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Tributyl(tetradecyl)phosphonium Chloride Ionic Liquid for Surfactant Enhanced Oil Recovery Iago Rodríguez-Palmeiro, Iria Rodríguez-Escontrela, Oscar Rodriguez, Ana Soto, Sven Reichmann, and Mohd M. Amro Energy Fuels, Just Accepted Manuscript • Publication Date (Web): 26 May 2017 Downloaded from http://pubs.acs.org on May 31, 2017

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Tributyl(tetradecyl)phosphonium Chloride Ionic Liquid for Surfactant Enhanced Oil Recovery Iago Rodríguez-Palmeiro1, Iria Rodríguez-Escontrela1, Oscar Rodríguez1, Ana Soto11, Sven Reichmann2, Mohd M. Amro2 1

Chemical Engineering Department, Universidade de Santiago de Compostela, E-15782 Santiago de

Compostela, Spain 2

Institute of Drilling Engineering and Fluid Mining, Technical University Bergakademie Freiberg, D-

09599 Freiberg, Germany

ABSTRACT The promising properties of surface active ionic liquids (SAILs) make these salts interesting candidates for the optimisation of surfactant enhanced oil recovery (EOR) methods. The tests that should be carried out at laboratory scale, prior to proposing a SAIL for EOR, were carried out with tributyl(tetradecyl)phosphonium chloride ([P4 4 4 14]Cl).

Phase diagrams with water and n-dodecane showed that the affinity of the

surfactant for water is greater than for oil, even in the presence of a high salt content. The advantage of the use of Winsor type I microemulsions in EOR is the low phase trapping/adsorption. A formulation consisting of 4000 ppm [P4 4 4 14]Cl, 4 wt% NaCl and 5000 ppm NaOH, was able to reduce the interfacial tension between water and Saharan crude oil from 19.2 mN·m-1 to 0.1 mN·m-1. Core-flooding experiments were carried out, at room temperature and an injection rate of 2 mL/min, mimicking enhanced oil recovery with brine solutions of SAIL, NaOH and the optimised formulation combining both chemicals. The injection of the proposed formulation, after flooding with brine, led to an additional recovery of about 8 % of the original oil in place. 1

Corresponding author. E-mail address: [email protected]

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ACS Paragon Plus Environment

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Keywords: Ionic Liquid, EOR, Phase Diagram; Interfacial Tension; Core-flooding

INTRODUCTION Among the chemical enhanced oil recovery (EOR) processes, surfactant flooding has the greatest potential, while it is the most challenging considering field application. In dilute surfactant flooding, oil droplets trapped in the pores of the rocks must be deformed to allow crude displacement. This effect can be achieved by low interfacial tension1. In micellar flooding, the surfactant solution is injected as a much more concentrated slug. Behaviour of water/brine, oil and surfactant mixtures corresponding to a Winsor type III system offers obvious benefits2. This behaviour implies the formation of a three-phase system, where a bicontinuous microemulsion forms a middle phase between excess oil and aqueous phases. When a middle phase microemulsion is formed, associated with an ultra-low interfacial tension value, oil and water are solubilised in each other, and oil droplets can flow more easily throughout pore throats1. In both surfactant methods, wettability can also be changed due to surfactant adsorption, thus favouring oil recovery. Traditional EOR research focuses on interfacial tension as the determining parameter to improve oil recovery using surfactants, and consequently Winsor type III systems show the desired phase behaviour for this application. Winsor type I systems, with an aqueous microemulsion and an excess oil phase, or Winsor type II systems, with an oily microemulsion and an excess water phase, are considered to be less adequate. However, Sheng1 analyses advantages and disadvantages of the three types of microemulsion systems, concluding that the optimum phase type can only be determined from core flooding experiments using reservoir cores.

