Review on application of nanoparticles for EOR purposes: A critical review of the opportunities and challenges

Chinese Journal of Chemical Engineering 27 (2019) 237–246

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Chinese Journal of Chemical Engineering journal homepage: www.elsevier.com/locate/CJChE

Review

Review on application of nanoparticles for EOR purposes: A critical review of the opportunities and challenges Yousef Kazemzadeh 1, Sanaz Shojaei 2, Masoud Riazi 2,3,⁎, Mohammad Sharifi 1 1 2 3

Department of Petroleum Engineering, Amirkabir University of Technology, Tehran Polytechnic, Tehran, Iran Enhanced Oil Recovery (EOR) Research Centre, IOR/EOR Research Institute, Shiraz University, Shiraz, Iran Petroleum Engineering Department, School of Chemical and Petroleum Eng., Shiraz University, Shiraz, Iran

a r t i c l e

i n f o

Article history: Received 7 April 2018 Received in revised form 26 May 2018 Accepted 28 May 2018 Available online 21 June 2018 Keywords: Enhance oil recovery Nanofluid injection Nanoparticle Interfacial tension Wettability alteration Pore blockage

a b s t r a c t Nanoparticles have already gained attentions for their countless potential applications in enhanced oil recovery. Nano-sized particles would help to recover trapped oil by several mechanisms including interfacial tension reduction, impulsive emulsion formation and wettability alteration of porous media. The presence of dispersed nanoparticles in injected fluids would enhance the recovery process through their movement towards oil– water interface. This would cause the interfacial tension to be reduced. In this research, the effects of different types of nanoparticles and different nanoparticle concentrations on EOR processes were investigated. Different flooding experiments were investigated to reveal enhancing oil recovery mechanisms. The results showed that nanoparticles have the ability to reduce the IFT as well as contact angle, making the solid surface to more water wet. As nanoparticle concentration increases more trapped oil was produced mainly due to wettability alteration to water wet and IFT reduction. However, pore blockage was also observed due to adsorption of nanoparticles, a phenomenon which caused the injection pressure to increase. Nonetheless, such higher injection pressure could displace some trapped oil in the small pore channels out of the model. The investigated results gave a clear indication that the EOR potential of nanoparticle fluid is significant. © 2018 The Chemical Industry and Engineering Society of China, and Chemical Industry Press. All rights reserved.

1. Introduction

wettability alteration [31–35]. Nanoparticles possess unique properties which can be used to obtain desirable features. These properties are high specific area, special chemical reactivity and having active surfaces [36–40]. It is proved that nanoparticles can significantly increase oil production by means of:

In-situ oil production and recovery with primary and secondary methods have resulted in weak and unstable conditions, hence, efficient technologies such as nanotechnology for enhanced oil recovery (EOR) of oil reservoirs have recently attracted much attentions [1–7]. On average, about one-third of the initial in-situ oil can be produced by primary and secondary methods. The remaining part of oil is trapped in a reservoir rock and left behind due to surface and interface tensions [8–14]. This trapped oil can be pulled out by reducing the capillary forces which prevent oil movement through small pores of the reservoir [15–19]. Nanotechnology proposes a unique approach in controlling the oil recovery process [20–23]. The nano factor can enhance oil recovery by improving the geomechanism of reservoir which is obtained by improvement in surface tension and the spontaneous modification of oil reservoirs [24–30]. The capillary force is the required force for compressing small droplets of hydrocarbons in the pore throat of reservoirs which is reduced by the decline in water–oil interface tension and

• • • • • • • • • •

⁎ Corresponding author at: Enhanced Oil Recovery (EOR) Research Centre, IOR/EOR Research Institute, Shiraz University, Shiraz, Iran. E-mail address: [email protected] (M. Riazi).

One of the challenges in nanoflooding is stability of nanofluid. Stability of nanoparticles in different fluids is determined by integrating the attraction and repulsion forces of nanoparticle surfaces. If the repulsion

Improving quality of the injecting fluid Viscosity alteration of the injecting fluid Density alteration of the injecting fluid Diminishing the surface tension Improving the emulsion formation Improving the conductivity and specific heat Improving the interactions between rock and oil Wettability alteration Altering the heat transfer coefficient Diminishing the formation damage by reducing released particles on pore surfaces [41–49].

