Comparative Study of Using Nanoparticles for Enhanced Oil Recovery

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A Comparative Study of Using Nanoparticles for Enhanced Oil Recovery: Wettability Alteration of Carbonate Rocks Rasoul Nazari Moghaddam, Alireza Bahramian, Zahra Fakhroueian, Ali Karimi, and Sharareh Arya Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/ef5024719 • Publication Date (Web): 23 Feb 2015 Downloaded from http://pubs.acs.org on February 24, 2015

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A Comparative Study of Using Nanoparticles for Enhanced Oil Recovery: Wettability Alteration of Carbonate Rocks Rasoul Nazari Moghaddam 1,2, Alireza Bahramian*1, Zahra Fakhroieyan1, Ali Karimi1, Sharareh Arya3 1

Institute of Petroleum Engineering, School of Chemical Engineering, University of Tehran, Tehran, Iran 2

Institute of Petroleum Engineering, Heriot Watt University, Edinburgh, UK 3

NIOC-R&D, Negar St., Valiasr St., Tehran, Iran

ABSTRACT: Nanofluids have been recently proposed as new chemical agents for enhanced oil recovery from oil reservoirs. Various nanofluids have been studied in that regard and reported in the literature, verifying the capability of nanostructured materials in enhancing the oil recovery through alteration of rock wettability. In this study, the impact of different nanofluids of Zirconium dioxide (ZrO2), Calcium carbonate (CaCO3), Titanium dioxide (TiO2), Silicon dioxide (SiO2), Magnesium oxide (MgO), Aluminum oxide (Al2O3), Cerium oxide (CeO2), and Carbon nanotube (CNT) on the wettability of carbonate rocks were investigated. A series of preliminary contact angle evaluation were performed to screen the nanoparticles. The performances of the selected nanofluids were evaluated by spontaneous imbibition and core flooding experiments. Results of spontaneous imbibition tests and coreflooding experiments confirm the active role of CaCO3 and SiO2 nanoparticles for enhancing oil recovery. In addition, the effect of nanofluid injection on the rock surface wettability was examined by drainage capillary pressure measurement. It is shown that the irreducible water saturation and the entry capillary pressure were both increased after treatment by CaCO3 nanaofluid. Moreover, the structural disjoining pressure gradient is proposed to be the responsible mechanism for changing wettability. Both experiments and theoretical calculations prove that disjoining pressure of the nanoparticles layer near the contact point can be high enough to remove oil from the surface.

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1. INTRODUCTION Carbonate reservoirs contain about 60 % of oil and 40 % of gas from total oil and gas reserves in the world.1 Most carbonate reservoirs can be considered oil-wet or mixed-wet.2-4 Current available recovery techniques, e.g. water flooding, recover less than half of the original oil in place (OOIP) in non-fractured carbonates, and much less in fractured carbonate reservoirs.5 In fractured reservoirs, wettability alteration from oil wetting to water wetting can improve oil recovery.6 Rock wettability can be altered thermally,7 or chemically using surfactants, low-salinity brine,8 and selective ions.9,10 More recently, some researchers have suggested that the effectiveness of wettability modifiers can be increased by adding nanoparticles.6,11-14 Some studies have been reported on the role of nanoparticles in enhanced oil recovery (EOR). The effects of nanoparticles (or in combination with surfactants) on reducing the surface forces have been investigated in last decade.15-22 For instance, Fletcher and Davis18 outlined the potential of nanotechnology for implementation in design and execution of chemical EOR and Hendraningrat et al.19-22 reported the potential of hydrophilic nanoparticles for EOR processes. Recently, the performance of SiO2 nanoparticles for wettability alteration of reservoir rock has been investigated.12,13,23 Ju et al.11 reported that nanometer range polysilicon could change the wettability of porous surfaces of sandstone, affecting the flow behavior of water and oil phase in porous body. Ju et al. 11-13 conducted experimental and theoretical studies on wettability alteration and absolute permeability change caused by adsorption of lipophobic-hydrophilic polysilicon nanoparticles (LHP) on the surface of sandstone cores. Sefiane et al.

24

investigated the effect of

nanoparticles on the fluid spreading and attributed the enhanced wetting to a pressure gradient within the nanofluid. This pressure gradient is created due to formation of a solid-like ordering in the fluid ‘wedge’ in the vicinity of the three-phase contact line. They identified two mechanisms as a potential reason for the observed enhancement in spreading of nanofluids: structural disjoining pressure and friction reduction due to nanoparticle adsorption on the solid surface. Ju and Fan

13

performed adsorption experiments and used two types of polysilicon nanoparticles. The adsorption experiments of lipophobic and hydrophilic polysilicon nanoparticles (LHPN) were conducted to examine the wettability alteration from oil wet to water wet. In addition, Onyekonwu et al.

25

studied the ability of three different polysilicon nanoparticles to improve oil recovery. They injected different blends of lipohydrophilic, hydrolipopholic and medium-wet nanoparticles. Their


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results indicated that neutrally wet polysilicon nanoparticles and hydrophobic and lipophilic polysilicon nanoparticles (dispersed in ethanol) are suitable agents for enhancing oil recovery in water wet formations. Skauge et al.

26

also injected nanoparticles with a polymer solution into

sandstone core models to improve oil displacement efficiency. However, all tests were conducted in ambient temperature. Karimi et al.

6

investigated the effect of zirconium oxide (ZrO2)-based

nanofluids on wettability alteration of a carbonate rock by contact angle measurements and free imbibition experiments. The authors concluded that the ZrO2-based nanofluids can be used as wettability modifiers for carbonate systems. Their results also indicated that a considerable amount of oil can be quickly recovered during free imbibition of the nanofluids into the core plugs. Giraldo et al.

