Synergistic application of aluminium oxide nanoparticles and oilfield polyacrylamide for enhanced oil recovery

Journal of Petroleum Science and Engineering 182 (2019) 106345

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Synergistic application of aluminium oxide nanoparticles and oilfield polyacrylamide for enhanced oil recovery

T

Afeez O. Gbadamosia, Radzuan Junina,b,*, Muhammad A. Manana,b, Augustine Agia, Jeffrey O. Oseha, Jamilu Usmanc a

Department of Petroleum Engineering, Faculty of Chemical and Energy Engineering, Universiti Teknologi Malaysia, 81310 Skudai, Johor Bahru, Malaysia Institute for Oil and Gas, Faculty of Chemical and Energy Engineering, Universiti Teknologi Malaysia, 81310 Skudai, Johor Bahru, Malaysia c Advanced Membrane Technology Research Centre (AMTEC), Faculty of Chemical and Energy Engineering, Universiti Teknologi Malaysia, 81310 Skudai, Johor, Malaysia b

A R T I C LE I N FO

A B S T R A C T

Keywords: Enhanced oil recovery Polymers Nanoparticles Polymeric nanofluid Aluminium oxide Nanotechnology

Due to the inherent limitation of oilfield polyacrylamide in reservoir temperature and salinity, nanoparticles (NPs) have been extensively studied for their application in enhanced oil recovery (EOR) because of their unique properties and availability in large quantities. Recent trend in nanotechnology involves incorporating NPs as additive with polymer to form novel materials termed polymeric nanofluids (PNF's) for EOR. However, previous studies have investigated and focussed more on the suitability of silica (SiO2) polymeric nanofluids. In this work, the potential application of metal oxide polymeric nanofluid for EOR was explored and evaluated. Aqueous HPAM-based Al2O3 PNF's were formulated and characterised using Transmission Electron Microscopy (TEM) and Fourier-transform infrared (FTIR) spectroscopy. The performance of aluminium oxide (Al2O3) NP on the rheological properties of HPAM in the presence of different electrolyte concentrations representative of field brine and typical reservoir temperatures were investigated. Wettability alteration study of Al2O3 PNF was carried out using DataPhysics optical contact angle (OCA) instrument. Results obtained for Al2O3 PNF were compared to the widely reported SiO2 PNF and base polymer without nanomaterial. Experimental results show that the rheological properties improved while degradation of HPAM macromolecule was inhibited due to the addition of NPs. At 2,000 ppm HPAM solution (25 mol. % degree of hydrolysis), 0.1 wt% NP concentration was found to be the optimal choice for Al2O3 NP which gives rise to the highest viscosity on the rheological characterization. Al2O3 PNF exhibited better steady shear viscosity performance under the different electrolyte concentrations and temperatures studied. Al2O3 PNF altered the wettability of the porous media from oil-wet to water-wetting condition. Finally, oil displacement test in sandstone cores at typical reservoir temperature and salinity showed that Al2O3 PNF had 11.3% incremental oil recovery over conventional HPAM. This study is beneficial for extending the frontier of knowledge in nanotechnology application for EOR.

1. Introduction Crude oil has remained the major source of world energy supply despite considerable efforts on other sources of energy (Giraldo et al., 2017). Due to rapid industrialization, there is an increase in world energy demand leading to the need to produce increasing volume of crude oil to support this demand (Alvarado and Manrique, 2010; Rezvani et al., 2018). Meanwhile, the oil and gas industry is fazed with the dearth of new abundant reserves and low production from existing reservoirs (Kumar and Mandal, 2017; Zhao et al., 2018). Due to the capital intensive nature involved in searching for new hydrocarbon

deposits, the industry is dissipating more energy and drive to recovering oil from existing reservoirs (Bayat et al., 2016; Esfandyari Bayat et al., 2014; Gbadamosi et al., 2018b). After primary and secondary recoveries, two-third of crude oil deposit is either bypassed or trapped by capillary forces in the reservoir (Xu et al., 2018). Thus, numerous tertiary oil recovery methods also known as enhanced oil recovery (EOR) methods have been proposed, devised and utilised for higher oil recovery (Abbas et al., 2018; Agi et al., 2018; Gbadamosi et al., 2018b; Pillai et al., 2018; Yekeen et al., 2018). Of the numerous EOR methods, polymer flooding, a chemical EOR method has been adjudged as the most effective and efficient way to

* Corresponding author. Department of Petroleum Engineering, Faculty of Chemical and Energy Engineering, Universiti Teknologi Malaysia, 81310 Skudai, Johor Bahru, Malaysia. E-mail address: [email protected] (R. Junin).

https://doi.org/10.1016/j.petrol.2019.106345 Received 23 February 2019; Received in revised form 4 August 2019; Accepted 6 August 2019 Available online 07 August 2019 0920-4105/ © 2019 Elsevier B.V. All rights reserved.

Journal of Petroleum Science and Engineering 182 (2019) 106345

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studied the use of titanium oxide (TiO2), silicon oxide (SiO2) and Al2O3 NPs for EOR at higher temperatures (26–60 °C) in intermediate-wet limestone. The NPs lowered IFT and altered the wettability of the limestone at all temperatures. Capillary force reduction was adduced as the mechanism of EOR by the investigated nanofluids. Despite their significant efficiency for EOR, the stability of the NPs in the presence of reservoir brine and elevated temperature condition remains a concern for the field implementation of nanofluids. More recently, researchers have shown that appropriate addition of NPs to polymer form novel materials which exhibit excellent and fascinating properties than the individual polymer or NP, which are beneficial for EOR applications (AlamiNia and Khalilinezhad, 2017; Almahfood and Bai, 2018; Babamahmoudi and Riahi, 2018; Cao et al., 2018; Giraldo et al., 2017; Ko and Huh, 2019; Kumar et al., 2017; Lee and Yoo, 2016; Saha et al., 2018). These includes improved rheological properties and degradation inhibition even in the presence of reservoir brine salinity and hardness and elevated temperature conditions, resulting in a high oil recovery of the injectant. Besides their higher functionality, NPs are available in large quantities and relatively cheap, hence, making the overall process economical (Lee and Yoo, 2016). Maghzi et al. (2014) examined the influence of dispersed SiO2 NPs on non-ionic polyacrylamide (PAM) solution and reported an increase in polymer viscosity and a higher oil recovery. Rezaei et al. (2016) induced HPAM molecules with clay nanoplatelets and studied the rheology of the resultant polymeric nanofluid (PNF) at typical reservoir shear rates. Result shows that the pseudoplasticity and shear-thinning of the polymer solution at typical reservoir shear rate improved by adding clay nanoparticles. They quoted an incremental oil recovery factor of 33% over conventional HPAM polymer was achieved by inducing the HPAM polymer molecule with surface modified clay NPs. Zhu et al. (2014a,b) formed polymeric nanofluids by introducing SiO2 NPs into acrylamide polymer solution. They investigated the effect of the SiO2 NPs on the shear resistance and rheological behaviour at high temperature (85 °C) and high salinity condition (33,000 ppm). They observed that the shear viscosity of the PNF increases with addition of SiO2 NPs and they exhibited better shear resistance than the corresponding acrylamide solution. A summary of available works of application of nanoparticle for improved rheological properties of HPAM is summarised in Table 1. It is noteworthy that most experimental works of PNF's have focused on the use of SiO2 NP except for a few non-metals such as carbon (Lima et al., 2016), graphene (Nguyen et al., 2015), and nanoclay (Cheraghian and Khalilinezhad, 2015). Meanwhile, the efficiency of metal oxide NP remains obscure in literature. Cheraghian (2016) evaluated the application of TiO2 PNF and reported an improved oil recovery. Nevertheless, the results from the application of TiO2 PNF is not enough to validate the efficiency of metal oxide NP as additive for polymer flooding. This is because titanium metal inherent in the TiO2 NP is classified within transition metal group, whose elements exhibit variable oxidation states, thus, unstable. Al2O3 NP is a metal oxide NP and is known to exhibit excellent properties during their use as nanofluid (Mallakpour and Khadem, 2015). They possess high thermal conductivity and can dissipate heat