2. Stability of Nanofluids

https://doi.org/10.1016/j.cjche.2018.05.022 1004-9541/© 2018 The Chemical Industry and Engineering Society of China, and Chemical Industry Press. All rights reserved.

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force becomes greater, the suspension gets stable and there will be no nanoparticle agglomeration [50–52]. • Zeta potential and charge density are two parameters that can be manipulated to form a stable suspension of nanoparticles. That is by an increase in zeta potential regardless of its sign (i.e. its absolute value), the stability and suspension of nanoparticles in fluid increase due to an increase in electrostatic repulsion force between the particles. Increasing zeta potential, however, intensifies the ionic power of the solution. The surface charge density of particles increases and results in higher attraction forces between particles and existing ions. This will diminish or eliminate stability of nanoparticles. The stability is therefore provided through the manipulation of the zeta potential and particle charge density. In fact, zeta potential is the representation for salinity, alkalinity, ion type and its concentration, which can be adjusted to form or improve stability in nanoparticles [53]. One of the ways to improve zeta potential and charge density parameters is pH alteration and adjustment. The surface charge load of the existing particles allows them to be stable in acidic, basic or neutral systems. If the particles are negatively charged (e.g. silica particle), stability increases by reducing solution pH. This is due to the electrostatic adsorption of hydronium ions towards silica particles which repulses these particles [53]. The effects of salinity, temperature and formation lithology can be summarized as follows: o Salinity of the nanoparticle containing fluid is one of the important instability factors for different fluids in oil reservoirs. Oppositely charged particles have negative impacts on stability of nanoparticles in the carrier fluid [54]. o Temperature is another important factor in nanofluid stability. In fact, a direct relation between salinity and temperature of the carrier fluid existed with reactivity and agglomeration rate of the nanoparticles. Thermal stability is a parameter which depends on the fluid salinity and formation lithology [55]. o Formation lithology also adds some complications to nanoparticle stability. Similar to the presence of different ions in the formation water, nanoparticle agglomeration and their attraction towards rock reservoir are highly plausible if the reservoir rock is oppositely charged towards nanoparticles [56].

3. Oil Displacement Mechanisms by Nanofluids Generally, three different mechanisms have been proposed for nanofluids. 3.1. Disjoining pressure This pressure is the one which in fact resists the adhesion force of fluids towards the solid surface to separate the fluid. This actually is the pressure difference between the thin layer of fluid and the bulk of fluid. A wedge-like film is formed by nanoparticles at the interface of discontinuous fluid through this mechanism. Such mechanisms are formed due to energies including Brownian motion and electrostatic repulsion force between nanoparticles. Greater repulsion forces exist with smaller nanoparticles [59]. Moreover, this force is intensified by increasing nanoparticle concentration. Schematic view of this mechanism is illustrated in Fig. 1. Such an arrangement for nanoparticles exerts a greater pressure at the interface of two fluids. The greater forces will be at the interface with the increased number of particles in fluid. If such energy is applied at the interface, displacement occurs to reach the equilibrium. Like other colloidal systems, magnitude of disjoining pressure is affected by parameters including particle size, temperature, and salinity of carrier fluid and surface properties of the present phases [60]. The form of the meniscus height, in the presence and the absence of nanoparticles, is shown in Fig. 2. 3.2. Density difference In the ultra-small throats of pores, nanoparticles agglomerate at the entrance of throats due to the density difference between water and nanoparticles. The agglomeration allows the injecting fluid to flow towards adjacent pores and increases their pressure. This leads the oil in adjacent pores to move and be produced. Pressure is reduced by the displacement of the oil and results in gradual restoration of pore blockages. The nanoparticles can be displaced by the carrier fluid once more under this circumstance [59]. 3.3. Wettability alteration and interface tension

• Surface coating of nanoparticles by different functional groups to improve their surface properties is another method for enhancing nanofluid stability. Surface coating of nanoparticles not only improves the zeta potential but also can enhance stability in high-saline systems. For instance, surface of the silica can be altered by Ceylon. These functional groups thus can be used to stabilize nanofluids in high temperature and salinities [57]. By the movement of nanofluids in porous media, various mechanisms contribute in reducing the nanoparticle concentration in nanofluids. The most important factors involved in such phenomenon are the adhesion of nanoparticles to rock surfaces and blockage of different throats of the rock. The throats are blocked by two ways in rocks: o The solid particles cannot pass through pores if the pore diameters are smaller than their size. According to which nanoparticle diameter is usually smaller than pore diameter, occurrence of such phenomenon is of scarcity. o Rock pores can be blocked under mechanisms of agglomeration and bridge if the diameter of pores is bigger than nanoparticles. While the nanoparticle containing water moves through the pore throats of rocks, the smaller water droplets pass with higher speed and comfort and hence, nanoparticles accumulate at throats. Diameter of the pores is reduced and eventually blocked due to the placement of nanoparticles on surfaces. Agglomeration generally depends on nanoparticle concentration, flow rate and the diameter ratio of droplets to pores [58].

