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Newly Prepared Nano Gamma Alumina and Its Application in Enhanced Oil Recovery: an Approach to Low Salinity Waterflooding Sajad Kiani, Mostafa Mansouri Zadeh, Saeed Khodabakhshi, Alimorad Rashidi, and Jamshid Moghadasi Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.5b03008 • Publication Date (Web): 09 Apr 2016 Downloaded from http://pubs.acs.org on April 9, 2016

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Newly Prepared Nano Gamma Alumina and Its Application in Enhanced Oil Recovery: an Approach to Low Salinity Waterflooding Sajad Kiani †, Mostafa Mansouri Zadeh ‡, Saeed Khodabakhshi §, Alimorad Rashidi *†, Jamshid Moghadasi ∥ †

Nanotechnology Research Center, Research Institute of Petroleum Industry (RIPI), P.O. Box

14665-1998, Tehran, Iran ‡

Department of Petroleum Engineering, Islamic Azad University, Omidieh Branch, Omidieh,

Iran §

Department of Chemistry, Robatkarim Branch, Islamic Azad University, Robatkarim, Iran

∥

Department of Petroleum Engineering, Petroleum University of Technology, Ahwaz, Iran

KEYWORDS. Nano gamma alumina; Enhanced oil recovery; Nanofluid; Low salinity

ABSTRACT. Nano gamma alumina (NGA) was prepared via a simple synthetic route and used for the preparation of a nanofluid in various salinity on the water-wet sandstone core samples. A new waterflooding experiment on sandstone rock for enhanced oil recovery (EOR) has been used by taking into account at different water salinities. In this paper, the impressiveness of a new EOR process in the presence of alumina-based nanofluids to alter the dynamic adsorption of 1


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sandstone core sample in low salinity and high salinity brine injection has been experimentally studied. The nanofluids with suitable concentration of NGA particles and salinities in ranging from 2000 ppm to 200000 ppm and 25-80 oC were prepared. The results showed a reduced adsorption by the use of nanoparticles at low salinity conditions. The ultimately optimum recoveries for 2000, 20000, and 200000 ppm of nanofluids injection were obtained as 56.95%, 64.78%, and 71.48%, respectively. It was found that these oil recoveries depend strongly on the concentration of salinities and were increased with decreasing salinity loading. Therefore, the dynamic adsorption behavior of nanofluids results shows a key role in clay migration in oil displacement.

1. INTRODUCTION EOR processes includes using various techniques to increase the amount of crude oil is prone to be extracted from oil fields. Because of some current issues against petroleum industry such as non-productive primary and secondary recovery, high crude oil price, increasing energy demand, the use of EOR technology is actually essential. It is well known that waterflooding is a widely used method for the enhanced oil recovery (EOR). By waterflooding, about 50-70% oil in the formation remains and it cannot be removed without using next chemical, thermal or gas injection processes.1 Wetting properties of the rock plays an important role in the ability of water flooding to increase the oil recovery. With considering to sand surface adsorption for EOR process, the low salinity waterflooding is also of importance to achieve this target.2 The EOR achievement by remarkable lowering the injection brine salinity or modification of the brine composition of the injection water has been reported in several experimental studies and field 2


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trials for both tertiary (residual oil condition) and secondary (initial water condition) modes of waterflooding.3-7 In this regard, the injection of water with low salinity has been experimentally investigated and some reasonable mechanisms concerning low salinity waterflooding have been suggested in the literature.8-10 A large number of chemical analyses were carried out on the effluent to know the extent of interaction between the injected brine, the oil and the rock matrix. Based on many experiments, it was found that the presence of connate water and the claycontaining mixed-wet porous media are essential conditions for the low salinity effect (LSE).1, 1114

In the next studies, as reasons for the LSE, other mechanisms have been also proposed by

several research groups. Some key factors in sandstone often determine the mechanisms that include: (1) release and migration of mixed-wet clay fines resulted from wettability alteration toward a more water-wet state,15-18 (2) mineral dissolution and ion-exchange reactions which lead to increase the pH and subsequently reduce interfacial tension (IFT),12, 19 and (3) multicomponent ionic exchange (MIE)20 between adsorbed crude oil components, connate brine, and clay particles.21 Synthetically, there are some physical (mechanical milling,22 flame spray,23 thermal plasma decomposition,24 and laser ablation) and chemical (sol–gel,25, 26 hydrothermal method,27 precipitation,28 combustion synthesis,29 and spray pyrolysis 30) for the preparation of nano gamma alumina (NGA) particles. However, some of the reported methods suffer from drawbacks such as inability to control the size of nanoparticles especially in mechanical milling method, high cost, expensive equipments, and low product yield. Some recent and relevant studies include the effect of nanomaterials in EOR operations.31-34 one of them describes the application of NGA-based fluids as wettability modifiers.35