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The promising properties of ionic liquids (ILs) can be extended to surface active ionic liquids (SAILs). Some of these properties are particularly advantageous when applied to EOR applications: thermal stability (in most cases), high capacity of solubilisation of polar and non-polar compounds, and tuning possibilities. For these reasons, SAILs are emerging as possible candidates to improve surfactant EOR methods3-5. Papers where SAILs are tested for surfactant EOR found in the literature6-18 can be classified into two groups. Some of them6-12 show the reduction of the interfacial tension between water or brine and oil through the measurement of dynamic interfacial tensions. The second group of papers13-19 involve those where core flooding tests are carried out. Hezave et al.14 reached extractions of about 50% of the original oil in place (OOIP) flooding with brine and an additional 8 % of OOIP in tertiary flooding with a 4000 ppm solution of the SAIL 1-dodecyl-3-methylimidazolium chloride in water. This extraction increased up to 13 % of OOIP when the same concentration of SAIL was prepared in formation brine. However, the authors do not indicate the type of rock used in the experiments. Benzagouta et al.15-16 suggested the use of Ammoeng 102 (tetraalkyl ammonium sulfate). Flooding runs were conducted on Berea sandstone samples. The injection of 20 % brine solution (83% NaCl and 17% CaCl2) allowed an extraction of about 40% of the OOIP. The following injection of 500 ppm of Ammoeng 102 diluted in the same brine solution, led to an additional extraction of about 5 % of the OOIP. Gou et al.17 used water-soluble complexes of hydrophobically modiﬁed polymers and surface active imidazolium-based ILsfor enhancing oil recovery. The polymer, denoted as PAAD, was prepared with acrylamide, acrylic acid, and N,N-diallyl-2dodecylbenzenesulfonamide.

The

PAAD/1-methyl-3-octylimidazolium 3


bromide

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complex was found to be more effective at reducing the interfacial tension than water/[C8mim]Br system. An EOR from sand cores of about 22% of the OOIP was obtained with the complex brine solution. Sakthivel et al.18 tested the combination of several methods of EOR using ILs at several temperatures and salinities. The authors carried out core-flooding experiments (sandpack cores) with sodium dodecyl sulfate (SDS), alkyl ammonium ILs (not surface active compounds), polyacrylamide and polyacrylamide after SDS/IL flood. Best results were found under high saline conditions (10 wt% saline solution). After the water-flood operation, tertiary oil recoveries with ILs ranged from 10 to 15 % of the OOIP. A subsequent polymer flood improved the recovery. Similar extractions (12-14 % of OOIP) were found by these authors working with hexanoate and alkyl-methylimidazolium SAILs19. For imidazolium chloride SAILs, the longer the alkyl chain length, the bigger the extraction. However, the literature lacks manuscripts which consider all of the tests that should be carried out at laboratory scale prior to proposing a SAIL for EOR. Those preliminary studies should involve, at least, phase equilibria (including salinity tests), interfacial tension and core-flooding tests. Thus, in this work and with the aim of analysing the suitability of the SAIL tributyl(tetradecyl)phosphonium chloride to improve surfactant EOR methods, the above-mentioned tests are carried out. The surfactant character of this IL was shown by Blesic et al.20 who determined its cmc (1 mM). A comparison of the capability of extraction of this SAIL and NaOH, an alkali widely used in EOR,21,22 is also presented. MATERIALS AND METHODS Materials The SAIL tributyl(tetradecyl)phosphonium chloride was kindly donated by CYTEC (USA). To purify it, [P4 4 4 14]Cl was heated at moderate temperature (ca. 343 K) under 4


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stirring and high vacuum (99 wt%). Prior to its use, it was washed with fresh bidistilled water at least three times and passed several times through a column of alumina (Sigma-Aldrich, activated, basic, Brockman I). Its final water content was 60 ppm. The crude oil used in the dynamic interfacial tension measurements (Saharan Blend, 45.3 ºAPI, Pour Point: -20 ºC, Viscosity at 40 ºC: 1.6 mm2/s) was kindly supplied by Repsol (Refinery of A Coruña, Spain). Model oil used in core-flooding experiments was WIOLTAN SSH 70 supplied by H&R refinery, Hamburg (30.5 ºAPI, Pour Point: -12 ºC, Viscosity at 40 ºC: 70.5 mm2/s). Methods Phase equilibria Phase diagrams were determined using the direct analytical method. Mixtures of the three components (water, n-dodecane and [P4 4 4 14]Cl), with global compositions in the immiscible domain, were placed inside jacketed equilibrium glass cells. Temperature was controlled by circulation of water from a thermostatic bath (Selecta Ultraterm 6000383) through the cell jacket. The mixtures were mechanically stirred for at least 2 h, and then allowed to settle for a minimum of 24 h. On the basis of preliminary tests, these times were found to be sufficient to ensure achievement of equilibrium and 5