Flooding with nanofluids improves wettability and interface tension properties of the system. Furthermore, nanoparticles affect the density of the injecting fluid and the reservoir fluid. Silicone nanofluids are again usually used to obtain such mechanism. As it is mentioned earlier, these nanoparticles can possess different wettability. Alcohol is a proper solvent for neutral and hydrophobic nanoparticles while hydrophilic nanoparticles are properly suspended in aqueous environments. These hydrophilic nanoparticles are mainly used for enhanced oil recovery of oil reservoirs which are mostly oil-wet. The main production mechanism by using these nanoparticles is to alter wettability from oil-wet to neutral or water-wet and vice versa. Wettability alteration is accomplished by adsorbing nanoparticles with proper wettability on the rock surface [61–63]. 4. Factors Influencing the Process of Flooding with Nanoparticles Flooding process with nanoparticles is affected by various factors which requires a sensitivity analysis to effectively determine these factors. These factors can be mentioned as follows. 4.1. Property of nanoparticles 4.1.1. Nanoparticle concentration Nanoparticle concentration has a bilateral influence on nanofluid injection. From one side, an increase in nanoparticle concentration escalates the disjoining pressure and Brownian motion due to the

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TiO2 NPs Fig. 1. Disjoining pressure gradient at oil–nanofluid interface.

influence of increased repulsion forces, and nanofluid efficiency for altering wettability is consequently enhanced. On the other hand, an increase in the concentration results in a decline in porosity and permeability of the reservoir rock due to the increased rate of nanoparticle deposition on the rock surfaces. 4.1.2. Nanoparticle size Disjoining pressure is also affected by the size of nanoparticles and their corresponding charge density. As it is mentioned earlier, the smaller the particle sizes are, the greater is the repulsion force and thus the higher is the disjoining pressure that exist between them. Particles however agglomerate with higher rates if the particles become ultra-small. 4.1.3. Nanoparticle wettability The arrangement of nanoparticles at the interface of oil and water is defined by their wettability. Wettability of the reservoir rock also alters by adsorbing these particles on rock surfaces. Wettability alteration in the surface of reservoir rock changes the resistances against fluid flow and thus alters the relative permeability of oil and water in the reservoir.

4.2. Nanofluid system 4.2.1. Salinity Generally, stability of nanoparticles decreases by increasing the salinity of the system. In fact, increase in salinity reduces the zeta potential and therefore results in agglomeration of colloidal particles. However, increasing the salinity by adding different ions doesn't prevent nanoparticles from moving, it significantly increases the deposition of nanoparticles on rock surfaces. 4.2.2. Temperature Reservoir temperature is much higher than the surface temperature. Each nanoparticle thus has to maintain its efficiency in the reservoir temperature to be applicable for injection in oil fields. By increasing the temperature, particles agglomerate due to the decline in zeta potential. In fact, stability of nanoparticles is diminished by increasing the temperature. Nevertheless, according to the results, performance of the nanofluids in enhanced oil recovery has improved in higher temperatures. This can be due to the decreased surface tension in higher temperatures as the result of decline in interactions of liquid molecules. 4.2.3. Injection rate Small water molecules move faster than suspended nanoparticles by increasing the injection speed and results in agglomeration of nanoparticles which blocks pores and reduces oil production. By increasing the injection rate, nanofluid efficiency is therefore diminished due to particle agglomeration and pore blockages and its resulting permeability decline.

With Nanoparticle

Without Nanoparticle

Fig. 2. Effect of disjoining pressure on form of the meniscus height in the wedge region [60].

4.3. Reservoir rock 4.3.1. Size of rock particles In fact, specific area of the porous media is related to the size of the reservoir rock. The specific area of the reservoir rock is decreased by increasing the size of rock particles in which nanoparticle deposition on the rock surfaces also diminishes.