3


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As far as we are aware, there is no report on the application of NGA as a suitable agent in increased oil recovery. In this research project, we aimed to synthesize NGA via a one-pot method and control of its textural properties such as surface area, pore volume, pore size, morphology, particle size, and thermal stability. Successively, as a new application, we used asprepared NGA particles in different saline medium onto Berea sandstone core plug. The effect of NGA particles-based fluids on clay migration was carefully investigated to alter the recovery factor in different salinity in ranging from 2000 to 200000 ppm on sandstone cores, differential pressure, and dynamic adsorption tests at different temperature.

2. EXPERIMENTAL 2.1. Materials and methods All chemicals were purchased from Merck and Aldrich. The pore size and surface area measurements were performed with a Micrometrics ASAP-2010 instrument by adsorption of nitrogen at 77K. IR spectra were recorded on a FT-IR JASCO-680. Scanning electron microscopy (SEM) studies of the nanostructures were carried out with a JEOL JEM 3010 instrument operating at an accelerating voltage of 300 kV. X-Ray diffraction (XRD, D8, Advance, Bruker, AXS) patterns were obtained for characterization of the heterogeneous catalyst. 2.2. General procedure for preparation of NGA particles High-purity Gibbsite (99.99%)-to-ammonium bicarbonate weight ratio is about 25-45%, and deionized water (3-5 mL) were mixed and placed in a 300 mL Teflon-lined autoclave at 754


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85 °C for 10 h. The mixture was cooled under stirring at room temperature about 30 min. Finally, the as-prepared mixture was calcinated at 450 °C for 60 min to produce NGA particles under thermal decomposition conditions.36

2.3. Preparation of Brines. Table 1 indicates the synthetic brine that was used for saturating core plugs in tertiary mode. The brine concentrations were prepared by dissolving in water with total dissolved solids (TDS) nearby 2000, 20000, and 200000 ppm. Table 1 lists the properties of the brine compositions used in this work at different temperatures. Table 1. Composition of Synthetic Water TDS (ppm) Compound 2000 NaCl

20000

200000

1514.29

15142.9

151429

Na2SO4

7.39

73.9

739

MgCl2

81.30

813.0

8130

CaCl2

352.15

3521.5

35215

KCl

28.05

280.5

2805

NaHCO3

16.79

167.9

1679

5


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2.4. Preparation of nanofluids. The different solutions of NGA incorporating several concentrations (wt. %) were dispersed in the deionized water followed by ultrasonic for 50 min. Then, another solution prepared by calculating the salinity concentration and slowly added onto the first solution and stirred followed by sonication (30 min) to produce corresponding nanofluid. Regarding the experiments, the optimum concentration of NGA particles was determined as 0.1 wt. %. 2.5. Core and oil sample properties. Coreflood experiments were performed by Berea sandstone core plugs as the porous medium in the laboratory. The core plug properties are summarized in Table 2. Table 2. Core plug properties of carbonate reservoir as model. Permeability Porosity Diameter Length

Pore volume

Core ID

S1

(mD)

(%)

(cm)

(cm)

(mL)

32

23.28

3.68

6.31

16.5

The following conventional tests after each coreflood experiment by taking account of salinity medium and nanoparticles injection were performed to core plug saturation at room temperature: For all tests, the core plug was soxhleted for 48 h and washed with methanol at 70 °C during 24 h. The core plugs were dried in an oven at 120 °C/24 h to obtain purified rock surfaces and vacuumed to reduce humidity for 10 hr. The core plugs were completely aged in crude oil for two-four weeks and flooded with a low salinity and two high salinity 2000 ppm and 200000 ppm rine in tertiary oil recovery mode.

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2.6. Core flooding experiment apparatus tests. A core flooding experiment apparatus is assembled of transfer vessels, differential pressure transducer, back-pressure regulator, gas flow meter system, core holder, pump heating system, positive displacement pumps, DBR pump, and a data acquisition system. The pressure drops were determined continuously from the data collected in all experiments. Figure 1 shows a schematic diagram of core flooding system in the present study. 2.7. Critical micelle concentration (CMC) measurement. It is obvious that the CMC measurements is evaluated by several methods such as ultraviolet-visible (UV−vis) spectroscopy, cyclic voltammetry (CV) , scattering measurements, Isothermal Titration Calorimetry (ITC) , surface tension measurements, and conductivity data.37 We demonstrate in this work that, the conductivity measurement of samples were recorded with a commercial conductimeter (EC-Meter GLP 31+) form Crison Company. For the experiments, after calibration using standard solution, the conductometer probe washed up with distilled water. Finally, the CMC values for optimum condition (containing polyacrylic acid based dispersal (AcumerTM 3100)) can be drawn based on conductivity measurements versus concentration. 38 Along the experiments for the stable condition, the concentration values remained steady with time (see Figure S1 in Supplementary Material). It is obvious that the surfactant ions, become micelles when the concentration upsurges to a definite value which is shown in Figure S1. Furthermore, the CMC optimum concentrations were obtained at 0.1 wt. %.