recover hydrocarbons from depleted reservoirs (Jang et al., 2015; Levitt and Pope, 2008; Wei et al., 2014). This is because of its high efficiency, technical and economic feasibilities and reasonable capital cost. Polymer flooding involves the injection of water-soluble polymer to aid recovery of bypassed and residual oil in the reservoir. The injected polymer improve the viscosity of injectant in the reservoir, thereby, resulting in an improved mobility ratio required to recover bypassed oil (Gbadamosi et al., 2019b; Kumar et al., 2016). Besides, polymer also improve macroscopic or sweep efficiencies through the mechanism of disproportionate permeability reduction (Olajire, 2014). On the other hand, residual oil in the reservoirs are recovered due to viscoelastic nature of the polymers which enables them to access the pore throats and constriction, thereby, displacing residual oil immobilised in cores (Gbadamosi et al., 2019a; Wang et al., 2001; Wei et al., 2014). Polymer flooding has maintained its increasing importance to the current energy market. The most notable contribution being the reported incremental oil production of up to 300,000 bbl/day from Daqing oilfield in China (Cheraghian and Hendraningrat, 2016). The most widely used polymer during field application of polymer floods is the partially hydrolysed polyacrylamide (HPAM) (Gbadamosi et al., 2018a; Halake et al., 2014; Pu et al., 2018). HPAM is preferred in EOR field applications because it can tolerate the high mechanical forces present during flooding of a reservoir, it is resistant to bacteria attack, has good water solubility, mobility control and it is a relatively low-cost polymer (Abidin et al., 2012; Emrani and Nasr-El-Din, 2017). Nonetheless, HPAM is very susceptible and sensitive to harsh reservoir conditions such as elevated temperature and brine salinity. Its viscosity enhancement property is significantly reduced when it dissolves in salinity or hardness brine and in the presence of shear forces. Moreover, polymer tends to hydrolyse at elevated temperature often encountered in reservoirs and its polymer molecule precipitates in the presence of reservoir hardness brine (Levitt and Pope, 2008). Hitherto, research for improvement of polymer flooding has focussed on the development of new polymers for EOR process. To this end, many approaches have been used for modification of the acrylamide monomer to develop salt and temperature tolerant acrylamide polymer for EOR. The most common method been the copolymerisation of acrylamide with suitable monomers that can increase stiffness and rigidity of the polymer chain. Some of the new polymers formed from the modification process were found to be effective in improving rheological properties and adjudged to have good EOR potentials. Nonetheless, the formulated polymers are deemed unsuitable due to economic reasons as they are expensive and will result in an increase of the overall cost of the polymer flooding process (Kamal et al., 2015). Recently, the use of nanotechnology has been courted and utilised as EOR agents due to their unique properties and availability in large quantities. Joonaki and Ghanaatian (2014) evaluated the use of aluminium oxide (Al2O3), iron oxide (Fe2O3) and silane treated silicon oxide nanoparticle (NP) as EOR agents in sandstone cores. Different concentrations of each NP were dispersed in propanol and their effect on interfacial tension (IFT), wettability, and oil recovery were measured. Results of the experiment indicated that Al2O3 and silane treated silicon oxide are good agents for EOR. Esfandyari Bayat et al. (2014)

Table 1 Previous rheological studies on polymeric nanofluids. Ref.

NP Type

Polymer Type

PNF Conc.

Brine Conc./Type

Core Flooding Temp.

Porous Media Type

Maghzi et al. (2011) Yousefvand and Jafari (2015) Cheraghian (2016) Rezaei et al. (2016) Khalilinezhad et al. (2016) Cheraghian (2016)

SiO2 SiO2 TiO2 MMT Clay SiO2 Nanoclay SiO2

HPAM HPAM HPAM HPAM HPAM HPAM

1,000 ppm 800 ppm 1,200–4,200 ppm 1,000 ppm 1,500 ppm 3,150 ppm

– 3 wt% NaCl 2 wt% (NaCl, CaCl2, MgCl2.6H2O, Na2HCO3) 10 wt% (NaCl, CaCl2, MgCl2) 2.0 wt% (NaCl, CaCl2, MgCl2.6H2O) 2.0 wt% (NaCl, CaCl2, Na2SO3, Na2HCO3, MgCl2.6H2O)