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complete phase separation. Samples from each equilibrated phase were taken with syringes coupled with stainless steel needles, avoiding disturbance of the interface during the sampling process. The composition of phases in equilibrium was analysed by gas chromatography using an internal standard method. The gas chromatograph used was a Hewlett-Packard HP6890 series equipped with a HP-FFAP (25 m x 0.2 mm x 0.33 µm) capillary column and a thermal conductivity detector. A pre-column was used to prevent IL not retained in the liner from reaching the analytical column. Helium was used as the mobile phase. The GC operating conditions are given in Table 1. Samples of the equilibrium phases (ca. 0.25 mL) were diluted in 2-propanol (ca. 0.5 mL) and methyl acetate (ca. 0.2 mL) was added as standard. GC analysis allowed quantification of water and n-dodecane mass fractions. The IL mass fraction was obtained by summation to unity, since phases in equilibrium have three components. A Mettler Toledo AE 240 analytic balance with a precision of 10-4 g was used for weighing during the calibration process. Dynamic interfacial tension Dynamic interfacial tensions between the surfactant solutions and the crude oil were measured with a Krüss SITE 100 spinning drop tensiometer working in automatic mode. The operation principle is shown in Figure 1. The aqueous phases were used to fill the capillary tube as the bulk phase, and crude oil (4 µl) was injected in the middle of the tube as the drop phase. Rotating velocities between 3000 and 5000 rpm were applied to measure the interfacial tension in all cases but for pure water/crude oil that required a rotating velocity of 12000 rpm. The interfacial tension was calculated according to the following equation: γ =

∆ ρω 2 D 3 32

6


(1)

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where ω is the angular velocity, D is the diameter of the oil drop and ∆ρ the density difference between the aqueous phase and the crude oil. The calibration of the equipment was carried out with a reference wire in order to calculate the drop diameter in millimeters from the height of the drop in pixels measured in the image. After measurements, cleaning was accomplished washing several times with hot water and using a soft brush, following by washing with acetone. The estimated uncertainty in measurement is ±2%. The temperature was kept constant using a thermostatic bath Julabo model EH-5 with stability ±0.1 K. All the experiments were performed at least twice to ensure repeatability. Core-flooding Flooding experiments were conducted using an automated core-flooding system equipped with a core holder and three piston accumulators for oil, brine and surfactant solution (Figure 2). A constant flow positive displacement pump wass used to inject distilled water into the bottom of the three accumulators for the injection of the required fluid. Experiments were carried out at room temperature and a constant injection rate of 2 mL/min. This corresponds to a Darcy velocity of ca. 2-3 m per day, focusing thus in a region from the near well bore to a distance of 5-15 m from the injection well. Confining pressure is controlled by an automated pressure intensifier. To prevent hydraulic side flow, a confining pressure of ca. 40 bar was applied, which is significantly higher than the flooding pressure. Effluents produced were collected in graduated tubes. Inlet and outlet pressures were measured by an UNIK 5000 PTX sensor and a National Instruments DAQ system. The rock samples used in the coreflooding experiments were Bentheim sandstone (adsorption test) and Berea sandstones (oil recovery tests) . The properties of the Berea sandstones are shown in Table 2. The cylindrical samples were 30 cm long and 3.8 cm wide. 7


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After the assembly of the sandstone core in the system, the core was then evacuated. Small amounts of gas remaining inside the core sample would affect pressure measurements and would disturb the oil-brine and oil-formulation two phase flow due to the occurrence of a third moving phase. Pressure curves were determined to analyse the surfactant solution adsorption. In order to calculate the resistance factor (RF) and the residual resistance factor (RRF), the core (S0) was flooded with brine and afterwards 3-4 pore volumes (PV) of surfactant solution (2000 ppm) were injected at a flow rate of 2 mL/min. Then the process was repeated using about 3 PV of brine (4 wt% NaCl). The RF is calculated as the ratio between the differential pressure during surfactant flooding and brine flooding, since the viscosities are approximately constant. The RRF is calculated as the ratio of the differential pressure during brine flooding after surfactant injection and the corresponding differential pressure before surfactant injection. As the first step in oil recovery experiments, each sandstone core was flooded with WIOLTAN SHH 70 model oil after it had been saturated with brine. During the flooding, some of the brine was displaced by oil. After the displacement, the sample was aged for 2 weeks in order to attain a constant wettability. Three oil recovery studies were carried out. In the first test (core S1), when the ageing was finished, the sample was flooded with brine again. During this process part of the oil was extracted. Due to restraining mechanisms, like capillary forces and viscosity effects, only a part of the original oil in place (OOIP) can be obtained. The remaining oil is called residual oil in place (ROIP). After reaching the ROIP saturation, the formulation optimised through dynamic interfacial tension measurements (2000ppm SAIL, 5000 ppm NaOH, 4 wt% NaCl) was injected to determine the additional oil recovery. A second test was carried out. To mimic enhanced oil recovery in this case a 4000 ppm SAIL in brine solution 8