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4.3.2. Clay content The adsorption of nanoparticles is escalated by increasing the clay content. This is primarily due to which available specific area for nanoparticles is enhanced and more spots are available for nanoparticle to be deposited on.

5. Literature Review on Using Nanoparticles and Its Efficiency in Enhanced Oil Recovery 5.1. Influence of nanoparticles on wettability alteration Zhang et al. have compared the performance of nanoparticles made by the Illinois technology institute and the silicone nanoparticles, and proved that nanoparticles which are made by this institute have more effectively performed in increasing the production of the trapped oil and wettability alteration [64]. In another study by Ju and Fan [65] the wettability alteration of oil-wet sandstones has been evaluated by injecting hydrophilic nanoparticles of silica. Results including TEM images have confirmed the wettability alteration and the adsorption of nanoparticles on the rock surfaces [65]. Onyekonwu and Ogolo [66] have studied the ability of poly-silicone nanoparticles in wettability alteration and enhanced oil recovery. Solvents including water and ethanol have been used to suspend the nanoparticles. It was found that in water-wet cores, oil recovery in 3000 ppm concentration can be improved by using neutral and hydrophobic nanoparticles due to mechanisms of wettability alteration and interface tension reduction, while, the oil recovery was diminished by using hydrophilic nanoparticles simply due to enhanced core water-wet property [66]. Karimi et al. [67] also have utilized nanoparticles with zirconium oxide base to investigate the influences on enhanced oil recovery. They have concluded that these nanoparticles are capable of altering carbonate rock wettability from highly oil-wet to highly water-wet. Considerable amount of oil was produced through spontaneous experiments by using these nanofluids [67]. In a study by Giraldo et al. [68], the influence of nanofluids containing aluminum-oxide-base nanoparticles has been evaluated. They have revealed that these nanoparticles can considerably alter the wettability of highly oil-wet sandstones to water-wet. Efficiency of surfactants as wettability alternation additives also has been improved [68]. By conducting contact angle experiments in high temperature and pressure condition, Cao et al. [69] have concluded that the ionic liquids and the utilized nanofluids are efficient and stable for wettability alteration at high temperatures. Fig. 3 indicates the percentage of papers on wettability alteration compared to the other chemical EOR processes published between 2001 and 2017.

5.2. Influence of nanoparticles on reducing interface tension By using iron nanoparticles, Suleimanov et al. [70] have evaluated the application of the nanofluids in enhanced oil recovery. They have reported that systems containing both nanoparticles and surfactants can enhance oil recovery up to 35%. This is while in systems containing only surfactants, oil recovery was reported to be 17%. They have explained the increased oil production by relating it to the reduced interface tension of the system containing nanoparticles [70]. Roustaei et al. [71] have studied the efficiency of poly-silicone nanoparticles by measuring the contact angle and interface tension parameters. They have detected a decline in the interface of oil and water (from about 26 to 2 mN·m−1) and an increase in the enhanced oil recovery by using the nanoparticles [71]. Efficiency of the suspended solutions containing hydrophilic polysilicone nanoparticles for enhanced oil recovery was investigated by Hendraningrat et al. [72]. They have reported a decline in the interface tension of oil and water at the presence of nanoparticles in which solid surfaces get more water-wet. They have eventually observed a 5percent improvement in the oil recovery at the presence of nanoparticles [72]. Moghadam and Azizian have studied the influence of zinc oxide nanoparticles on the behavior of anionic surfactants at the interface of the two fluids. They have confirmed a significant decline in the interface tension of the surfactant and oil at the presence of nanoparticles [73]. Fig. 4 illustrates the percentage of papers on interfacial tension compared to the other chemical EOR processes published between 2001 and 2017. nanofluid applicationin IFT reduction/%

240

20 18 16 14 12 10 8 6 4 2 0

Years Fig. 4. The percentage of papers on interfacial tension compared to the other chemical EOR processes published between 2001 and 2017.

nanofluid application in wettability alteration/%

5.3. Influence of nanoparticles on emulsion stability 25

20

15

10

5

0

Years Fig. 3. The percentage of papers published on wettability alteration by nanoparticles compared to the other chemical EOR processes.