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Figure 1. Schematic view of the setup used for the core flooding. Two scenarios were designed before the fluid injection. In order to investigate the effect of NGA particles with different salinities and temperatures, firstly, the fluid (200000 ppm) were injected for all connate water. The initial saturation of core plug in all experiments was evaluated and the two scenarios were defined as: a) in the absence of NGA particles in several salinities (200000 ppm, 20000 ppm, and 2000 ppm) and at different temperatures (25 °C, 60 °C, and 80 °C). b) In the presence of NGA particles in the same concentrations, salinities, and temperatures. In all experiments, the flow rate and overall pressure for the injected fluid was 1 mL/min and 2500 PSI, respectively. The pressure differential on either side of core plug was continuously measured and recorded.

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3. RESULTS AND DISSCUSION 3.1. NGA synthesis analysis NGA particles were prepared and characterized by field emission scanning electron microscopy (FE-SEM), X-ray diffraction (XRD), and Fourier transform infrared spectroscopy (FT-IR). Figure 2 shows XRD pattern for NGA particles. The XRD pattern of NGA is match with the (JCPDS 00-004-0880) diffraction standard card that show intensities of the peaks due to γ-Al2O3. Three broad diffraction peaks at 2θ angles around 38.0◦, 46.0◦, and 66.0◦ corresponding to the (311), (400), and (440) planes, respectively. The intensity of the characteristic peaks is significantly in agreement with the standard data for the NGA structure.39

Figure 2. X-ray diffraction pattern for NGA particles. The FT-IR spectra of the natural gibbsite as precursor and synthesized NGA particles in the range 400-4000 cm-1 can be observed in Figure 3. The characteristic absorbance at 400-1000 cm–1 as a broad band can be ascribed to Al-O vibration, which is consistent with the reported IR spectra for NGA particles in the literature. Furthermore, a broad peaks around 3100-3600 cm–1 for both NGA and gibbsite belong to the stretching vibration OH groups. Based on the chemical structure of the precursor and product, 9


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the weak peaks in the region 1100-1400 cm–1 for NGA can be assigned as bending vibrations of OH groups on the surface of NGA particles, while the same vibration for the gibbsite mode appeared at around 1060 cm-1.40, 41

Figure 3. FT-IR spectra for the comparison of gibbsite and NGA particles. Figure 4 shows the FE-SEM image for the morphology of the as-prepared NGA particles. As can be seen, the synthesized NGA particles are relatively uniform and spherical in shape with average diameter of 20 nm.

Figure 4. FE-SEM image of NGA particles.

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The porous character of the as-prepared NGA particles was carried out by N2 adsorption analysis. The Barrett–Joyner–Halenda (BJH) pore size distribution curve derived from adsorption data of the isotherms clearly shows a main peak with the pore size centered at 5 nm, for one type of pores (Figure 5A). Both N2 sorption isotherms exhibit the typical type-IV curve with a H2 hysteresis loop indicating pore interconnectivity in agreement with IUPAC classification (Figure 5B).42 The specific surface area and pore volume of the catalyst were calculated as 352.48 m²/g and 0.49 cm³/g, respectively.

Figure 5. (a) Pore size distribution of NGAs sample obtained by Barrett–Joyner–Halenda (BJH) and (b) N2 adsorption–desorption analysis.

3.2. Flooding data The XRD analysis of crushed sandstone core plug which used for this work was shown in Figure 6. The semi-quantitative mineral composition measurements by XRD pattern of the porous media core sample was containing of quartz (89.5 wt. %), feldspar (2.3 wt. %), mica (4.1 wt. %), kaolinite (2.5 wt. %), dolomite (0.7 wt. %) and other minerals (0.9 wt. %).