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was injected until there was no further recovery. The aim is to analyse the capability of extraction of the SAIL alone. The extraction was finished with the injection of the optimised formulation. In the third test, after reaching the ROIP saturation, 5000 ppm NaOH in brine solution was injected followed by the optimised formulation. RESULTS Phase equilibria The SAIL [P4 4 4 14]Cl is solid at 298.15 K and liquid at 348.15 K. The melting point of this IL was determined by Del Sesto et al.23 and Bradaric et al.24. The reported values are 56 ºC and 60ºC, respectively. A high solubility of [P4 4 4 14]Cl in water was found at 298.15 K (w=0.96). This is in agreement with the value previously reported by Blesic et al [19] (w=0.94). At 348.15 K, the SAIL and water are completely miscible. When [P4 4 4 14]Cl, water and n-dodecane are mixed, biphasic systems are found. The affinity of the surfactant for the aqueous phase is greater than for the oil. Any mixture within the interior of the immiscible area splits into an aqueous phase that contains most of the surfactant in equilibrium with an excess phase of oil (almost pure n-dodecane at 298.15 K). Liquid-liquid equilibrium data are presented in supporting information (Tables S1 and S2) and phase diagrams are shown in Figures 3 and 4. At the lower temperature, and due to the solid character of the IL, only very small areas of SL and SLL equilibria appear at the top of the triangular diagram and close to the SAIL/ndodecane binary, respectively. These areas have been qualitatively determined by cloud point method and represented in Figure 3. At 348.15 K, a system characterised by the existence of two pairs of partially miscible liquid components and one biphasic region was found. Brine solutions were prepared with concentrations up to 4 wt% NaCl and were mixed with the surfactant at different concentrations at room temperature and atmospheric 9


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pressure. In all cases a clear solution was found. These samples were mixed with oil and a biphasic system was found in all ranges of salinity. Thus, a Winsor type III system (the goal in traditional EOR research) was not found. However, the advantage of the use of Winsor type I microemulsions in EOR is the low phase trapping/adsorption1. Correlation The correlation of the experimental data was carried out using the NRTL equation25. Despite initially being intended for non-electrolytes, the NRTL has become a standard model in the data treatment of phase equilibria involving ionic liquids. The reason for this widespread use is its ability to accurately reproduce the phase behaviour of a huge variety of systems. The non-randomness parameter α was fixed to 0.1, 0.2 and 0.3 to carry out the correlation. The binary interaction parameters were obtained using a computer program described by Sørensen and Arlt26 which uses two objective functions. The first objective function is based on activities and does not need any initial estimate of the parameters. The result of this first correlation is then used to estimate the second correlation using an objective function based on compositions (mole fractions) which provide the final fitting. More details are available elsewhere27,28. The accuracy of the correlation is measured by means of the root mean square deviation, rmsd, obtained as:

( x − xˆ )   F = 100 ×  ∑ min ∑ ∑  6M   2

ijk

k

i

ijk

0 .5

(2)

j

where x stands for the compositions (in mole fractions), superscripts exp and calc stand for experimental and calculated values, subscripts i, j and k identify the components, equilibrium phases and different tie-lines, respectively. M represents the total number of tie-lines. The two LLE data sets were correlated independently in order to provide a more accurate representation of the tie-lines. Additionally, a simultaneous correlation of 10


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the two data sets was carried out since it provides a single set of parameters, which is intended to give an adequate representation for the whole temperature range. The fitting parameters for NRTL are presented in Table 3 together with the rmsd associated with each correlation. In all cases, the best results were obtained with α = 0.3, while α = 0.2 provided only slightly higher deviations. A comparison of the experimental and correlated tie-lines is provided in Figures S3-S5 in the supporting information. Inspection of Figures S3-S5 in the supporting material confirms the high accuracy of the NRTL correlation, as indicated by the low rmsd obtained (rmsd < 1% in all cases). The simultaneous correlation seems preferable in general since a single set of parameters are able to describe the phase behaviour for a rather large temperature range (from 298.15 K to 348.15 K) while the loss of accuracy is rather small (an increase of about 0.3-0.5%). Dynamic interfacial tension With the aim of analysing the capacity of the SAIL [P4