Asumadu-Mensah et al. [74] have studied the impacts of nanoparticles including aluminum, copper and their oxides on emulsion stability. It was found that oil–water separation will be easier by using hydrophilic nanoparticles and the emulsion stability will decrease [74]. In another study, Al Otaibi et al. [75] have revealed that stable emulsion can be formed by carbon dioxide, nanoparticle and water. Concentration of the nanoparticles and water volume fraction were reported as the most affecting parameters on the emulsion stability [75]. Influence of nanoparticles on emulsion stability under the reservoir condition was also investigated by Binks and Whitby [76]. They have concluded that the surface charge is an essential parameter for stability and pH must be adjusted and controlled to reach stability [76]. Pei et al. [77] have studied the stability of emulsion by adding nanoparticles in micromodel experiments. The results ascertained that adding nanoparticles can increase the thickness of the emulsion layer and improve the mobility. The heavy oil also gets emulsion by injecting the emulsions which were stabilized with nanoparticles and surfactants.

nanofluid application in emulsion stabilty/%

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stabilized with nanoparticles and surfactants. They have concluded by performing core flooding experiments that up to 82% of the in-situ oil can be produced by this method [79]. Fig. 5 shows the percentage of papers on formation and stability of emulsions compared to the other chemical EOR processes published between 2001 and 2017.

18 16 14 12 10

5.4. Influence of nanoparticles on foam stability

8 6 4 2 0

Years Fig. 5. The percentage of papers on formation and stability of emulsions compared to the other chemical EOR processes published between 2001 and 2017.

nanofluid application in foam stabilty/%

241

25

20

15

10

5

0

Years Fig. 6. The percentage of papers on formation and stability of foam compared to the other chemical EOR processes published between 2001 and 2017.

They have claimed that these stabilized emulsions can produce 40% of the in-situ oil by means of EOR processes [77]. In a recent effort by Kim and Krishnamoorti [78], the formed emulsion of oil in saltwater was measured and evaluated by using silica nanoparticles and four types of surfactants (cationic, anionic, ion-dipole and nonionic). It was found that these emulsions are highly efficient as well as low cost [78]. Griffith et al. [79] have studied the influence of mineral oil production through the injection of pentane emulsions in water which was

Espinoza et al. [80] have studied the effects of nanoparticles on controlling mobility of superheated carbon-dioxide foams. Based on the results, nanoparticles with 0.05 wt.%. can create stable foams. They reported that salinity has great impacts on the foam stability. They also succeeded to create foams in high temperatures such as 95 °C by using nanoparticles [80]. Aminzadeh-goharrizi et al. [81] have studied the stability of carbondioxide foams in water under the effects of surfaced modified nanoparticles. These nanoparticles were claimed to alter the movement pattern and the distribution of carbon-dioxide in environment, also, they have showed the capabilities to reduce carbon-dioxide mobility [81]. Mo et al. [82] have also conducted experiments to determine the factors affecting foam stability at the presence of nanoparticles. They have measured the optimum nanoparticle concentration under the experimental conditions to be in the range of 2000 to 3500 μl·L−1 [82]. Performance of the nanoparticle-stabilized foams in enhanced oil recovery was investigated by Yu et al. [83]. They have claimed that such foams can enhance oil recovery in cores with low and high permeability [83]. Performance of the modified nanoparticles in stabilizing carbon-dioxide foams was also evaluated by Zhang et al. [84]. They have confirmed the high effectiveness of the surface modified nanoparticles of silica in forming stable emulsions of oil in water and carbon-dioxide foams in water. Foams which were produced in this way can be stable in 95 °C and up to 10% salinity [84]. Fig. 6 shows the percentage of papers on formation and stability of foam compared to the other chemical EOR processes published between 2001 and 2017. 5.5. Influence of nanoparticles on enhanced oil recovery As noted above, nanofluids with different mechanisms contribute to the enhanced oil recovery. Therefore, various aspects of the application of nanoparticles have been discussed in previous studies. The present study addresses changes in wettability, reduction of interfacial tension, emulsion formation, and foam stability and formation. Fig. 7 shows the percentage of nanofluid application in each of the mechanisms studied in different years.

Percentage of nanofluid application

30

25

20

15

10

5

0 2000

2002

2004

2006

2008

2010

2012

2014

2016

2018

Years

Wettability Alteration

IFT Reduction

Emulsions Stability

Foam Stability

Fig. 7. The percentage of nanofluid application in each of EOR mechanisms compared with other techniques.