27

also used alumina-based nanofluids as wettability modifiers. They studied the effect of

nanofluids on wettability alteration by contact angle and imbibition tests. They reported that the designed nanofluids could significantly change the wettability of the sandstone cores from strongly oil-wet to strongly water-wet. Results presented by them showed that the effectiveness of anionic surfactants could be improved by adding nanoparticles in a concentration lower or equal than 500 ppm. Despite all reported studies, there is no comparative study to investigate the performance of different nanoparticles for wettability alteration in carbonate rocks by different wettability measurement techniques. There are several methods to measure the wettability of a surface. Contact angle measurement, spontaneous imbibition and wettability indexes determination (Amott, Ammott-Hervey and USBM) from drainage capillary pressure can be categorized as quantitative methods. Furthermore, relative permeability measurement and core flooding experiments can be considered as qualitative methods. The main aim of this work is to perform a comparative study by both qualitative and quantitative methods on different nanoparticles. In this study, both qualitative and quantitative wettability determination techniques were performed to find the best candidates among different nanoparticles reported in literature which can be used in petroleum industry. Eight previously investigated nanoparticles of Zirconium dioxide (ZrO2),6 Calcium carbonate (CaCO3),28 Titanium dioxide (TiO2),29 Silicon dioxide (SiO2), 12,13,23

Magnesium oxide (MgO),28 Aluminum oxide (Al2O3),27 Cerium oxide (CeO2)30 and Carbon

nanotube (CNT)31 have been selected, examined, and screened systematically in this study. Carbonate substrates were used to measure the performance of the nanofluids by contact angle


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measurement. After preliminary evaluation by contact angel measurements, the selected nanofluids were used to study the effect of brine salinity. Then, the performances of the selected nanofluids were examined by spontaneous imbibition and core flooding experiments. Moreover, the best nanoparticle was used to treat the core and investigate the effect of wettability alteration on drainage capillary pressure curve and end point saturations.

2. MATERIALS AND METHODS 2.1.

Materials

Crude oil from a reservoir located in the northern offshore of the Persian Gulf (a member of Bahregan oil area) was provided by National Iranian Oil Company (NIOC). The oil contains a considerable amount of asphaltene (10 wt %) and a viscosity of approximately 64 cSt at 70 °C (425 cSt at ambient temperature). The oil was initially diluted with kerosene in a 50/50 v/ v ratio, and the mixture was used as an oil phase in wettability study experiments. The diluted mixture had a density of 0.861 g/cm3. Distilled water with conductivity of 0.05−0.08 μs/cm was used in all experiments. Persian Gulf brine with approximately 30000 ppm salinity and 2 centipoise viscosity was also used in this study. The n-Heptane with a purity of 99.9% was provided by Merck Company. The potential of different nanofluids for wettability alteration of oil-wet carbonate rocks was examined using outcrops from a reservoir formation nearby the Masjid-i-Sulaiman field. Xray Fluorescence (XRF) analysis of obtained outcrops was performed using X'Unique II system provided by Philips. The results showed 10% (w/w) MgO, 40% (w/w) CaO and the rest as loss on ignition (L.O.I). For contact angle experiments, sufficient amount of substrates were prepared. The substrates were polished, washed by methanol and dried in oven at the temperature of 70 oC for 24 hours. For the other experiments, five numbers of core plugs were used. Properties of the core plugs are summarized in the Table 1.

2.2.

Nanofluid Preparation

Nine different nanofluids were used in this study to compare their performance on carbonate rocks. Table 2 shows nanoparticles name and their approximate size and shape calculated from SEM images (Figure 1). Nanofluids were prepared as follow:


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CNT type 1 (174): 0.03 gr multi-walled nanotubes (MWNTs) mixed with a solution of Tween80/ Span20 in ratio of 1:1 in 40 ml paraffin. CNT type 2 (26): 0.05 gr multi-walled nanotubes (MWNTs) mixed with 10 gr of Tween80 in a solution of paraffin/heptane. TiO2 new-12: 0.05 gr TiO2 nanoparticles mixed with 10 ml LA-7EO (Lauryl alcohol 7 mole ethoxylated) in an acidic aqueous solution. CeO2 21: 0.05 gr CeO2 nanoparticles mixed with a solution of Tween80/ Span83 in a ratio of 10:1 and 6 ml OA-6EO (Oleic acid 6 mole ethoxylated) dissolved in aqueous solution. Al2O3 (12): 0.03 gr Al2O3 nanoparticles mixed with 0.24 gr SDS in 100 ml acidic aqueous solution. MgO 175: 0.05 gr MgO nanoparticles, 10 ml LA3 (Lauryl alcohol 3 mole ethoxylated) and 0.5 gr Oleic acid mixed with a solution of Tween80/ Span83 in a ratio of 10:1 in acidic aqueous solution. ZrO2 41A: 0.05 gr ZrO2 nanoparticles mixed with a solution of Tween80/ Span85 in a ratio of 1:10 in 100 ml acidic aqueous solution. The pH of solution was adjusted to the range of 2-3. SiO2 (52) : 0.30 gr SiO2 nanoparticles mixed with 60 ml solution of paraffin/heptane and combined with a mixture of 30 ml Ethylene glycol and 15 ml LA3EO ( Lauryl alcohol 3 mole ethoxylated). CaCO3 : 0.05 gr CaCO3 nanoparticles dissolved in 100 ml solution of water and alcohol and mixed with Tallow Amine Ethoxylate-15 mole ethoxylated and Sodium dodecyl sulphate. CNT particles were provided by Neutrino Company, Tehran, and used as received. The rest of investigated nanoparticles were synthesized in the laboratory, based on the reported methods in the literature.32-38 It should be noted that, all prepared nanofluids are homogenized using ultrasonic methods to obtain clear and stable solutions. The prepared nanofluids and their base-fluids diluted in distilled water at concentration of 5 wt %. The obtained fluids were then used for investigation of wettability alteration by contact angle measurements, spontaneous imbibition tests, core flooding and capillary pressure test. In the following, the term nanofluid refers to the prepared final solution as described above.