4 4 14]Cl

to reduce the

interfacial tension between water or brine and crude oil, dynamic interfacial tension measurements were carried out. A value of 19.2 mN·m-1 was found for the Saharan crude oil/water interfacial tension. To evaluate the effect of the SAIL, three aqueous solutions were prepared with concentrations of 500, 2000 and 4000 ppm. Dynamic interfacial tension measurements between crude oil and these solutions were carried out at 298.15 K and atmospheric pressure. Results are shown in Figure 5. The interfacial tension decreases with concentration of the surfactant ionic liquid, reaching a value of 3.7 mN·m.1 for a concentration of 4000 ppm when the system is equilibrated. As salts can have a significant effect on the interfacial tension, dynamic interfacial tensions between crude oil and surfactant (4000 ppm) aqueous or brine (4 wt%) solutions were measured at 298.15 K, 318.15 K and 338.15 K and the results can be seen in Figure 6. 11


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Salt concentration was selected as representative value for low-medium saline reservoirs. The influence of temperature has a slight effect on interfacial tension, obtaining lower values of this variable at the lowest temperature. However, the salt concentration has a greater effect in the reduction of the interfacial tension. A value of about 0.2 mN·m-1 was found at the lowest temperatures when brine was used instead of water. With the aim of improving the formulation, NaOH solutions were prepared in water with surfactant (4000 ppm) and NaCl (4 wt%) and dynamic interfacial measurements were carried out at 298.15 K. It is well known that alkalis react with components of crude oil generating surfactants in situ, thus a synergistic effect was expected. The tested NaOH solutions were 5000 ppm, 10000 ppm and 15000 ppm. The presence of NaOH further reduces the interfacial tension reaching a value of 0.1 mN·m-1 (Figure 7). The concentration of the alkali does not affect the final value obtained. This behaviour is contrary to that previously obtained for the SAIL [C12mim][OAc] [9], where high concentrations of NaOH were required to reduce the values of the interfacial tension. Core-flooding To investigate the surfactant adsorption on the rock surface, the RF and RRF were determined. Resistance is related to mobility, which includes the effect of permeability reduction and viscosity increase.

Due to the similar viscosity of brine and SAIL

solutions, the increase of the RF in this case is due to geometry changes of the pores when the surfactant is adsorbed. This adsorption means that the concentration of chemical is reduced, the zone around the injection well is damaged and higher pressures are required to extract the oil. The RF value obtained (core S0) converged to a value of 1.6 after the injection of 2 PV and stayed constant after the injection of 2.5 PV of surfactant solution. This low value indicates a very limited adsorption which does not 12


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lead to plugging or other severe problems. The injection of 3 PV of brine after surfactant injection allowed the calculation of the RRF that remained constant in a value of 1.5. Thus, RF and RRF values indicate low and partially reversible adsorption. As a significant reduction in the interfacial tension was found with the optimised formulation (4000 ppm SAIL, 5000 ppm NaOH, 4 wt% NaCl), oil recovery experiments were carried out with the aim of drawing conclusions for the viability of the use of this chemical system in EOR. The pressure curve for this first test is shown in Figure 8. After brine flooding, tertiary oil recovery was mimicked with the NaOH-IL-brine formulation. At the beginning of the flooding, a rise in the pressure indicated a significant mobilisation of oil in the core. Accordingly, the pressure fell to a lower level than the initial residual oil in place level. These results are in agreement with numbers shown in Table 4. After secondary recovery (31.4 % of the OOIP extracted), an additional oil production of 8.1 % of the OOIP was reached when the optimised formulation was used. The RF values are on a very low level suggesting no plugging was caused due to the flooding. The pressure curve for the second test is shown in Figure 9. In this case, brine flooding was followed by the IL-brine injection. At the beginning of the flooding, a small pressure rise occurred. This was due to small amounts of mobilised oil and inertia of the flow. Extraction with brine led to a recovery of 35.8 % of the OOIP, and during the IL-brine flooding 4.3 % of the OOIP was extracted. The final NaOH-IL-brine flooding was ineffective and did not mobilise significant amounts of oil. The pressure data indicated a high fractional flow of water and thus low opportunity for further brine flooding. In the test T3, brine flooding produced 28.6% PV oil (38.3 % OOIP). After brine flooding, the NaOH-brine solution was injected simulating tertiary oil recovery (Figure 13


