanoparticles in wettability changing in low concentration. These results indicate the importance of studying diffusion, adsorption, and deposition of nanoparticles in different parts of the core plug. More investigation can suggest an accurate model of the nanofluid flooding mechanism. Based on that model, the modification of nanoparticles for each specific reservoir has a great potential for improving EOR methods.
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AUTHOR INFORMATION
Corresponding Author
*E-mail:
[email protected] (M.M.A.). Notes
The authors declare no competing financial interest.
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ACKNOWLEDGMENTS The authors gratefully acknowledge Prof. S. Ayattolahi for preparing IFT and contact angle measurements and Mr. M. S. Moosapoor for helping in IFT experiments.
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REFERENCES
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dx.doi.org/10.1021/ef5015605 | Energy Fuels 2015, 29, 1−8