Ambient Ambient Ambient – – Ambient

Micromodel Micromodel Sandstone core Sandpack – Sandstone core

2

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efficiently from fluids through Brownian motion (Rafati et al., 2016). Hence, fluids containing Al2O3 NPs is less affected by temperature increase. Additionally, they retain their fluidic form and do not degrade in the presence of shear forces. The presence of oxygen atom on the surface of its NP means it can neutralize cations present in brines and withstand saline conditions (Maghzi et al., 2014). Furthermore, Al2O3 NPs have been shown to increase viscosity of water and other base fluids (Koca et al., 2018; Murshed and Estellé, 2017). Finally, they are low cost NP and environmentally friendly (Kedir et al., 2014; Kiruba et al., 2018). All the aforementioned properties of Al2O3 NP are desirable for improving rheological properties of polymers especially at shear rate, temperature, and salinity typical of reservoir condition. However, such study is elusive in literature. Furthermore, most of the previous researches of oil displacement by PNF's were carried out either in micromodel (Yousefvand and Jafari, 2015), glassbead pack (Abdullahi et al., 2018) or sandpack (Saha et al., 2018; Sharma et al., 2016). These porous media types are only symbolic and not synonymous with real reservoir core as they do not account for the reservoir heterogeneity of oilfield applications. Moreover, while the process of such porous media (micromodel, glassbead and sandpack) preparation is apt, researchers ignore the possibility of fluid movement via the sidewalls of these porous media types. Fines migration/fluid channelling via the walls do take place during their use for oil displacement test and are unaccounted for even though they have consequential effect on the flooding result. This work therefore seeks to extend the frontier of knowledge in PNF's application for oil recovery by exploring, exploiting and evaluating the application of Al2O3 NP additive in sandstone cores at typical reservoir condition. The influence of Al2O3 NPs on the rheological properties of HPAM at typical reservoir field conditions were evaluated and compared to those of well-researched SiO2 polymeric nanofluid and bare HPAM molecules. FTIR is used to understand the interaction between the NP and HPAM. Thereafter, the applicability and suitability of Al2O3 PNF for EOR was determined via oil displacement experiment in sandstone core which are representative of real reservoir cores. The mechanism of their higher EOR capabilities has been elucidated herein.

Table 3 Crude oil properties. Viscosity (cP)

Density (g/cm3)

SARA Property

Value (wt. %)

11

0.89

Volatiles Inorganics Saturates Aromatics Resins Asphaltenes

79.83 0.06 11.02 2.73 6.35 0.01

Table 3. 2.2. Preparation of brine solution Synthetic formation brines (SFB's) typical of reservoir formation brine was prepared with different concentration of NaCl. The electrolytes were prepared synthetically by diluting appropriate concentrations of salt in DIW. The prepared SFB is then filtered with filter paper to ensure that the solution is free of any particulate matter and that a uniform brine solution has been made. NaCl concentration range of 0.5–3.41 wt% was used for the rheological characterization test. 2.3. Preparation of polymer solution and polymeric nanofluids The polymer solutions were prepared following the API 63 standard “Practices for evaluation of polymers used in enhanced oil recovery operations” by adding calculated quantities of HPAM polymer directly to deionised water. Polymer concentrations were varied from 500 to 5,000 ppm to determine the critical concentration of the HPAM molecules. Subsequently, a fixed concentration of HPAM above the critical concentration was used for the rheological characterization. Two-step method was used for the preparation of polymeric nanofluids. Firstly, a predetermined quantity of NPs (0, 0.02, 0.03, 0.04, 0.05, 0.1, 0.2, 0.5 1.0 wt%) was dispersed in DIW and subsequently ultrasonicated for 30 min via ultrasonic bath (Crest Ultrasonics, USA) to form a stable and homogenised dispersion. Thereafter, HPAM powder was added into the respective aqueous dispersion of NPs and gently stirred for 24 h on a magnetic stirrer. Finally, the prepared sample was stored at room temperature for 1 week and neither showed visible macroscopic phase separation nor viscosity reduction. To investigate the effect of electrolyte concentration, SFB with varying composition (0.5–3.41 wt%) NaCl was added to the HPAM solution/hybrid suspension, followed by stirring for 24 h.

2. Experimental work 2.1. Materials HPAM (degree of hydrolysis (DOH) = 25 mol%, molecular weight 20 × 106 Dalton) was obtained from SNF Floerger, Paris was used to prepare the polymer solutions used in this study. Two readily available commercial NPs namely aluminium oxide NP (Al2O3, with 99% purity, size of 20 nm and specific surface area 230–400 m2/g), and silicon dioxide NP (SiO2, with 99.5% purity, size of 15–20 nm, specific surface area 170–200 m2/g) were purchased from Sky Spring Nanomaterial, Inc., Houston, TX, USA. Sodium chloride (NaCl) was purchased from Merck Group to make the electrolyte solutions. Table 2 itemise the list of materials used in this study. Deionised water (DIW) was used for mixing the polymers and preparation of stock solutions. All chemicals were of analytical reagent grade and were used as received without further modification or purification. Intermediate crude oil from one of Sarawak oilfield, Malaysia supplied by Petronas Carigali Sdn Bhd was used for the experiment. The properties of the crude oil are itemised in

2.4. Characterization of nanoparticle and nanopolymer Transmission electron microscope (TEM) was used to determine the microstructure of the NPs. To elucidate the differences in the morphologies and molecular structure of the HPAM and PNF's, Fourier Transform Infrared (FTIR) test within the scanning range of 500 to 4,000 cm−1 was analysed to evaluate the functional groups and interaction between NPs and HPAM. To measure the spectra of HPAM and NPs-HPAM suspensions, the Perkin-Elmer FTIR spectrometer 2000 was used. 2.5. Characterization of the sandstone core

Table 2 Properties of experimental materials. Materials

MW (g/mol)

ρ (g/cm3)

DOH

SSA (m2/g)

Particle size (nm)

HPAM Al2O3 SiO2 NaCl Crude Oil

20 × 106 101.96 60.08 58.44 –

1.02 – – 2.16 0.89

25% – – – –

– 230–400 170–200 –

– 20 15–20 – –

Sandstone cores characterised with medium range permeability were collected from an outcrop of sandstone formation in Sarawak Malaysia. They were used for wettability and oil displacement tests. The properties of the utilised cores for each experiment are listed in subsequent sections. Moreover, Rigaku X-ray diffraction (XRD) equipment was used to characterize and understand the mineralogical composition of the mid-permeability sandstone core. 3

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limitation of this technique, the measurement is repeated thrice until the acceptable margin of error was achieved.

2.6. Rheological measurement The rheological characterization of the polymer and PNF's are important to provide suitable insights into physical stability and flow behaviours against deformation. Thus, rheological experiments of HPAM and PNF's were analysed using a rheometer (Brookfield RST Coaxial Cylinder rheometer) equipped with temperature controller and water bath for high temperature conditions. The rheometer is characterised with a quick connect coupling for easy spindle attachment, and a measuring chamber to contain the sample and coaxial cylinder spindle for rheological evaluation. All rheological measurements of HPAM solution and PNF's were carried out under the shear range 1–250 s−1 and temperature range 27–90 °C and repeated thrice to ascertain reproducibility. Before any measurement was made, the rheometer setup for the experiment was calibrated by testing with standard oil and pure water at varying temperatures. Subsequently, the HPAM and PNF's samples were poured into the coaxial cylinder and measured. The uncertainty of the rheological experiment is that in the rheometer, shear rate is set, and the viscosity of the fluid is measured. Meanwhile, in the porous media, the shear rate is quite variable and dependent on both local geometry and the saturation of the oil obstructing flow of the aqueous solution.