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10). As in the second test, at the beginning of the flooding a very small pressure rise occurred likely due to the inertia of the flow. During the NaOH-brine flooding 3.5% of the OOIP was extracted. The final NaOH-IL-brine flooding mobilised an additional 5.3 % of the OOIP resulting in the lowest residual oil saturation of the experiments. The pressure data indicated a high fractional flow of water and thus low opportunity for further brine flooding. During all flooding experiments no stable emulsion was found in the effluent. The results obtained (Table 4) show that enhanced oil recovery can vary drastically with the injection order. Direct injection of the optimised formulation gives practically the same result as in the case where it is injected after the NaOH brine solution. However, when the formulation is injected last following the IL injection, improvements in oil recovery are minimal. The reason for this is that the surfactants not only reduce the interfacial tension but also change the wettability of the rocks. CONCLUSIONS The IL [P4 4 4 14]Cl is a surface active agent which can significantly reduce the surface tension of a solvent. When this SAIL is mixed with water and n-dodecane, a biphasic system is formed. At 298.15 K, and due to the solid character of the IL, significantly reduced regions of SL and SLL equilibrium can also be found. At 348.15 K only liquid phases are found. Any mixture within the interior of the liquid-liquid area splits into an aqueous phase that contains most of the surfactant in equilibrium with an excess phase of n-dodecane. The capacity of the IL to solubilise oil is limited. A salinity scan with NaCl showed that this biphasic system is maintained throughout a wide range of salinities. A bicontinuous microemulsion related to a balanced solubilisation of water and oil was not found.

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In type I microemulsions, oil drops are solubilised in the large water phase, this being one of the oil recovery mechanisms. Moreover, very low concentrations of [P4 4 4 14]Cl

in water produce a significant reduction of the brine/oil interfacial tension. A

formulation consisting of 4000 ppm SAIL, 4 wt% NaCl and 5000 ppm NaOH, was able to reduce the interfacial tension between water and Saharan crude oil from 19.2 mN·m-1 to 0.1 mN·m-1. This reduction is of great interest because the basis of the surfactant EOR method is the improved displacement efficiency due to the ultralow IFT effect. Ultralow IFT results in a high capillary number which leads to a low residual oil saturation; oil droplets can flow more easily through pore throats and oil recovery is increased. RF and RRF studies showed a very limited adsorption of the IL by the rocks. Coreflooding experiments using a [P4

4 4 14]Cl

solution after brine led to similar results

previously found in literature for other SAILs. A quantitative comparison is not possible due to the different conditions of the tests carried out. Experiments differ in the type of secondary recovery (with or without salt), the type of rock (material, porosity, permeability…), IL and salinity concentrations, etc. In this work, a sand core with a medium permeability was used. The EOR with SAIL solution in brine allowed a slightly better recovery in comparison with the use of NaOH, a product frequently used in chemical EOR, but one difficult to work with due to its high corrosive and irritant character. The combination of the two chemicals led to an enhanced oil recovery of about 8 % of the OOIP. The injection order of the chemicals greatly affects oil recovery results, supporting wettability alteration as another oil recovery mechanism. According to all the laboratory tests carried out, [P4 4 4 14]Cl is a promising surfactant to reduce capillary forces that trap oil in rock pores. Pilot and large-scale applications would require tests with conditions matching those of real wells (oil, temperature, 15


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formation water salinity, rock, etc.) and the analysis of the effect of the injection flow rate. Finally, numerical simulations predicting the performance of the method, taking into account real geological features of reservoirs, would be necessary to optimise injection parameters and schemes. The promising features of ILs increase the value of these studies, which are currently very limited for traditional surfactants.

ACKNOWLEDGEMENTS The authors acknowledge the Ministry of Economy and Competitiveness (Spain) for financial support throughout project CTQ2015-68496-P (including European Regional Development Fund advanced funding) and networking support by the COST Action CM1206.

ASSOCIATED CONTENT Supporting Information The Supporting Information is available free of charge on the ACS Publications website at DOI: Experimental tie-lines for liquid-liquid equilibrium of water (1) + [P4 4 4 14]Cl (2) + ndodecane (3) ternary system at 298. 15 K and atmospheric pressure (Table S1), Experimental tie-lines for liquid-liquid equilibrium of water (1) + [P4 4 4 14]Cl (2) + ndodecane (3) ternary system at 348.15 K and atmospheric pressure (Table S2), 1H NMR spectrum of the IL [P4 4 4 14]Cl (Figure S1),

13

C NMR spectrum of the IL [P4 4 4 14]Cl

(Figure S2), Comparison of the experimental and correlated tie-lines using NRTL (α= 0.3) at 298.15 K (Figure S3), Comparison of the experimental and correlated tie-lines using NRTL (α = 0.3) at 348.15 K (Figure S4), Comparison of the experimental and

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correlated tie-lines using NRTL (α = 0.3) and simultaneous correlation of 298.15 and 348.15 K data sets (Figure S5).