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Figure 6. X-ray diffraction pattern curve of core sample. Firstly, the oil recoveries results during different salinitiy waterflooding presented in bulk and nano injection mode. Considering the effect of salt on the flooding process, Zhang et al. 43 showed that changes in the salt composition can lead to oil recovery. Therefore, the oil recovery factors resulted in waterflooding experiments in different salinities and at various temperatures were performed (Figure 7). As a result, it was well found that increasing the temperature and salinity caused more oil recovery in scenario 1. Compared to the scenario 1, the scenario 2 in the presence of NGA particles gave relatively better results. All experiment tests were carried out by injection until production ceased a stable pressure profile. The results are summarized in Fig 7.

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Figure 7. Oil recovery factor for sandstone core plug (tertiary mode) at (a) 25 °C, (b) 60 °C, and (c) and 80 °C.

According to the water injection rate and recovery factor percentage during the experiments, the recovery factors increased significantly from 25 to 80°C. However, the amount of recovery factors varies with temperatures into the porous medium. As can be seen in Figure 7 (a), recovery factor values are less than 70 %. At the 60 °C (Figure 7 (b)), it indicates an upward trend over the 70 % with low salinity water flooding. A similar state was reported for the Figure 7 (c) and it was found that at 80°C, the rate of increase was significantly more than other ones. 13


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The clay particles in the high salinities are undistributed, hence, the sandstone keeps its own oilwet nature which leads to less oil displacement while this manner is apparently reversed in scenario 2. According to low saline mechanism, in lower salinities, the clay particles would be easier separated from pore surface. However, the presence of NGA particles as an oil sweeping agent between contact surface of fluid with sandstone and increasing temperatures and salinity changes the surface properties and enhances oil recovery. According to the dynamic adsorption studies, more EOR and pressure drop was observed by increasing the adsorption rate of NPs on the core. Based on the results obtained from the various flooding pressures drop, it can be concluded that the fluid injection in scenario 1 has less pressure drop than scenario 2 and obviously reduces the oil recovery. In fact, this situation confirms the positive effect of using NGA particles. As shown in Fig 8, it can be said that increasing the temperature, increases the adsorption amount of NPs and leads to more oil production.

Figure 8. Dynamic adsorption of fluids at various temperatures.

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In regard of the dynamic adsorption data and differential pressure across the sandstone core plug which was continuously recorded with a data gathering system, it can be deduced that a volume of core was occupied and the adsorption of samples containing NGA particles occurred. As can be seen in Fig 9, the pressure drop increased to some extend by enhancement of oil recovery that has a direct relationship with temperature increase. Increase of pressure drop during fluid injection in the presence of NPs is more than NPs-free case and it declares the adsorption of NGA particles in core and its positive effect. It should be noted that during coreflood experiments and after the injection period, the differential pressure (DP) increased to a maximum value, followed by a relatively sharp decrease, but it was not observed for all cases. For example, in some cases in which the increase in pressure drop was observed, no fine particle detected in the sampling tubes.44 It is well known that the concentration of present ions in injected brine can affect interactions with rock matrix and influence differential pressure (DP) during waterflooding.

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Figure 9. Differential pressure for sandstone core plug (tertiary mode) at (a) 25 °C, (b) 60 °C, and (c) and 80 °C.

As a comparision, Figure 10 summarizes all oil recovery factors for the bulk and nanofluids in these injection processes. It can be seen that the best result was observed for the fluids with low salinity injection. However, it can be also deduced that fluid containing NGA particles caused more recover than the bulk case.

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Figure 10. Comparison of oil recovery factors for the bulk and nanofluids in the injection process.

The effect of NGA particles adsorption on the sandstone core plug to prevent clay swelling and improvement in EOR has been mechanistically suggested in Figure 11.45 As can be seen, NGA particles may make some efficient interactions including hydrogen bonds and Al-O coordination with the sandstone surface yielding decrease in surface tension of oil hydrocarbons and sandstone for better oil sweeping.20

Figure 11. Possible mechanism for NGA particles adsorption on the sandstone core plug. 17


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CONCLUSION In summary, the NGA particles were easily prepared and employed as a cheap and highly efficient sweeping agent in the EOR process. Based on the obtained results during experiments, it was concluded that the dynamic adsorption of as-prepared NGA particles in core plug was apparently more than bulk injection, especially when the temperature increased. More enhanced oil recovery for the low saline injection mechanism has been also observed in comparison with moderate and high salinities. On the other side, more pressure drop happened during injection which can be a reason for more oil recovery. The results showed that injection of low salinity waterflooding increased oil recovery by tertiary-mode in bulk and NGA particles on Berea sandstones. AUTHOR INFORMATION Corresponding Author *Address: Nanotechnology Research Center, Research Institute of Petroleum Industry (RIPI), P.O. Box 14665-1998, Tehran, Iran; E-mail: [email protected] Notes The authors declare no competing financial interest.