2.8. Oil displacement test The enhancement of polymer flooding through the inducement of NPs was studied using reservoir sandstone core with setup depicted in Fig. 1. The coreflooding equipment used is a high temperature high pressure (HTHP) equipment manufactured by Fars EOR Technologies. The coreflooding equipment is dedicated for evaluating oil recovery for different injection fluids with a maximal pressure capacity of 6,000 psi, and temperature capacity of 150 °C. The apparatus is characterised with an oven for adjusting the temperature, four piston-like vessels for accommodating the injection fluids, and a core holder to enable the system to perform different injection scenarios. In this experiment, only three of the accumulators are utilised. The first accumulator was used to accommodate brine, while the second and third accumulators were used to retain crude oil and injected chemicals respectively. The crude oil has a viscosity of 11 mPas (at 25 °C), and 27 °API gravity. After the crude oil is filtered, it is stored in jars until it is loaded into the accumulator for injection, settling may change the composition of the crude that is injected into each experimental core. Oil is shaken both before filling the cylinder and prior to injection but some variance in injected oil must be expected. The core holder houses the cores used in the experiment. Three identical sandstone cores (C5 – C7) from the same outcrop of sandstone used for wettability test were used for the coreflooding experiment (see Table 3). Each core was cleaned after every use by rinsing it with toluene in a soxhlet extractor. Afterwards, the cleaned core is dried in an oven for 48 h at 100 °C. A series of core flooding tests were performed to evaluate the effect of NPs on flooding performance of oilfield HPAM. The system is pressurised to 2500 psi, supported with a backpressure of 100 psi. Also, the temperature of the oven is increased to 90 °C to simulate reservoir condition. The procedure for oil displacement tests includes air evacuation, initial saturation of the core with SFB (3.41 wt%), and then oil flooding until connate water saturation is reached (Esfandyari Bayat et al., 2014). An ISCO displacement pump was used for pumping the injectants from the accumulator through the core flooding system. Crude oil was injected at a flow rate of 0.5 mL/min. The system was then aged for 24 h to establish equilibrium and attain uniformity. Subsequently, water was injected at a flow rate of 0.5 mL/min until water breakthrough occurred. At 1.0 PV, water breakthrough was recorded. Afterwards, 0.5 PV slug containing 0.1 wt% of chemical (HPAM/NPs-HPAM) was injected to recover bypassed and residual oil. This was followed by injection of 1.0 PV of chase water to evaluate the total oil recovery. Each chemical flooding experiment was repeated thrice, and the average value was reported.

2.7. Wettability experiment Wettability alteration is conducted to understand the influence of the nanoparticle additive in the polymer solution on capillary forces of trapped residual oil. Contact angle measurement is a proven method for evaluating wettability alteration in porous medium and is used in this study (Mohammed and Babadagli, 2015). Sandstone core plugs C1 – C4 with properties listed in Table 4 were used to conduct the wettability test. The cores are gotten from outcrop of sandstone sourced from Sarawak, Malaysia. Firstly, the outcrop is trimmed using a trimming machine, and the extracted cores were polished and saturated by water. Afterwards, the cores were solvent cleaned with toluene and methanol to remove contaminants from the core plugs. Thereafter, an oil-wet state of the cores was established by inducing the core plugs with dead oil for 30 days. Afterwards, the cores were removed and dried at room temperature. The aged cores were used to conduct wettability test as the baseline. To evaluate wettability alteration of the cores under static conditions, each oil-wet core was submerged in samples of HPAM, SiO2–HPAM, and Al2O3–HPAM with concentration of 0.1 wt%. The rock sample in each solution was constantly stirred at 500 rpm for 48 h at 90 °C (Llanos et al., 2018). Finally, the cores were washed with deionised water and dried in an oven at 40 °C for 24 h. A qualitative assessment of the wettability alteration was established by estimating the water contact angle of the treated cores using a DataPhysics optical contact angle (OCA) instrument with a drop shape analyser. This is conducted by placing a drop of water onto the surface of the dried cored and then estimating the contact angle of the liquid/air/rock system (Giraldo et al., 2013). The OCA instrument analyses the images of the water contact angle with the aid of an inbuilt camera and software at room temperature. Though the use of porous rocks is more realistic as compared to mineral plates, the uncertainty of contact angle measurement on core sample is that issues such as surface heterogeneity may interfere with the accuracy of the measurement. To reduce the

3. Results and discussion 3.1. Characterization of nanoparticle and polymeric nanofluid Fig. 2 captures the TEM micrograph of SiO2 and Al2O3 NPs used for the experiment. It is observed that the SiO2 NP appeared circular/ spherical in shape. Meanwhile, Al2O3 NP showed an irregular shape due to the hexagonal and octahedral site inherent in the crystal structure of the alumina. FTIR spectrophotometry was used for the characterization of the samples and the obtained spectra and vibration assignment are depicted in Figs. 3 and 4. Fig. 3 depict the FTIR spectrometric characterization of SiO2, HPAM, and SiO2-HPAM with absorption band in the wavelength range of 500 cm−1 to 4000 cm−1. Two clear peaks at 1080 cm−1 and 800 cm−1 corresponding to Si–O–Si asymmetric stretching, and Si–O–Si bending vibration respectively were observed for the pure SiO2 NP. For HPAM sample, a peak of X–H stretch region at 3400 cm−1 (where X = N or O) was observed in the range of 3150–3700 cm−1. The broad

Table 4 Properties of the sandstone core. Cores

C1

C2

C3

C4

C5

C6

C7

Average diameter (cm) Average length (cm) Porosity Permeability (mD)

3.7 4.5 15.20 168.2

3.7 4.6 15.12 166.1

3.7 4.4 15.17 165.8

3.7 4.4 15.15 167.3

3.7 9.6 15.31 165.6

3.7 9.7 15.25 167.4

3.7 9.8 15.28 169.1

4

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Fig. 1. EOR coreflooding setup.