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2.3.

Contact Angle Measurement and Spontaneous Imbibition

Contact angle was the first criteria to evaluate the performance of the different nanofluids. After rock preparation, all substrates were aged in heavy oil for about one week to alter the wetting tendency of their surface to nearly oil wet. All aging processes were performed at the temperature of 70 °C and atmospheric pressure. The pre-treatment measurements were performed at this stage. Then the oil-wet substrates were aged for about 24 hours in prepared nanofluids as described in the previous part. After drying the substrates in oven for 12 hours, the post-treatment measurements were performed. To measure the contact angle, a decane droplet was released and captured below the rock substrate which was submerged in brine. Side images of decane droplets captured below the substrate were taken and analysed using in-house built drop shape analyser (DSA) with the accuracy of + 0.5°. The second technique to evaluate wettability alteration was spontaneous imbibition experiment. All spontaneous imbibition experiments were performed by Amott cell. Amott cell is a visual glass cell with a graduation tube on the top. It can be used for both measurement of spontaneous imbibition and spontaneous drainage at atmospheric pressure. For spontaneous imbibition test, an oil saturated core sample is placed inside the cell and then it is filled up with brine for a period of time. The expelled oil from the core can be collected and measured accurately by reading the graduation on top of the cell. In this study, the imbibition experiments were conducted for both nanofluid and its base-fluid (without nanoparticles). It should be noted that, as mentioned before, the nanofluid and its base-fluid also diluted in water at concentration of 5 wt %. All imbibition experiments were conducted at 70 °C and atmospheric pressure. The amount of recovered oil was measured versus time until oil production was stopped. Cores No. 1 and 4 were used for this experiment. All spontaneous imbibition tests were performed without initial water saturation.

2.4.

Core Flooding Experiments


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Core flooding experiments were performed on reservoir condition to investigate the performance of wettability alteration on oil recovery. Core No. 2 and 3 were used for these experiments. Both core plugs were fully saturated with oil and were aged for about one week at 70 °C and atmospheric pressure. After aging, primary water flooding was conducted and the recovery was recorded. Primary water flooding was continued until no oil was recovered from the plugs. Then, two pore volume of nanofluid was injected into the core plugs and left them to soak for about 24 hours. After that, the secondary water flooding was conducted to investigate if additional oil can be recovered. Injection rate were adjusted to have a same capillary number (Nc) in all experiments to make sure that the additional oil production is not due to increase in viscous forces. The experiments were performed on the temperature of 70 °C and net overburden pressure of 600 psig.

2.5.

Capillary Pressure Determination

Capillary pressure measurement was performed for core No. 5 to evaluate the performance of wettability alteration by nanoparticle at reservoir condition. The drainage capillary pressure curve was measured before and after nanofluid injection. For this purpose, CAPRI apparatus provided by VINCI Company was used. The CAPRI system can be used for determination of the capillary pressure curves and the electrical resistivity index as a function of core sample saturation at high pressure and temperature. The main part of this instrument is a core holder furnished with hydrophobic and hydrophilic ceramics, whole system housed in a temperature air bath. The automated pumping systems for both brine and oil and hydrophobic and hydrophilic ceramics allow applying positive and negative capillary pressure inside core. In this study, both experiments were performed at reservoir conditions. Before the experiment, the core plug was saturated 100% with brine from Persian Gulf. After pre-evaluation capillary pressure measurement, the plug was washed and saturated with nanofluid and kept to soak for 24 hours at reservoir condition. Then the drainage capillary pressure experiment was repeated again with the same procedure as the preevaluation measurement.


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3. RESULTS AND DISCUSSION 3.1.

Preliminary Evaluation Based on Contact Angles

Contact angle measurements were performed for all treated rock substrates to evaluate and compare the performance of each nanofluid. In the first set of the experiments, the results of contact angle for treated substrates and non-treated one were compared and three of them with better performance were selected. To make sure about the repeatability of the results, two different substrates were aged in each nanofluid and two separate tests were conducted. Table 3 shows the result of two tests and the average value of them for each nanofluid. It should be noted that, contact angle of substrates before aging in nanofluids was around 39-40 degree. Thus, the performance of each nanofluid can be compared considering contact angle value before and after aging. According to Anderson’s table 3, contact angle between 0° and 60°-75° for water droplet can be considered water wet, a range between 60°-75° to 105°-120° demonstrates neutral wettability and a range between 105°-120° to 180° indicates oil wettability of the system. This classification is used in this study as the criteria to preliminarily screen the nanofluids. It should be noted that, all the reported contact angles in this study are measured through decane droplet (lighter phase) contact angle. The contact angle based on heavier phase (water) can be calculated by subtracting the measured value from 180°. As it is evident from Figure 2 and Table 3, the performance of five nanoparticles of Zirconium dioxide (ZrO2), Calcium carbonate (CaCO3), Carbon nanotube type 1 (CNT), Titanium dioxide (TiO2) and Silicon dioxide (SiO2) are in an acceptable level to be selected for the next step of evaluation. To focus just on the metal oxide nanofluids, excluding ZrO2 which was previously reported by our research group (Ref. 6), Calcium carbonate, Titanium dioxide and Silicon dioxide were selected for the next steps.

3.2.