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As it is shown in Fig. 7, nanofluid studies have paid more focus on wettability than other mechanisms. Fig. 7 shows that the application of nanofluids for enhanced oil recovery gains increasing attention compared to other methods.

Researchers have recently succeeded to create water–oil emulsions with metal and metal-oxide nanoparticles and improve oil properties by in-situ utilization of the emulsions. These emulsions contain nanoparticles with catalytic and absorption properties which can be

Table 1 An overview of studies on the use of nanofluids in enhanced oil recovery from reservoirs Author

Method

Reservoir rock

Results

Subject

Aminzadeh Goharrizi [89]

Core flooding

Boise sandstone

Experimental measurement of sweep efficiency during multi-phase displacement in the presence of nanoparticles

Assef et al. [90]

Core flooding

Sandstone

Bagaria et al. [91]

Chemical method

Cieśliński and Krygier [92]

Contact angle

Ehtesabi et al. [93]

Core flooding

Nanoparticles can reduce the mobility of the injected CO2 as an alternative to saltwater, improving the sweep efficiency by about 20%. Increasing the Zeta potential from 3 to about 9, minimizing damages, preventing severe connections in the vicinity of the well, and improving communication between the well and virgin formation Significant increase in spatial stabilization of nanoparticles and very low absorption at silica levels even in severe API brine The contact angle of the nanofluids drops depends on the roughness of the surface, the type of substrate, the nanoparticle materials, and the concentration of the nanoparticles. The main mechanism enhancing the sweep efficiency is the change in the wettability of the rock surface from an oil-wet state to a hydrophilic state because of deposition of TiO2 nanoparticles. A significant reduction in the viscosity of heavy oil and bitumen at low concentrations CTAB and SDBS surfactants are unable to stabilize nickel nanoparticles because they are not able to create ζ potential needed to prevent van der Waals force. CTAB surfactant concentration plays an important role in the transport of particles to the water and oil interface. The particle distribution depends on the heterogeneity of the medium and the injection flow Clear improvement of the effluent water quality by flooding of the nanoparticles The use of nanoparticles can increase the clay stability and can also control the clay migration more effectively. The presence of Fe3O4 nanoparticles can contribute to reducing the asphaltene precipitation intensity. The addition of HP-b-CD monomer to the solution reduces its viscosity. Extreme temperature dependence for the SDS surface was observed with low viscosity at high temperatures. Hydrophilic nanoparticles can postpone the drinking process for more hydrophilic stones, but they do not have much impact on wettability alteration. These nano-hydrophobics can increase the hydrophobicity of neutral wettability cores and increase the wettability index of more hydrophilic cores by 10%. With the increase in temperature and decrease in size, the effective thermal conductivity increases. Nano-polymers have been used for altering wettability and improving the relative permeability and movement through the porous medium. Concentration, type, and particle size are the main parameters affecting viscosity reduction. The optimum values of these parameters are effective on heavy-oil thermal applications. The addition of nanoparticles at low concentrations increases the stability of the stabilized surfactant foam. Introducing the new concept of EOR by enhancing the macroscopic displacement as the microscopic deviation. A 20% decrease in Spr due to the presence of nanoparticles Increased oil harvest The contact angle increases with nanofluid concentrations for similar droplet size and starts to reduce after culmination. 50% of crude oil can be harvested from Berea sandstones using the IIT nanofluids. This reduces to 17% when using only saltwater solution, indicating the good performance of IIT nanofluids in an aqueous medium with high salinity For both emulsions with increasing concentrations of nanoparticles, more dispersed phase emulsions are formed, the volumetric function of the dispersed phase in the emulsion increases, and average droplet diameter decreases

Plates made of glass

Greff and Babadagli Thermal [94] Micromodel Hamedi-Shokrlu and Babadagli [95]

Huang and Clark [96]

Core flooding

Kazemzadeh et al. [97] Kjøniksen et al. [98]

IFT

Li et al. [99]

Adsorption and wettability

Mintsa et al. [100]

Thermal

ShamsiJazeyi et al. [54]

Chemical method

Shokrlu and Babadagli [101]

Thermal

Singh and Mohanty [102] Skauge et al. [58]

Core flooding

Berea sandstone

Core Flooding

Berea sandstone

Vafaei et al. [103]