C–H deformation bonds respectively. For hybrid suspension of SiO2–HPAM sample, two peaks were recorded at 1098 cm−1 and 792 cm−1 corresponding to asymmetric stretching and flexural vibrations of Si–O–Si group. Moreover, a clear peak was detected at 962 cm−1 indicating Si–OH bending vibration, introduced by the

envelope indicates the presence of hydrogen bonding dominated by the O–H group (Joonaki et al., 2018). Besides, a band of C–H symmetric stretching vibration was recorded at 2980 cm−1. Meanwhile, clear peaks at 1650 cm−1, 1580 cm−1, and 1390 cm−1 are indicative of weak bands characteristic of C]O bond, C–C bond in aromatic moieties and

Fig. 2. TEM images of (a) SiO2 nanoparticles, (b) Al2O3 nanoparticles. 5

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Fig. 3. FTIR spectra for 0.1 wt% SiO2/0.2 wt% HPAM hybrid dispersion.

SiO⋯HNH–CO – C). Finally, a peak in the range of 3100–3750 cm−1 was observed which corresponds to vibration of the NH, Si–OH, –OH group. Therefore, the possible intermolecular interaction between the HPAM and SiO2 NP has led formation of a strong SiO2–HPAM hybrid dispersion (Hu et al., 2017). Fig. 4 shows FTIR spectroscopic analysis carried out to evaluate the

hydroxyl group on the SiO2 surface. Subsequently, peaks of 1350, 1500, and 1650 cm−1 representing vibrations of Si–O, Si–NH2, and –NH2 respectively were noted. The –OH groups from the SiO2 surface reacts with –NH2, –CHO, and –COOH groups on the HPAM surface to form strong hydrogen bridges, hence, resulting in hydrolysable covalent crosslinks of SiO2 and HPAM (SiO–H⋯ N–H or SiO–H ⋯O–CNH2 or

Fig. 4. FTIR spectra for 0.1 wt% Al2O3/0.2 wt% HPAM hybrid dispersion. 6

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Fig. 5. XRD spectra of sandstone core.

chain molecules occurs due to their anionic nature, which causes them to repulse, intertwine and entangle with each other under static or near static conditions (Chul et al., 2012; Lam et al., 2015). Nonetheless, due to incessant Brownian motion, sliding motion of the molecules of the polymer over each other occur, causing formation and dissociation from entanglements as they move. The resistance to flow due to entanglements is high, hence, viscosity is highest at low shear conditions. Meanwhile, as shear increases, more polymeric chains orient in the direction of flow causing a reduction in the number of entanglements (Lam et al., 2015). Hence, the pseudoplastic behaviour depicted on the viscosity-shear rate plot. The relationship of viscosity and shear rate was fitted using Ostwald-de Waele (or power-law) model (see Equation (1)) and the parameters obtained are summarised in Table 5. As HPAM concentration increases, the flow consistency index (“K”) increases, demonstrating an increase in viscosity of the fluids while the flow behaviour (“n”) decreases, indicating the fluids exhibit more shear thinning behaviour.

structure of Al2O3 and HPAM, and morphological interaction between hybrid sample of Al2O3–HPAM. For pure Al2O3 sample, peaks were detected at 594, 642, and 682 cm−1 representing Al–O stretching in the octahedral structure. Besides, an absorption peak was captured at 3400 cm−1, belonging to the stretching vibration of –OH bond. For hybrid of Al2O3–HPAM, two peaks appeared at 718 cm−1 and 1122 cm−1 corresponding to Al–O stretching in the tetrahedral structure and symmetric bending vibration of Al–O–H by the –OH group on the alumina surface. Furthermore, an absorption peak appeared at 1652 cm−1 denoting stretching vibration of carboxyl group in the acrylamide polymer. Strong hydrogen bonding occurs between –OH group on the surface of Al2O3 and the oxygen/nitrogen of amide groups present in HPAM (AlO–H⋯N–H or AlO–H⋯O–CHNH2). Additionally, hydrogen bond is formed between hydrogen group in HPAM and oxygen group on Al2O3 (AlO⋯HNH–CO – C) surface leading to the existence of strong hydrolysable crosslinks of Al2O3–HPAM. 3.2. XRD analysis of the sandstone core

μ = K . γ˙ (n − 1)

The XRD analysis of the sandstone used for the experiments was investigated and shown in Fig. 5. The spectra affirm the sandstone mineral composition as quartz (80.2%), feldspar (18.7.7%), and illite (1.1%).

(1)

where μ = viscosity, γ˙ = shear rate, K = flow consistency index and n = flow behaviour index. Fig. 7 depict the critical concentration of the HPAM solution. Below the critical concentration, there are fewer molecules of polymer in solution, hence, intramolecular association within the polymer molecules control the polymer rheology, thus resulting in smaller viscosity. Above the critical concentration, entanglements of polymer chain arise due to more molecules of HPAM in solution. Ion-dipole interaction and strong hydrogen bonding is formed due to the attraction between highly-polar dissociated carboxylate group (–COO–) of HPAM and water molecules. Additionally, the hydrogen atoms present in the polymeric amide groups (–CONH2) forms hydrogen bonds with water molecules (Lam and Jefferis, 2017). Consequently, intermolecular association between the polymer chains control the polymer rheology, thereby, resulting in an increase of the polymer viscosity. Thus, 2,000 ppm, a concentration

3.3. Rheological behaviour of HPAM at varying concentration Fig. 6 show the rheological behaviour of HPAM concentrations at 27 °C under different shear rate on a log-log scale. The rheogram shows that HPAM solution exhibit a non-Newtonian behaviour. The viscosity of HPAM solution decreases as the shear rate increases, hence, demonstrating a pseudoplastic behaviour at medium to high shear rates. Furthermore, the viscosity of the polymer solution increases with increase in polymer concentration both at low, medium and higher shear rate considered. At low shear rate, uncoiling and aligning of the long7

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Fig. 6. Viscosity of HPAM versus shear rate (T = 27 °C).

above critical concentration (determined from the turning point of the bilinear curve) was chosen for subsequent analysis of the HPAM solution behaviour.

Table 5 Summary of power law model parameters for HPAM polymer fluid. Polymer concentration (ppm)

Flow consistency index (K) (mPa·s)

Flow behaviour index (n) (−)

500 1,000 2,000 3,000 4,000 5,000

195.42 451.25 843.56 1,461.3 1,802.7 2848.4

0.412 0.396 0.383 0.377 0.364 0.352

3.4. Rheological behaviour of HPAM solution in different electrolyte concentrations The effect of different concentrations of NaCl on the viscosity of HPAM (2,000 ppm) solution were studied and presented in Fig. 8. HPAM solution is sensitive to brine and obviously its solution viscosity decreases monotonically as the concentration of electrolyte increases. This is because HPAM is a polyelectrolyte. Addition of salt cations (e.g., Na+) effectively screens the negative carbonyl groups on the backbone

Fig. 7. Effect of HPAM concentration on viscosity (T = 27 °C, shear rate = 10 s−1). 8

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Fig. 8. Effect of NaCl concentration on rheology of HPAM (T = 27 °C).