Salinity Effect

Nanoparticles stability is one of the main issues that should be considered in different environments. The first challenge encountered in a traditional oil field treatment is the ionic nature (salinity) of the carrier fluid. The nanofluids are adversely affected by oppositely charged ions


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present in solution.39 Recently, Li et al.40 have shown that the retention of the nanoparticles in brine solution probably result from the electrostatic attraction between the negative charged particle clusters and parts of the calcium carbonate surface with positive zeta potential. Based on their experimental results the most non-interacting nanoparticles can be small particles with zero charge. Considering these results and ionic nature of oil reservoirs, the performance of candidate nanofluids were investigated in different salinity. In this step, the substrates were treated by nanofluids diluted to 5 wt% in brine with different salinities. Sea water from Persian Gulf and three synthetic brines (NaCl) with salinity of 80000, 100000 and 120000 ppm were used. It is found that the selected nanofluids are stable and clear solution in all of the above salinity conditions. To measure the contact angle values, two different substrates were treated and used to make sure about the repeatability of the results. As shown in Table 4, the decane contact angle of all treated substrates has decreased with increasing salinity and starts increasing again from 100,000 ppm to 120,000 ppm (It can be assumed that there is a minimum value for contact angle around 100,000 ppm). However the performance of CaCO3 was in an acceptable level for all salinity tests (less than 90°). The SiO2 nanoparticles also showed a reasonable function in presence of brine with salinity up to 80000 ppm (the contact angles were below 90°). In addition, results of Table 4 indicate that the performance of TiO2 nanoparticle is not at a desirable level. Therefore CaCO3 and SiO2 nanofluid were selected for the spontaneous imbibition experiments.

3.3.

Spontaneous Imbibition

Spontaneous imbibition occurs when a wetting fluid displaces a non-wetting fluid in porous media. If the porous media is exposed to a fluid with an effective contact angle smaller than 90°, the fluid spontaneously imbibes into the pores. In order to evaluate the performance of the selected nanoparticles, two imbibition experiments were conducted for each nanoparticle (CaCO3 and SiO2). The first experiment was performed for base-fluid without nanoparticles and the second one with the nanofluid. The performance of the nanoparticles can be obviously observed by comparing the results. Figure 3 shows the result for nanofluid of CaCO3 and Figure 4 shows the same results for SiO2 nanofluid. As it is shown in Figure 3, poor imbibition of the base-fluid into core proves oil-wet tendency of the rock surface (maximum oil recovery is 5 % OOIP). This behavior is in agreement with the data of contact angle for the untreated trims (140°). The result for CaCO3


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nanofluid imbibition into the core shows the recovery around 20% OOIP. Although it cannot be concluded that the core is water wet, it is obvious that around 15 % OOIP recovered due to presence of nanofluid. Figure 4 also shows the result of the same experiment for SiO2 nanofluid. As indicated in Figure 4, oil recovery has increased by 25% because of the presence of SiO2 nanoparticles in the base liquid. However the speed of oil production was higher when CaCO 3 nanofluid was used, but the maximum production was around 10% higher by SiO2 nanofluid. This observation can be presented more sensibly when the results are scaled based on the literature scaling relationship for spontaneous imbibition of liquid-liquid systems.

3.4.

Generalized Scaling Equation

Scaling relationships can be used for estimation of oil recovery by spontaneous imbibition. Ma et al. 41 reported Equation 1 for scaling of imbibition data based on the equation of Mattax and Kyte 42

as: 𝑘 𝜎 1 𝑡𝐷 = 𝐶 𝑡√ 𝜑 √𝜇𝑜 𝜇𝑤 𝐿2𝐶

(1)

where 𝑡𝐷 is a dimensionless time. C, a unit conversion factor, is equal to 0.018849 if the imbibition time 𝑡 is in minutes, 𝑘 the permeability in md, 𝜑 the fractional porosity, 𝜎 the interfacial tension in dyne/cm, 𝜇 the water viscosity in cP, and L a characteristic length in cm. Equation 1 was used to scale the results of the imbibition experiments. Figure 5 shows scaled results of both imbibition experiments based on Ma et al. 41 equation.

Ma et al.41 also proposed a single parameter model to fit literature imbibition data of water-wet system. They proposed the following equation which is a modified form of Aronofsky et al. equation: 𝑅 𝑅𝑚𝑎𝑥

= 1 − 𝑒 −𝑎 𝑡𝐷


(2)

43

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where R is oil recovery by imbibition, 𝑅𝑚𝑎𝑥 is ultimate oil recovery by imbibition, and “a” is the oil production decline constant. They reported that all imbibition data for water-wet system can be scaled by this equation with a production decline constant of 0.05. As shown in Figure 5, imbibition results can be scaled based on the proposed equation but with different decline constant (a). For imbibition experiment of SiO2 the results were fitted with a=0.004 which means different behaviour from water-wet system. For imbibition experiment of CaCO3, the results were fitted with decline constant of 0.05. It means that this system acts similar to a water-wet system. Although SiO2 nanofluid recovered more oil (maximum recovery of 30% OOIP), the rate of recovery was higher with CaCO3 nanofluid. This behaviour was also observed in the core flooding experiments.

3.5.