REFERENCES (1) Sheng, J. J. Modern chemical enhanced oil recovery. Theory and practice; Elsevier: Amsterdam, 2011. (2) Clint, J. H. Surfactant aggregation; Springer: New York, 1992. (3) Li, X.; Sun, W.; Wu, G.; He, L.; Li, H.; Sui, H. Energ. Fuel, 2011, 25, 52245231. (4) Bera, A.; Beljah, H. J. Mol. Liquid, 2016, 224, 177-188. (5) Bin Dahbag, M. S.; Hossain, M. E.; AlQuraishi, A. A. Energ. Fuel, 2016, 30, 9260-9265. (6) Benzagouta, M. S.; Al Nashef, I. M.; Karnanda, W.; Al-Khidir, K. Korean J. Chem. Eng, 2013, 30, 2108-2117. (7) Hezave, A. Z.; Dorostkar, S.; Ayatollahi, S.; Nabipour, M.; Hemmateenejad, B. J. Mol. Liquid, 2013, 187, 83-89. (8) Hezave, A. Z.; Dorostkar, S.; Ayatollahi, S.; Nabipour, M.; Hemmateenejad, B. Fluid Phase Equil. 2013, 360, 139-145. (9) Sakthivel, S.; Velusamy, S.; Gardas, R. L.; Sangwai, J. S. Ind. Eng. Chem. Res. 2015, 54, 968-978. (10) Sakthivel, S.; Velusamy, S.; Gardas, R. L.; Sangwai, J. S. Colloids Surf. A. 2015, 468, 62-75. (11) Sakthivel, S.; Chhotaray, P. K.; Velusamy, S.; Gardas, R. L.; Sangwai, J. S. Fluid Phase Equil. 2015, 398, 80-97. (12) Rodríguez-Palmeiro, I.; Rodríguez-Escontrela, I.; Rodríguez, O.; Arce, A.; Soto, 17


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A. RSC Adv. 2015, 5, 22178-22187. (13) Pereira, J. F. B.; Costa, R.; Foios, N.; Coutinho, J. A. P. Fuel 2014, 134, 196200. (14) Hezave, A. Z.; Dorostkar, S.; Ayatollahi, S.; Nabipour, M.; Hemmateenejad, B. Colloids Surf. A. 2013, 421, 63-71. (15) Bin-Dahbag, M. S.; Al Quraishi, A. A.; Benzagouta, M. S.; Kinawy, M. M:; Al Nashef, I. M.; Al Mushaegeh, E. J. Pet. Environ. Biotechnol. 2014, 4, 165-171. (16) Bin-Dahbag, M. S.; Al Quraishi, A. A.; Benzagouta, M. S. J. Petrol. Explor. Prod. Technol. 2015, 5, 353–361. (17) Gou, S.; Yin, T:; Yan, L.; Guo, Q. Colloids Surf. A. 2015, 471, 45-53. (18) Sakthivel, S.; Gardas, R. L.; Sangwai, J. S. Energ. Fuel 2016, 30, 2514-2523. (19) Sakthivel, S.; Velusamy, S.; Nair, V. C.; Sharma, T.; Sangwai, J. S. Fuel 2017, 191, 239-250. (20) Blesic, M.; Canongia-Lopes, J. N.; Costa-Gomes, M. F.; Rebelo, L. P. N. Phys. Chem. Chem. Phys. 2010, 12, 9685-9692. (21) Samanta, A.; Ojha, K.; Mandal, A. Energ. Fuel 2011, 25, 1642–1649 (22) Zhang, H.; Chen, G.; Dong, M.; Zhao, S.; Liang. Energ. Fuel 2016, 30, 38603869 (23) Del Sesto, R. E.; Corley, C.; Robertson, A.; Wilkes, J. S. J. Organomet. Chem. 2005, 690, 2536–2542. (24) Bradaric, C. J.; Downard, A.; Kennedy, C.; Robertson, A. J.; Zhou, Y. H. Green Chem. 2003, 5, 143–152. (25) Renon, H.; Prausnitz, J. M. AIChE J. 1968, 14, 135–144. (26) Sørensen, J. M.; Arlt, W. Liquid–Liquid Equilibrium Data Collection. Binary Systems; DECHEMA Chemistry Data Series, vol. 5: Frankfurt, 1979. 18


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(27) Arce, A.; Rodríguez, O.; Soto, A. Ind. Eng. Chem. Res. 2004, 43, 8323-8327. (28) Lago, S.; Rodríguez, H.; Arce, A.; Soto, A. Fluid Phase Equil. 2014, 361, 3744.