ACKNOWLEDGMENT The authors are grateful to Nanotechnology Research Center, Research Institute of Petroleum Industry, Iran.

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REFERENCES 1. Gandomkar, A.; Rahimpour, M. R., Investigation of low salinity waterflooding in secondary and tertiary enhanced oil recovery in limestone reservoirs. Energy & Fuels 2015. 2. Aghaeifar, Z.; Strand, S.; Austad, T.; Puntervold, T.; Aksulu, H.; Navratil, K.; Storås, S.; Håmsø, D., Influence of Formation Water Salinity/Composition on the Low-Salinity Enhanced Oil Recovery Effect in High-Temperature Sandstone Reservoirs. Energy & Fuels 2015, 29, (8), 4747-4754. 3. Myint, P. C.; Firoozabadi, A., Thin liquid films in improved oil recovery from low-salinity brine. Current Opinion in Colloid & Interface Science 2015, 20, (2), 105-114. 4. AlAmeri, W. S.; Teklu, T. W.; Graves, R. M.; Kazemi, H.; AlSumaiti, A. M., Enhanced oil recovery process to inject surfactant-augmented low-salinity water in oil-wet carbonate reservoirs. In Google Patents: 2015. 5. Song, W.; Kovscek, A. R., Functionalization of micromodels with kaolinite for investigation of low salinity oil-recovery processes. Lab on a Chip 2015, 15, (16), 3314-3325. 6. Wilson, A., CO 2 Low-Salinity Water Alternating Gas: A Promising New Approach for EOR. Journal of Petroleum Technology 2015, 67, (01), 84-86. 7. Myint, P. C.; Firoozabadi, A. In Thermodynamics of Flat Thin Wetting Films with Applications to Low-Salinity Waterflooding, SPE Annual Technical Conference and Exhibition, 2015; Society of Petroleum Engineers: 2015. 8. Austad, T.; Shariatpanahi, S.; Strand, S.; Black, C.; Webb, K., Conditions for a low-salinity enhanced oil recovery (EOR) effect in carbonate oil reservoirs. Energy & fuels 2011, 26, (1), 569-575. 9. Lager, A.; Webb, K. J.; Collins, I. R.; Richmond, D. M. In LoSal enhanced oil recovery: Evidence of enhanced oil recovery at the reservoir scale, SPE Symposium on Improved Oil Recovery, 2008; Society of Petroleum Engineers: 2008. 10. Morrow, N.; Buckley, J., Improved oil recovery by low-salinity waterflooding. Journal of Petroleum Technology 2011, 63, (05), 106-112. 11. Austad, T.; Shariatpanahi, S. F.; Strand, S.; Aksulu, H.; Puntervold, T., Low Salinity EOR Effects in Limestone Reservoir Cores Containing Anhydrite: A Discussion of the Chemical Mechanism. Energy & Fuels 2015. 12. Yang, J.; Dong, Z.; Dong, M.; Yang, Z.; Lin, M.; Zhang, J.; Chen, C., Wettability Alteration during Low Salinity Waterflooding and The Relevance of Divalent Ions in This Process. Energy & Fuels 2015. 13. Mahani, H.; Keya, A. L.; Berg, S.; Bartels, W.-B.; Nasralla, R.; Rossen, W. R., Insights into the Mechanism of Wettability Alteration by Low-Salinity Flooding (LSF) in Carbonates. Energy & Fuels 2015, 29, (3), 1352-1367. 14. Brady, P. V.; Morrow, N. R.; Fogden, A.; Deniz, V.; Loahardjo, N., Electrostatics and the Low Salinity Effect in Sandstone Reservoirs. Energy & Fuels 2015, 29, (2), 666-677. 15. RezaeiDoust, A.; Puntervold, T.; Strand, S.; Austad, T., Smart water as wettability modifier in carbonate and sandstone: A discussion of similarities/differences in the chemical mechanisms. Energy & fuels 2009, 23, (9), 4479-4485. 16. Alagic, E.; Skauge, A., Combined Low Salinity Brine Injection and Surfactant Flooding in Mixed− Wet Sandstone Cores. Energy & fuels 2010, 24, (6), 3551-3559. 17. Matthiesen, J.; Bovet, N.; Hilner, E.; Andersson, M. P.; Schmidt, D. A.; Webb, K. J.; Dalby, K. N.; Hassenkam, T.; Crouch, J.; Collins, I. R., How naturally adsorbed material on minerals affects low salinity enhanced oil recovery. Energy & Fuels 2014, 28, (8), 4849-4858. 19


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