Core Flooding Results

The durability of modifier agent, adequate treatment process, sensitivity of treatment to rock mineralogy and treatment uniformity can be only investigated by core flooding experiments. In this step, the performances of the selected nanoparticles were examined by core flooding experiments. As mentioned before, the fully oil saturated core was flooded by water to measure the oil recovery due to primary water flooding. The water injection was continued until no additional oil was recovered. Then the treatment was performed by injection of two pore volumes of nanofluid. After soaking, secondary water flooding similar to primary injection was repeated to measure the additional oil recovery. Figure 6 and 7 show recovered oil versus pore volume of the injected water before and after the treatment. As shown in Figure 6, primary water flooding has recovered near 60 % of OOIP after 3 pore volumes. Although the core was aged in oil for one week at 70 ℃, this high amount of oil recovery from primary water flooding could be evidence that the rock surface was not completely oil wet and aging process could not change the wetting tendency of the surface to strongly oil wet. However around 40 % of the oil was remained in the pores which could not be recovered during primary injection. After nanofluid treatment, it was observed that around 9 % of OOIP could be recovered due to this treatment. Similar results were observed for SiO2 nanofluid treatment (Table


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5). As it is evident from Figures 6 and 7, nearly all recovered oil was produced after 2-3 pore volume injection. It can be due to low rate of injection which was around 2 cc per hour. In addition, it can be concluded that the oil recovery was slower from the treated core by SiO2 nanofluid in comparison to recovered oil from core treated by CaCO3 nanofluid. The results of recovered oil for SiO2 nanofluid shown in Figure 6 are in good agreement with imbibition results presented before. In Figure 8 oil recoveries for both core plugs treated by CaCO3 nanofluid and SiO2 nanofluid are shown. Rate of oil recovery in primary water injection reveals that displacement can be considered piston like. Although the ultimate recovery was higher for the core treated by SiO2 nanofluid, the enhanced oil was produced after 8 pore volumes of water injection. For the core treated by CaCO3, the enhanced oil was recovered just after one pore volume injection. These results are in line with the rate of production at imbibition experiment for CaCO3 nanofluid.

3.6.

Drainage Capillary Pressure

There are several indexes to express the wetting tendency of rock surface such as USBM, Amott and Amott-Harvey. All of these indexes are determined based on the capillary pressure data. At this stage, to evaluate the effect of nanoparticles treatment on surface wettability, a primary drainage capillary pressure measurement was conducted by porous plate method before and after the treatment. The CaCO3 nanofluid was selected for this experiment based on the observed results in core flooding and free imbibition experiments. Figure 9 shows the primary drainage capillary pressure curve before and after the treatment for core plug No. 5. The results, demonstrated that the irreducible water saturation and the entry pressure were increased after treatment by CaCO3 nanaofluid. Considering these results, it can be concluded that the wettability of the rock surface has been changed to more water wetting. However, although it is not possible to quantify this wettability alteration, changing the wetting tendency of the rock surface is evident. Moreover, higher capillary pressure for the same saturation means higher tendency toward water that prevents oil to enter the pores and needs a higher capillary pressure.


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3.7.

Theoretical Explanation

The conventional concepts behind the wetting and spreading of simple liquids cannot be applied to nanofluids. It has been shown recently that the structural disjoining pressure plays an important role in fluid ability to spread on surface and alters the spreading dynamics.44-47 Recent studies have shown that the presence of nanoparticles in three-phase contact region increases the tendency to create a wedge-film structure. This wedge film separates formation fluid such as oil, paraffin, water and gas from formation surface.39 Calculations performed by Wasan and Nikolov44 showed that the spreading coefficient increases exponentially as the film thickness decreases. Wasan and Nikolov 44 applied the concept of structural disjoining pressure and showed that the driving force for the spreading of the nanofluid is the structural disjoining pressure gradient or film tension gradient (Δγ) which is directed towards the wedge from the bulk solution. They pointed out that the structural component of the disjoining pressure is strong enough to move a liquid wedge. They calculated disjoining pressure, based on statistical mechanics using the method reported by Trokhymchuk et al.48 They have shown that the pressure is higher near the vertex and as the film thickness decreases towards the wedge vertex, the structural disjoining pressure increases. In this study, near the vertex disjoining pressure was calculated based on the scaled figure presented by Wasan and Nikolov.44 Figure 10 shows calculated disjoining pressure near the vertex for SiO2 nanoparticles. The mean size of SiO2 nanoparticles used in this study was estimated to be around 35 nm. As shown in Figure 10, near to the point of contact (assuming one layer of particle thickness) the pressure could be more than 7 Psi. This driving force can be strong enough to initiate a Marangoni flow towards the vertex. Furthermore, a set of contact angle measurements were designed and performed to evaluate the instantaneous performance of the nanofluids for changing the wetting tendency of the surface. In this experiment, we have used the same rock type and same procedure for substrate preparation, but the substrate was not treated before the experiment. The droplet of decane was released and captured below the substrate surface in the bulk of distilled water. Then the nanofluid was injected to the bulk of water and contact angles were measured versus time.


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Figure 11 shows the measured contact angles versus time after injection of CaCO3 nanofluid to the bulk phase. As mentioned above, the substrate was not treated by nanofluids before the test; hence we should not expect to observe the same results as reported in Table 3. The pictures in the Figure 11 were flipped and the contact angles were measured based on lighter component (decane). As shown in this Figure, decane droplet was pinned to the surface at beginning with contact angle of 14° but the contact angle was increased gradually to the value of 57° after 60 minutes. It supports the way nanaoparticles can alter the wetting of a surface as soon as they contact with oil wet surface. The similar results have observed recently by other researchers49 which prove the ability of nanoparticles for rapid spreading on surface.