Contact angle

Glass and silicon wafers

Chemical method

Zhang et al. [104]

Zhang et al. [105]

Berea sandstone

Berea sandstone

Emulsion

Controlling interactions of colloidal particles and porous media during low salinity water flooding and alkaline flooding by MgO nanoparticles Iron oxide nanoparticles grafted with sulfonated copolymers are stable in concentrated brine at elevated temperatures and weakly adsorb on silica Augmentation of the critical heat flux in water–Al2O3, water–TiO2 and water–Cu nanofluids

Enhanced heavy oil recovery using TiO2 nanoparticles: investigation of deposition during transport in core plug

Catalytic effects of nano-size metal ions in breaking asphaltene molecules during thermal recovery of heavy-oil Stabilization of nanometal catalysts and their interaction with oleic phase in porous media during enhanced oil recovery

Enhancing oil recovery with specialized nanoparticles by controlling formation-fines migration at their sources in waterflooding reservoirs Impact of Fe3O4 nanoparticles on asphaltene precipitation during CO2 injection Modified polysaccharides for use in enhanced oil recovery applications

Effect of silica nanoparticles adsorption on the wettability index of Berea sandstone

New temperature dependent thermal conductivity data for water-based nanofluids Polymer-coated nanoparticles for enhanced oil recovery

Viscosity reduction of heavy oil/bitumen using micro-and nano-metal particles during aqueous and non-aqueous thermal applications Synergy between nanoparticles and surfactants in stabilizing foams for oil recovery Nano-sized particles for EOR

Effect of nanoparticles on sessile droplet contact angle

Enhanced oil recovery (EOR) using nanoparticle dispersions: Underlying mechanism and imbibition experiments Nanoparticle-stabilized emulsions for applications in enhanced oil recovery

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Table 2 An overview of studies on flooding carbonate reservoirs using nanofluids(1mD=10-3μm2) Subject

Conclusion

Porosity/% Permeability/mD Nanoparticle Authors

Adsorption of novel nonionic surfactant and particle mixture in carbonates: enhanced oil recovery implication

With increasing concentrations of silica nanoparticles, the adsorption on the surface of carbonate rock decreases. Nanoparticle efficiency to reduce surface adsorption of surfactant nanoparticles depends on these nanoparticles. Oil recovery production factor up to 85%

12.39

1–10

SiO2

Ahmadi and Shadizadeh [106]

10–24

77–149

Haroun et al. [88]

The results for CO2 mixing conditions have shown the improved porosity and permeability and reduced asphaltene accumulation in the porous media as well as increased nanoparticle production. Nanoparticle size and their different properties, especially their surface properties are the main keys to improve production. A significant amount of oil can be produced in the core itself in the presence of nanosilicates during the drinking process. The recovery rated increased by 20% during the replacement process of water instead of gas in the presence of nanoparticles compared to the situation without nanoparticles. Surface and chemical properties of nanoparticles are important for improving the stability of the nanoparticles. Their recognition also reduces the spontaneous accumulation, increases homogeneity, and reduces reaction with the rock matrix. Small variations were found in the contact angle in the presence of modified and non-modified anionic, cationic, and non-ionic surfactants. The particle size does not have much impact on the contact angle.

8.093 16.953 15.941

2.982 7.285 6.943

Fe3O4 NiO CuO NiO

–

–

Metal oxide

Ayatollahi and Zerafat [108]

20

30

ZrO2

Karimi et al. [109]

10.33

2.839

SiO2

Moradi et al. [25]

24.6

142

Fe3O4

Kanj et al. [110]

–

–

SiO2

Metin et al. [111]

Smart nano-EOR process for Abu Dhabi carbonate reservoirs On the application of NiO nanoparticles to mitigate in situ asphaltene deposition in carbonate porous matrix Nanotechnology assisted EOR technique: new solution to old challenges Wettability alteration in carbonates using zirconium oxide nanofluids: EOR implications Application of SiO2 nano particles to improve the performance of water alternating gas EOR process