Fig. 9. Effect of salinity on the hydrodynamic size of polymer molecule (Lam and Jefferis, 2017).

thereby, resulting in viscosity reduction of the polymers which in turn impacts their mobility ratio in the reservoir negatively. Fig. 10 illustrates the effect of temperature on the rheology of HPAM (2,000 ppm) solution and revealed that the viscosity of HPAM solution is strongly dependent on the temperature condition in the reservoir. The viscosity of the HPAM solution showed a decreasing trend as the temperature of the system is increased at low, medium and high shear rates. This is because as the temperature increases, the thermal motion of the polymer molecules increases. Consequently, a higher mobility of the HPAM chains occurs, resulting in the impairment of the intermolecular interaction of its hydrophobic group. Hence, the polymer chain entanglements, hydrodynamic volume and viscosity of the HPAM polymer decreases (Chul et al., 2012).

of the HPAM solution to reduce the electrostatic repulsion of the polymer chain (Lam and Jefferis, 2017). Hence, the polymer hydrodynamic size changes in conformation from a stretched state to a shrinkable state as illustrated in Fig. 9. Consequently, the hydraulic radius of the polymer chain and the degree of polymer chain entanglement decreases, thereby, resulting in reduction of the HPAM solution viscosity (Chul et al., 2012). Jefferis and Lam (2013) also observed reduction of viscosity of HPAM in the presence of salt. Furthermore, it can be observed that viscosity difference after 3 wt% salinity is infinitesimal. In this work, 3.41 wt% NaCl was found to be the critical salinity threshold above which viscosity reduction by the NaCl is insignificant. This is in agreement with previous study by Levitt and Pope (2008). The implication of the viscosity reduction by the electrolyte is that the HPAM used as injectant during the oil recovery process will not be able to meet the targeted viscosity requirement for adequate mobility ratio in the reservoir, hence, they become inefficient.

3.6. Effect of Al2O3 NP loading on the viscosity of HPAM The influence of different concentrations of Al2O3 NP on the viscosity of HPAM at typical reservoir shear rate of 10 s−1 was investigated and depicted in Fig. 11. Nine Al2O3-HPAM hybrid dispersions were prepared with different Al2O3 concentrations ranging from 0.01 to

3.5. Rheology of HPAM at varying temperature conditions Generally, polymers thermally degrade at higher temperatures, 9

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Fig. 10. Effect of temperature on rheology of HPAM.

nanoclay and nano-SiO2 on HPAM (2,000 ppm) solution.

1.0 wt% in 2,000 ppm HPAM solution at ambient temperature. The effect of Al2O3 NP on the HPAM viscosity showed a non-monotonic trend. At first, the viscosity of the hybrid dispersion of Al2O3 PNF increased as the concentration of NP increases until it reaches 0.1 wt%, and thereafter decreases for the remaining concentration studied. Hence, 0.1 wt% Al2O3 is considered as the critical nanoparticle concentration (CNC) for this study. Above 0.1 wt% Al2O3, it was observed that Al2O3 NP was not fully dispersed in the HPAM solution, thereby, forming aggregates. Formation of aggregate diminish the functionality of the NP in the polymer solution (Gbadamosi et al., 2018a). This may partly explain the decrease in viscosity of the hybrid dispersion above the CNC. Rezaei et al. (2016) and Maghzi et al. (2013) also reported an optimum NP concentration of 0.1 wt% in their studies of the effect of

3.7. Effect of NP type on rheological properties of HPAM solution Fig. 12 depict the effect of NP (SiO2 and Al2O3) on rheology of HPAM at ambient temperature and in the absence of hardness brine. At optimum NP concentration of 0.1 wt%, viscosity of PNF were higher than that of HPAM solution at low, medium and high shear rates. Besides, both PNF's and HPAM molecules exhibited shear thinning behaviours. The higher viscosity of PNF is attributable to the high surface area of NP in the hybrid dispersions which increases their functionality and bonding with the HPAM solution. Formation of covalent linkages and strong electrostatic hydrogen bond is facilitated by the interaction

Fig. 11. Effect of Al2O3 NP on the viscosity of HPAM (T = 27 °C; shear rate = 10 s−1). 10

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Fig. 12. Effect of NP types on rheology of 0.2 wt% HPAM (at CNC = 0.1 wt%).

Al2O3 PNF had 31% higher viscosity than HPAM while SiO2 PNF viscosity increased by 15%. The decrease in the viscosity of PNF's at high temperature is a resultant effect of the decrease in the adsorption of the polymer on the NPs surface (Wiśniewska et al., 2016). At high temperature, dehydroxylation of the hydrogen bonded silanol groups and aluminol group occurs, hence, inducing a hydrophobic character. Consequently, this decreases the affinity of the acrylamide polymer towards the surface of the NPs, hence, decrease in adsorption (Wiśniewska, 2012). Ultimately, the hydrogen bonds formed between the NPs and the polymer molecule becomes weak, leading to the weakening of the network structure formed by the PNF's and resulting in a decrease in viscosity. Nevertheless, the presence of NPs minimized thermal degradation of the polymer molecules. Al2O3 PNF had a higher viscosity because of the metallic ability of its inherent constituent to conduct heat. Besides, at the high temperature, an extended and stretched conformation of the polymer macromolecules occur, leading to the hydrolysis of HPAM and forming carboxylate (COO−) groups. Adsorption of HPAM polymer on the surface of Al2O3 proceed due to slight electrostatic interaction between the oppositely charged surface (Al3+ and COO−) as compared to SiO2 surface characterised by negative charge with depletion interaction (Wiśniewska, 2012; Wiśniewska et al., 2016).

between the silanol and aluminol functional group of the NPs and the amide group of the HPAM. Consequently, adsorption interaction of the macromolecules on the surface of the NPs occurs, with the NPs acting as a physical crosslinker between different polymeric chain. The adsorption reaction is irreversible, hence, three-dimensional network of stable flocs is developed with resultant increase in the viscosity of the suspension (Maurya and Mandal, 2016). Though the bridges between the NPs and the HPAM molecules cannot be broken, they are progressively weakened in shear fields, hence, the shear thinning behaviour. Amongst the PNF, Al2O3 PNF exhibited a higher viscosity than those SiO2 PNF and HPAM molecules under all shear rates. This is due to higher mechanical resistance of the Al2O3 PNF which lowers the effect of the shear forces.