4. CONCLUSION Eight different nanoparticles were used in this study to investigate their performances for wettability alteration on carbonate rocks. Both qualitative and quantitative wettability determination techniques were used to find the best candidates among all nanoparticles. Based on the preliminary evaluation by contact angles of decane/water system, SiO2, TiO2 and CaCO3 nanoparticles were selected. Moreover, the performance of the treated substrates in different saline environments was examined. The results showed that the decane contact angle decreases with increasing salinity. Although all nanofluids behaved in the same way, the performances of CaCO3 and SiO2 were in an acceptable level for all salinity tests to be selected for the spontaneous imbibition and core flooding experiments. Spontaneous imbibition results confirmed the active role of CaCO3 and SiO2 nanoparticles. Oil recovery has increased by a factor of 4 and 6 when CaCO3 and SiO2 nanoparticles were present in the base-fluid, respectively. The imbibition results were scaled based on the Ma et al. equation. Scaled decline constant of 0.05 for CaCO3 imbibition test proved that it acts similar to a water-wet system. Results of coreflooding showed the effectiveness of the CaCO3 and SiO2 nanofluids for EOR purposes. Oil recovery has increased about 8-9 % after injection of nanofluids. The results of both imbibition and core flooding experiments demonstrate that the SiO2 nanoparticles treatment


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improves the oil recovery more than the treatment by CaCO3 nanoparticles, but it happens at a longer time. The results of capillary pressure experiments before and after treatment by CaCO3 nanofluid demonstrated that the irreducible water saturation and the entry pressure were increased as a result of surface treatment. It is concluded that the wettability of the rock surface has been changed to more water wetting after injection of the nanofluids. In addition, it is proposed that the generated gradient in structural disjoining pressure was the responsible mechanism for changing dynamic wettability. Disjoining pressure was calculated approximately near the vertex for SiO2 nanoparticles. Based on this calculation, it was shown that the disjoining pressure of the nanoparticles layer near the contact point was high enough to advance on the surface and remove the oil from the surface. As presented in Figure 11, the oil removal by nanofluids is not a slow process, supporting the quick responses at the imbibition tests. It seems that the main mechanism of oil recovery by nanofluids is the IFT gradient or Marangoni flow, initiated by nanoparticle ordering and nanostructure forming near the wedge vertex. Accepting this idea, the smaller nanoparticles might be better candidates for oil recovery. Moreover, with similar operating mechanism, the oil recovery must show similar behaviour for different nanofluids. Both of these corollary ideas can be assumed as the subject of further investigations, mentioning that the latter is already under question considering the observed different behaviours at Figure 5.

AUTHOR INFORMATION Corresponding Author *Telephone: +98 21 88333058. Fax: +98 21 88632976. E-mail: [email protected].

ACKNOWLEDGMENTS This work is supported financially by NIOC-R&D (Contract No. 81-88009), which is gratefully acknowledged.


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

NOMENCLATURE C = conversion factor k= permeability (L2) L= length (L) t = time (T) R=recovery a=decline constant Greek Letters

σ Interfacial tension µ Viscosity 𝜑 Porosity Subscript

C Characteristics D Dimensionless max Maximum o oil w water

REFERENCES 1) Ahmed. T. Reservoir Engineering Handbook; Gulf Professional Publishing, Elsevier: Burlington, USA, 2010; pp 1341.


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2) Anderson, W. J. Pet. Technol. 1986, 1125–1142. 3) Anderson, W. J. Pet. Technol. 1986, 1246–1262. 4) Buckley, J. S.; Liu, Y., Monsterleet, S. SPE J. 1998, 3 (1), 54–61. 5) Hirasaki, G.; Zhang D. L; SPE Journal 2004, 151-162. 6) Karimi, A.; Fakhroueian, Z.; Bahramian, A.; Khiabani, N. P.; Darabad, J. B.; Azin, R.; Arya, S. Energy Fuels 2012, 26 (2), 1028−1036. 7) Al-Hadhrami, H.; Blunt, M. SPE Reservoir Eval. Eng. 2001, 4 (3), 179−186. 8) Nasralla, R.; Bataweel, M.; Nasr-El-Din, H. J. Can. Pet. Technol. 2013, 52 (2), 144−154. 9) Zhang, P.; Austad, T. Colloids Surf. A 2006, 279 (1), 179−187. 10) RezaeiDoust, A.; Puntervold, T.; Strand, S.; Austad, T. Energy Fuels 2009, 23 (9), 4479−4485. 11) Ju, B.; Dai, S.; Luan, Z.; Zhu, T.; Su, X.; Qiu, X. SPE paper 77938-MS presented at SPE Asia Pacific Oil and Gas Conference and Exhibition, Melbourne, Australia, Oct. 8-10, 2002. 12) Ju, B.; Fan, T.; Ma, M. China Particuology 2006, 1, 41–46. 13) Ju, B.; Fan, T. Powder Technol. 2009, 192, 195−202. 14) Maghzi, A.; Mohebbi, A.; Kharrat, R. Transp. Porous Media 2011, 3, 653−664. 15) Bink, B. P.; Whitby, C. P. Colloids Surf. A 2005, 253, 105-115. 16) Zhang. T.; Davidson, A.; Bryant, S. L.; Huh, C. SPE paper 129885-MS presented at SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, USA, April 24-28, 2010. 17) Espinosa, D.; Caldelas, F.; Johnston, K.; Bryant, S. L.; Huh, C. SPE paper 129925-MS presented at SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, USA, April 24-28, 2010. 18) Fletcher, A.J.P.; Davis, J.P. SPE paper 129531-MS presented at the 2010 SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, USA, April 24-28, 2010. 19) Hendraningrat, L.; Li, S.; Torsæter, O. SPE paper 159161-MS presented at the SPE Russian Oil & Gas Exploration & Production Technical Conference and Exhibition, , Moscow, Russia, Oct. 16–18, 2012. 20) Hendraningrat, L.; Engeset, B.; Suwarno, S.; Torsæter, O. SPE paper 163335-MS presented at SPE Kuwait International Petroleum Conference and Exhibition, Kuwait City, Kuwait, Dec. 10-12, 2012. 21) Hendraningrat, L.; Li, S.; Torsæter, O. SPE paper 164106-MS presented at SPE International Symposium on Oilfield Chemistry, The Woodlands, Texas,USA, 8-10 April, 2013. 22) Hendraningrat, L.; Li, S.; Torsæter, O. SPE paper 165283-MS presented at SPE Enhanced Oil Recovery Conference, The Kuala Lumpur, Malaysia, July 2-4, 2013. 23) Wang, H-W. Solid State Phenom 2007, 121–123, 1497.