Nanofluid coreflood experiments in the ARAB-D

Adsorption of surface functionalized silica nanoparticles onto mineral surfaces and decane/water interface

dispersed in the porous structure of the reservoir and the well pipes to provide multiple applications such as removal of the asphaltene sediments through the adsorption process. Some experiments have been conducted on the influence of different parameters and the performance of nanoparticles which are briefly addressed as follows. Chen et al. [85] also have studied on reducing the viscosity of heavy oils by nanoparticles. In this approach, nanoparticles react with the heavy oil by means of steam and act as a catalyst that loosens the bonds of N, S and O with the carbon; hence, components including aromatics and saturated hydrocarbons are produced due to the variation in the heavy oil structure. It also diminishes the percentage of asphaltene and resins primarily due to the breaks in the C\\O bonds of the molecule, C\\C bonds in the adjacent hydrocarbon chains and the C\\S bonds. Accordingly, in addition to the reduction in heavy parts of the oil, light parts act as solvents and reduce the oil viscosity. Results have emphasized on 80 to 93% reduction in the heavy oil in 200 and 280 °C [85]. Nassar et al. [86] have conducted multiple experiments on the influence of nanoparticles and different parameters on the recovery of oil comprising high asphaltene content. The results are briefly mentioned as follows. Performance of the nanoparticles including oxides of nickel, cobalt and iron can be sorted as: NiO N Co3O4 N Fe3O4. Here, the performance is defined as the abilities to oxidation and absorption as well as the catalytic ability. Asphaltene is spontaneously adsorbed on the nanoparticle surfaces with an exothermic nature [86]. Ogolo et al. [87] have claimed that some nanoparticles can enhance the oil recovery which this performance is also improved at the presence of ethanol. They also introduced the mechanisms by which nanoparticles improve the recovery process as: wettability alteration of the rock, IFT reduction, reduction in the oil viscosity, reduction of mobility ratio and permeability variations [87].

Hashemi et al. [107]

Haroun et al. [88] have compared the smart injection of water and nanoparticles. They have concluded that the recovery coefficient of a reservoir which is measured to be 46% to 63% by injecting the water, can be enhanced to the range of 57% to 85% by selecting the proper nanoparticle [88].

6. Field Applications of Nanoparticles The first field experience of nanoparticle injection was performed in the Liauhe field of China in which nanoparticles were injected through the steam.4 But in the Ghawar field of Saudi Arabia, about 5 kg of A-Dot nanoparticle was mixed with 255 barrels of sea water in 2012 and injected to one of the observation wells. The injection process was continued until the nanoparticles had advanced about 20 ft (1 ft = 0.3048 m) in the reservoir. The well was subsequently closed for 3 days and the oil production was then resumed. The samples indicated that 90% of the nanoparticles had been successfully recovered.5 Table 1 summarizes studies on the application of nanoparticles in the enhanced oil recovery from reservoirs. The table shows the research methodology, the reservoir rock materials, and a part of the results. One of the common uses of nanoparticles is their use in carbonate rock reservoirs. The following table shows some of the results and application of nanoparticles in the flooding of carbonate rocks. Table 2 also shows the permeability, porosity of the rock, the type and size of the nanoparticles along with the main results. Table 3 shows some of the results and application of nanoparticles in the flooding of sandstone rocks.

4 http://oilprice.com/Energy/Crude-Oil/Chinese-Scientists-Discover-New-Method-toIncrease-Recoverable-Oil-from-Wells.html 5 https://www.aramcoexpats.com

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Table 3 An overview of studies on flooding sandstone reservoirs using nanofluids Nanoparticle type

Nanoparticle concentration/wt%

Additional recovery factor/%

Base fluids

Authors

SiO2 Al2O3 Ni2O3 MgO Fe2O3 ZnO ZrO2 SnO SiO2 SiO2 TiO2 Al2O3 TiO2 SiO2 SiO2

0.02–0.03 0.3

– 12

Water Ethanol Brine water

Ju et al. [17] Onyekonwu and Ogolo [66]

0.1–0.4 0.01–1 0.05

19.31 31 7–11

Ethanol Brine Brine

Shahrabadi et al. [112] Ehtesabi et al. [11] Hendraningrat and Torsæter [28]

1

21

Sharma et al. [113]

SiO2 NANO clay ZrO2 TiO2 MgO Al2O3 CeO2 CNT CaCO3 SiO2 TiO2

0.01–3 0.9 5

29 5.8 8–9

Surfactant Polymer Water Water Brine

1.9–2.5

4

Polymer water

Cheraghian [46]

Acknowledgment Authors would like to sincerely thank Mr. Hosein Doryani and Mr. Hossein Rezvani for their collaboration in this work.

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