3.8. Effect of NP types on thermal degradation of HPAM The viscosity of SiO2 PNF, Al2O3 PNF, and HPAM solution at different temperatures were measured at typical reservoir shear rate of 10 s−1 and illustrated in Fig. 13. As the temperature of the system increases from 25 °C to 90 °C, the viscosity of HPAM and PNF's reduces, depicting that the viscosity of both systems is dependent on temperature. This is consistent with literature which depicts water soluble polymers as being susceptible to temperature increment (Lai et al., 2016a, 2016b). When heat is applied, chemical and physical changes occurs in the polymer moieties leading to significant changes in properties of the polymer. The increasing system temperature reduces the attractive binding energy between polymer molecules, hence, resulting in a decrease of the intermolecular forces between the polar group of the polymer structure and ultimately a decrease in the viscosity of the polymer. Nonetheless, Fig. 13 shows that the hybrid dispersions containing NPs displayed a higher viscosity than HPAM solution at ambient and higher temperatures. At ambient temperature, Al2O3 PNF had 51% higher viscosities than HPAM while SiO2 PNF had a 20.5% increment. This is because of the existence of micelle type three-dimensional flocs resulting from the adsorption of the polymeric chain on the surface of the NPs. Similarly, at the highest temperature observed in this study (90 °C).

3.9. Effect of NP types on HPAM solution viscosity in different electrolyte concentration Cations of brine present in reservoir significantly reduce the viscosity of HPAM aqueous solutions in reservoir due to their charge shielding effects (Kamal et al., 2015). A comparative analysis of the salt tolerance of the hybrids of PNF's and aqueous HPAM solution were investigated and presented in Fig. 14. The viscosity behaviour of Al2O3 PNF, SiO2 PNF, and HPAM were examined in different electrolyte concentrations of 0.5–3.41 wt% NaCl (representative of typical low to high salinity field injected brines) and high shear rates. As the NaCl concentration increases, the viscosity of both PNF's and HPAM aqueous solution decreases. However, Al2O3 PNF displayed a higher viscosity than those of SiO2 PNF and HPAM solution. At 0.5 wt% brine 11

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Fig. 13. Effect of NP types on viscosity of HPAM at varying temperature (at CNC = 0.1 wt%; no electrolytes).

bridging induced flocculation of particle and HPAM is promoting an increase in the viscosity of the suspension. On the other hand, the neutralization of the negative charge of the polymer by the cations of the brine is decreasing the viscosity. But since optimum concentration of the NP is used, some polymeric chains are adsorbed on the NPs surface, hence, the effect of the salt on the PNF's is low compared to HPAM. Even under varying temperature conditions depicted in Fig. 15, the viscosity of Al2O3 PNF remains remarkably greater than those of SiO2 PNF. This is attributable to the stronger adsorption between the Al2O3 NP and the polymer macromolecule as compared to the repulsion

concentration, Al2O3 PNF had 37.5% higher viscosity while SiO2 PNF had a 17.5% higher viscosity than conventional HPAM. Likewise, at 3.41 wt% NaCl concentration, the viscosity of Al2O3 PNF was 29.4% higher while SiO2 PNF viscosity was 11.76% higher than those of aqueous HPAM solution. HPAM has the lowest viscosity because the cations of the brine attacks the amide and carboxylate group of its molecules, which diminishes the electrostatic repulsion within the polymer chains (Chul et al., 2012). As compared to HPAM, the interaction of the electrolyte concentration and the PNF's generate an interplay of forces. Firstly, the

Fig. 14. Effect of NP types on viscosity of HPAM in different electrolyte concentration (at CNC = 0.1 wt%; T = 27 °C; shear rate = 500 to 1000 s−1). 12

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Fig. 15. Viscosity versus temperature plot of the effect of NP types on HPAM (NaCl conc. = 3.41 wt%; CNC = 0.1 wt%; shear rate = 500 to 1000 s−1).

Fig. 16. a) Attack on carbonyl group of HPAM by Na+, (b) shielding effect of NP on HPAM in the presence of Na+.

between the COO− and the SiO2 NP surface. The mechanism of improved HPAM performance due to the presence of NPs is depicted in Fig. 16. In the absence of NP, electrostatic attraction between Na+ present in the brine and oxygen atom on the surface of the anionic polyelectrolyte occurs which weakens the carbonyl group on the backbone of the polymer molecule. Consequently, the polymer shrinks, loses its viscosity and becomes rapidly degraded. On the other hand, in the presence of NPs, an ion-dipole interaction is generated between the oxygen atom present on the surface of the NPs and the Na+ cations, thereby, shielding the polymer molecules. Additionally, the presence of strong hydrogen bond facilitated by crosslinks between the NP and HPAM causes an interplay which shields the polymer to minimize degradation. Despite the increment in temperature conditions, Al2O3 PNF had higher viscosities than those of SiO2

PNF due to the higher thermal conductivity of its metallic oxide constituent. Besides, even though the hydrogen bonding interaction is weakened, adsorption interaction of the Al3+ of the Al2O3 and COO− group of the polymer proceed to inhibit the degradation of the Al2O3 PNF. 3.10. Wettability alteration Contact angle measurements were carried out on sandstone cores to study the effect of the each injectant during the oil recovery process (Joonaki et al., 2016). The water contact angle was utilised to depict the advancing contact angle (CA) and receding contact angle (CR) result for each experiment. As shown in Fig. 17a, the contact angle of the aged oil-wet surface is 111.8°, indicating the surface is in an oil-wet state. On 13

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Fig. 17. Advancing and receding contact angle of (a) Oil-wet surface, (b) Oil-wet surface treated with HPAM, (c) Oil-wet surface treated with SiO2-HPAM, (d) Oil-wet surface treated with Al2O3-HPAM, (e) graphical representation of contact angle measurements.