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24) Sefiane, K.; Skilling, J.; MacGillivray, J. Adv. Colloid Interface Sci. 2008, 138, 101-120. 25) Onyekonwu, M.; Ogolo, N. A. SPE paper 140744-MS presented at Nigeria Annual International Conference and Exhibition, Tinapa- Calabar, Nigeria, 31 July - 7 August, 2010. 26) Skauge, T.; Spildo, K.; Skauge, A. SPE paper 129933-MS presented at the 2010 SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, USA, April 24-28, 2010. 27) Giraldo, J.; Benjumea, P.; Lopera, S.; Cortés, F. B.; Ruiz, M. A. Energy Fuels 2013, 27, 3659−3665. 28) Hosseinpour, N.; Khodadadi, A. A.; Bahramian, A.; Mortazavi Y. Langmuir 2013, 29, 14135−14146. 29) Ehtesabi, H.; Ahadian, M.; Taghikhani, V. Energy Fuels, DOI: 10.1021/ef5015605. 30) Nassar, N. N.; Hassan, A.; Vitale, G. Applied Catalysis A: General 2014, 484, 161–171. 31) Liu, H.; Zhai, J.; Jiang, L. Soft Matter 2006, 2, 811–821. 32) Janbey, A.; Pati, R. K.; Tahir, S.; Pramanik, P. Journal of the European Ceramic Society 2001, 21, 2285-2289. 33) Ma, M.; Zhu, Y.; Cheng, G.; Huang, Y. Materials Letters 2008, 62, 3110–3113. 34) Ketzial, J. J.; Nesaraj, A. S. Journal of Ceramic Processing Research 2011, 12(1), 74-79. 35) Meenakshi, S. D.; Rajarajan, M.; Rajendran, S.; Kennedy A. R.; Brindha, G. Elixir Nanotechnology 2012, 50, 10618-10620. 36) Gao, H.; Yang, J. Modern Applied Science 2010, 4(9), 152-156. 37) Mahshid, S.; Askari, M.; Sasani Ghamsari, M. Journal of Materials Processing Technology 2007, 189, 296–300. 38) Chen, K. L.; Chiang, A.; Tsao, H. K. Journal of Nanoparticle Research 2001, 3, 119–126. 39) McElfresh, P.; Holcomb, D.; Ector, D. SPE paper 154827-MS presented at SPE International Oilfield Technology Conference, Noordwijk, The Netherlands, June 12-14, 2012. 40) Li, Y. V.; Cathles, L. M.; Archer L. A. Journal of Nanoparticle Research 2014, 16 (8), 1-14. 41) Ma S.; Morrow N. R.; Zhang, X. J. of Pet. Science and Eng. 1997, 18, 165-178. 42) Mattax, C.C.; Kyte, J.R. Soc. Pet. Eng. J. 1962, 177- 184. 43) Aronofsky, J.S.; Masse, L.; Natanson, S.G. Trans. A1ME 1958, 213, 17-19. 44) Wasan, D. T.; Nikolov, A. D. Nature 2003, 423, 156-159. 45) Chengara, A.; Nikolov, A. D.; Wasan, D. T.; Trokhymchuk, A.; Henderson, D. Journal of Colloid and Interface Science 2004, 280,192–201. 46) Wasan, D. T.; Nikolov, A. D.; Kondiparty, K. Current Opinion in Colloid & Interface Science 2011, 16, 344–349. 47) Kondiparty, K.; Nikolov, A. D., Wu, S.; Wasan D. T. Langmuir 2011, 27 (7), 3324–3335.


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48) Trokhymchuk, A.; Henderson, D.; Nikolov, A.; Wasan, D. T. Langmuir 2001, 17, 4940-4947. 49) Zhang, H.; Nikolov, A.; Wasan, D. T.; Energy Fuels 2014, 28, 3002−3009.


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Table1. Properties of the prepared plugs for Imbibition, core flooding and capillary pressure experiments Plug

Length

Total

Porosity

Permeability

Connate Water

No.

(cm)

Volume(cc)

(%)

(mD)

Saturation (%)

1

4.40

50.2

12.2

0.30

9.8

2

7.05

80.3

11.4

0.25

12.0

3

6.84

77.9

13.2

0.24

11.7

4

7.40

84.3

11.4

0.13

10.4

5

6.67

76.0

14.2

0.13

-

Table2. Properties of the nanofluids used in this study

Sample No. 1

Nano Fluid ZrO2

41 A

Shape of

Approx. Size

Nanoparticle

(nm)

Spherical

>35

-

Viscosity (cP)

2

CaCO3

Spherical

-

-

3

CNT Type 1 (174)

Tube

-

-

4

CNT Type 2 (26)

Tube

-

-

5

TiO2 New 12

Spherical

>35

-

6

SiO2

52

Spherical

30-40

0.933

7

MgO

175

Spherical

>40

-

8

Al2O3

312

Spherical

>40

-

Bar shape

-

1.090

9

CeO2 21


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Energy & Fuels

Table3. Preliminary evaluation by contact angle measurements for each nanofluid Test 1

Test 2

Contact Angle

Contact Angle

(Degree)

Avg. Contact

Avg. Contact Angle

Angle based on

based on Heavier

(Degree)

Lighter component

Component

Sample No.