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Table 1. Gas chromatograph operation conditions Injector Temperature 503.15 K Split 1:50 Injection volume 1 µl Column Type HP-FFAP Flux Constant flux of 1.1 mL ·min-1 Detector Type TCD Temperature 503.15 K Oven Temperature program 373.15 K (2.50 min) 120 K·min-1 to 493.15 K (1.50 min)

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Table 2. Properties of the sand cores used in this work S0 Sample S1 -15 1650 Permeability [10 m²] 580 76.5 Pore volume [mL] 74.2 0.226 Porosity 0.218

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S2 388 72.3 0.213

S3 767 73.5 0.216

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Table 3. Binary interaction parameters and deviations (rmsd, %) of the NRTL equation (α = 0.3) for each data set (298.15 K; 348.15 K) and for the simultaneous correlation of both data sets. Pair i-j 1-2 1-3 2-3

Pair i-j 1-2 1-3 2-3

∆gij -11189.6 9826.0 -723.08 T=298.15K

Parameters, J/mol ∆gji ∆gij -1174.9 878.01 13150.2 10667.5 5079.6 -1597.2 rmsd=0.29% T=348.15K

∆gji 4623.8 11904.7 13205.0 rmsd=0.52%

Simultaneous correlation (298.15 & 348.15 K) ∆gij ∆gji -2564.3 15914.7 rmsd,% (T,K) 9591.6 10582.7 0.78 (298.15K) -1373.8 12315.4 0.88 (348.15K)

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Table 4. Core-flooding results Test Sample Initial oil saturation Initial oil in place [mL] Slug 1 Produced oil [mL] Oil saturation Resistance factor Slug 2 Produced oil* [mL] Oil saturation Resistance factor Slug 3 Produced oil* [mL] Oil saturation Resistance factor

T1 S1 0.831 61.7 4% NaCl brine 19.4 0.570 2.8 Brine+IL+NaOH 24.4 0.502 2.2

T2 S2 0.8 57.8 4% NaCl brine 20.7 0.514 3.1 Brine+IL 23.2 0.479 1.8 Brine+IL+NaOH 23.7 0.472 1.5

*Accumulated extracted oil

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T3 S3 0.821 60.3 4% NaCl brine 23.1 0.507 2.7 Brine+NaOH 25.2 0.478 2.0 Brine+IL+NaOH 28.4 0.435 1.5

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ω HEAVY PHASE LIGHT PHASE

d

Figure 1. Operating principle of the spinning drop tensiometer

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A

PM

D

P1

P2

T

B C E

Figure 2. Schematic representation of the core flooding equipment. A: Injection HPLC pump; B: Piston accumulators; C: Flooding cell with core inside; D: Manual pump to apply confining pressure; E: Automatic sample collector.

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Figure 3. Liquid-liquid equilibrium for the ternary system water (1) + [P4 4 4 14]Cl (2) + n-dodecane (3) at 298.15 K and atmospheric pressure

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Figure 4. Liquid-liquid equilibrium for the ternary system water (1) + [P4 4 4 14]Cl (2) + n-dodecane (3) at 348.15 K and atmospheric pressure

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5.4 5.2 5.0 1000 ppm IL 2000 ppm IL 4000 ppm IL

4.8

IFT (mN/m)

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4.6 4.4 4.2 4.0 3.8 3.6 3.4 0

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Figure 5. Effect of [P4 4 4 14]Cl concentration on the interfacial tension (IFT) between crude oil and water at 298.15K and atmospheric pressure.

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5

4

IFT (mN/m)

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Water 298.15 K Water 318.15 K Water 338.15 K Brine 298.15 K Brine 318.15 K Brine 338.15 K

3

2

1

0 0

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Figure 6. Effect of the presence of sodium chloride (4 wt%) and temperature on the interfacial tension between aqueous solution of 2000 ppm ILand crude oil

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0.25 0.5 wt% NaOH 1 wt% NaOH 1.5 wt% NaOH

0.20

IFT (mN/m)

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0.15

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Figure 7. Effect of NaOH concentration on the IFT between brine (4 wt.% NaCl) solution of 2000 ppm IL and crude oil at 298.15K and atmospheric pressure.

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14 Brine NaOH - IL - brine

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Pressure [bar]

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8

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Figure 8. Pressure curve for core-flooding test T1

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14 Brine IL - brine NaOH - IL - brine

12

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Pressure [bar]

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14 Brine IL - brine NaOH - IL - brine

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