comparison, parameters such as salinity, temperature, pressure, flow rate and pore volume injected remain the same for all flooding processes. The cumulative oil recovery versus injected pore volume for waterflooding, HPAM flooding, SiO2–HPAM, and Al2O3–HPAM, and the pressure drop through the sandstone core versus the pore volume of injected fluid are depicted in Figs. 18 and 19 respectively. Oil recovery by waterflooding process yielded 30.2% of the original oil in place (OOIP). After water breakthrough, polymer flooding and PNF's flooding processes were conducted. Each experiment was conducted three times. Al2O3–HPAM demonstrated the highest oil recovery process in comparison to the other flooding processes. For HPAM flooding, oil recovery from the sandstone core was 56.5% OOIP. The recovery increased to 63.2% OOIP and 67.8% OOIP for SiO2–HPAM and Al2O3–HPAM respectively. For all tests, the pressure drop during water flooding remained low and ranges between 5 and 15 Psi. However, the pressure drop increased to 35.3, 40.2, and 45.7 Psi during HPAM, SiO2–HPAM and Al2O3–HPAM flood respectively. As compared to HPAM, the occurrence of high pressure drops for PNF's is due to their higher viscosity. The higher oil recovery of PNF's over the polymer flooding process is due to the presence of the nanoparticles which weakens the mobility

treating the surface with HPAM, the contact angle of the surface decreased to 55.7°, which shows the polymer molecules have altered wettability of the surface to water-wet. Polymer alters wettability of the surface through mechanisms of pulling effect and stripping effect (Wei et al., 2014). Furthermore, treating surface of the oil-wet cores with SiO2–HPAM, and Al2O3–HPAM further alters the wettability of the porous media to a more water-wet state. Contact angle of the sandstone core decreased further to 31.0° and 25.1° when treated with SiO2–HPAM, and Al2O3–HPAM respectively. This is attributable to the irreversible adsorption of the inherent nanoparticle of the suspensions to the rock surface (Moghadam and Mahsa, 2018; Nikolov et al., 2019). Giraldo et al. (2013), also reported that the use of Al2O3 based nanofluids significantly alters wettability of sandstone cores to strongly water-wet condition.

3.11. Oil displacement experiment To determine the suitability and performance of Al2O3 PNF as an EOR agent, oil displacement experiment was conducted in a sandstone core at typical reservoir conditions. The core flooding experiment was repeated for SiO2 PNF and aqueous HPAM solution. For suitable 14

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Fig. 18. Oil recovery versus injected pore volume.

Fig. 19. Pressure drop versus pore volume of fluid.

4. Conclusion

of the polymer molecules in the sandstone core due to its higher rheology. Besides, the ability of nanoparticle to inhibit degradation of macromolecular chain of HPAM molecules in the presence of prevailing temperature and salinity also improves it efficiency. Al2O3 PNF exhibited the highest efficiency due to its exemplary rheological and wettability alteration behaviour at the prevailing conditions. The altering of the wettability of the sandstone core from oil-wet to water-wet ensured entrained oil are easily recovered by the injectant. Overall, mobility ratio was improved, viscous fingering was eradicated, leading to conformance efficiency of its injectant in the reservoir and an enhancement of the swept volume.

In this study, we explored the suitability of Al2O3 NP as an additive for improving the rheological and oil displacement properties of partially hydrolysed polyacrylamide solution. Wettability alteration effect of the injectant was also studied. The addition of Al2O3 nanoparticles at CNC of 0.1 wt% on rheological properties of HPAM solution at critical concentration of 2,000 ppm was tested. The results obtained were compared with polymeric nanofluid formulated with well-established and renowned industry standard SiO2 NP, and base HPAM sample without nanoparticles. Overall, the use of NP as an additive for HPAM inhibited thermal degradation and lowered chemical degradation of the aqueous polymer molecules due to their shielding effects. More 15

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importantly, Al2O3 PNF exhibited sterling and fascinating properties than SiO2 PNF and individual HPAM solution for both rheological and oil displacement experiments due to their exceptional physiochemical properties and good thermal conductivity. Moreover, the Al2O3 PNF altered the wettability of oil-wet surface to water-wet, hence, reducing capillary force of trapped residual oil. Finally, 0.1 wt% of Al2O3 PNF showed better efficiency at recovering oil from sandstone core at typical reservoir conditions. Hence, the use of Al2O3 polymeric nanofluid is hereby proffered for EOR activities especially in harsh environments.

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Acknowledgement The authors would like to thank the Ministry of Higher Education, Malaysia, and Universiti Teknologi Malaysia for supporting this research through Research Management Grant Vot. No. Q.J30000.2546.14H50 and R.J130000.7846.4F946. Nomenclature DIW API HPAM NaCl NP SFB SSA ID Soi Swc φ ρ K SiO2 Al2O3 PNF MMT RPM DOH

Deionised water American Petroleum Institute Hydrolysed polyacrylamide Sodium chloride Nanoparticle Synthetic formation brine Specific surface area Internal diameter Initial oil saturation Connate water saturation Porosity Density Permeability Silica Aluminium oxide Polymeric nanofluid Montmorillonite Revolution per minute Degree of hydrolysis

Appendix A. Supplementary data Supplementary data to this article can be found online at https:// doi.org/10.1016/j.petrol.2019.106345. References Abbas, A.H., Sulaiman, W.R.W., Jaafar, M.Z., Gbadamosi, A.O., Ebrahimi, S.S., Elrufai, A., 2018. Numerical study for continuous surfactant flooding considering adsorption in heterogeneous reservoir. J. King Saud Univ. Eng. Sci. 1–9. https://doi.org/10.1016/j. jksues.2018.06.001. Abdullahi, M.B., Rajaei, K., Junin, R., Bayat, A.E., 2018. Appraising the impact of metaloxide nanoparticles on rheological properties of HPAM in different electrolyte solutions for enhanced oil recovery. J. Pet. Sci. Eng. 1–15. https://doi.org/10.1016/j. petrol.2018.09.013. Abidin, A.Z., Puspasari, T., Nugroho, W.A., 2012. Polymers for enhanced oil recovery technology. Procedia Chem. 4, 11–16. https://doi.org/10.1016/j.proche.2012.06. 002. Agi, A., Junin, R., Syamsul, M.F., Chong, A.S., Gbadamosi, A., 2018. Intermittent and short duration ultrasound in a simulated porous medium. Petroleum 1–12. https:// doi.org/10.1016/j.petlm.2018.03.012. AlamiNia, H., Khalilinezhad, S.S., 2017. Application of hydrophilic silica nanoparticles in chemical enhanced heavy oil recovery processes. Energy Sources, Part A Recover. Util. Environ. Eff 1–10. https://doi.org/10.1080/15567036.2017.1299257. Almahfood, M., Bai, B., 2018. The synergistic effects of nanoparticle-surfactant nanofluids in EOR applications. J. Pet. Sci. Eng. 171, 196–210. https://doi.org/10.1016/j.petrol. 2018.07.030. Alvarado, V., Manrique, E., 2010. Enhanced oil recovery: an update review. Energies 3, 1529–1575. https://doi.org/10.3390/en3091529. Babamahmoudi, S., Riahi, S., 2018. Application of nano particle for enhancement of foam stability in the presence of crude oil: experimental investigation. J. Mol. Liq. 264, 499–509. https://doi.org/10.1016/j.molliq.2018.04.093.

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