Nano Fluid

Non Aged

-

39.5

40.0

39.7

140.2

1

ZrO2

116.5

124.0

120.2

59.7

2

CaCO3

120.0

123.5

121.8

58.2

3

CNT Type 1

116.0

113.0

114.5

65.5

4

CNT Type 2

59.0

56.5

57.7

122.2

5

TiO2

130.5

127.0

128.8

51.2

6

SiO2

122.0

101.0

111.5

68.5

7

MgO

81.0

82.5

81.7

98.2

8

Al2O3

77.0

76.0

76.5

103.5

9

CeO2

72.5

80.5

76.5

103.5


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Table 4. Results of salinity impact on the measured contact angles Avg. Contact

Avg. Contact

Angle

Angle

based on

based on

Lighter

Heavier

component

Component

129.0

127.8

52.2

124.5

126.0

125.3

54.7

TiO2

27.0

22.0

24.5

155.5

CaCO3

120.5

125.5

123.0

57.0

SiO2

115.5

119.0

117.3

62.7

6

TiO2

25.0

23.5.0

24.3

155.7

7

CaCO3

75.0

70.0

72.5

107.5

SiO2

49.0

48.0

48.5

131.5

9

TiO2

34.5

41.5

38.0

142.0

10

CaCO3

99.0

102.5

100.75

79.25

SiO2

51.5

51.5

51.5

128.5

TiO2

22.0

23.0

22.5

157.5

Test 1

Test 2

Contact

Contact

Angle

Angle

(Degree)

(Degree)

CaCO3

126.5

SiO2

3 4

Sample No.

Salinity

1

Nanofluid

Sea Water 2 (30 000 ppm)

5

8

11 12

80 000 ppm

100 000 ppm

120 000 ppm


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Energy & Fuels

Table 5. Oil recoveries before and after the treatment by CaCO3 and SiO2 nanofluid

Plug No.

Nanofluid

Porosity

Max. Oil Recovery after

(%)

Primary Waterflooding (%)

Enhanced Oil Recovery after Secondary Waterflooding (%)

2

CaCO3

11.4

56.2

8.7

3

SiO2

13.1

60.7

7.7


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(a)

(b)

(c)

(d)

(e) (e)

(f)

Figure 1. Scanning Electron Microscopy (SEM) images of prepared nanoparticles: (a) Al2O3, (b) SiO2, (c) CeO2, (d) TiO2, (e) MgO, (f) ZrO2.


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180 160 140 120

Contact angle (Degree)

100 80 60 40 20 0

Figure 2. Performance of different nanofluids based on the contact angle of lighter phase (Decane). The higher contact angle means the higher water tendency. The blue bars (CaCO3, TiO2 and SiO2) were selected for the next experiments.

25

20

OOIP (%)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

CaCO3 Nanofluid Base Fluid

15

10

5

0 0

20

40

60 Time (hr)


80

100

Energy & Fuels

Figure 3. Spontaneous imbibition of CaCO3 nanofluid and its base-fluid

35 30 25

OOIP (%)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 26 of 31

SiO2 Nanofluid Base Fluid

20 15 10 5 0 0

20

40

60 Time (hr)

80

100

Figure 4. Spontaneous imbibition of SiO2 nanofluid and its base-fluid


120

Page 27 of 31

100

CaCO3 Nanofluid Imbibition

Oil Recovery ( % Recoverable Oil)

SiO2 Nanofluid Imbibition Generalized Eq. (Ma et al.1997) a=0.004

80

Generalized Eq. (Ma et al.1997) a=0.05 60

40

20

0 0.1

1

10 Dimensionless Time (tD)

100

1000

Figure 5. Oil recovery vs. dimensionless imbibition time for both experiments of CaCO 3 and SiO2 nanofluids. Both curves can be fitted by single parameter function reported by Ma et al. (1997) with: a=0.05 for CaCO3 and

a=0.004 for SiO2.

Primary Recovery %

Enhanced Recovery %

60

15

50

Recovery % OOIP

Recovery %OOIP

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

40 30 20

10 5

10 0

0 0

2 PV Injected 4

6

0

2

PV Injected

4

Figure 6. Results of oil recovery during waterflooding before and after CaCO 3 nanofluid treatment


6

Energy & Fuels

Primary Recovery %

70

Enhanced Recovery % 10

Recovery %OOIP

Recovery %OOIP

60 50 40 30 20 10

8 6 4 2 0

0 0

2

PV Injected

4

6

0

5

10

PV Injected

Figure 7. Results of oil recovery during waterflooding before and after SiO 2 nanofluid treatment

80 70

Oil Recovery (% OOIP)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 28 of 31

60 50 40 CaCO3 Primary Waterflooding 30

CaCO3 Secondary Waterflooding (After Nanofluid Inj.)

20

SiO2 Primary Waterflooding

10

SiO2 Secondary Waterflooding (After Nanofluid Inj.)

0 0

2

4

6

8 Injected PV

10

12

14

Figure 8. Comparison of oil recoveries in primary and secondary water injection for both plugs treated by CaCO 3 and SiO2 nanofluids.


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Figure 9. Primary drainage capillary pressure curve before and after CaCO3 nanofluid treatment. Pore sizes are calculated from capillary pressure data and measured IFT of 29 mN/m. Lines are guide to eye.


Energy & Fuels

Solid Nanofluid Film

8

Nanoparticle

6

Disjoining Pressure, Psi

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

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4 2 0 -2 -4 -6 30

50

70

90

110

130

150

Distance (nm) Figure 10. Disjoining pressure near the vertex calculated for SiO2 nanoparticles in our experiments using the analytical method of Wasan and Nikolov 44 and Trokhymchuk et al.48


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100 80

Contact Angle (degree)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

60 40 20 0 0

10

20

30

40

50

60

Time (minutes) Figure 11. Contact angles of decane droplet versus time when it was exposed to CaCO3 nanofluid. The pictures were flipped and the contact angles were measured based on lighter component (decane)


Comparative Study of Using Nanoparticles for Enhanced Oil Recovery

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