rock system

Journal Pre-proof A mechanistic experimental study on the combined effect of Mg2+ , Ca2+, and SO4 2− ions and a cationic surfactant in improving the surface properties of oil/water/rock system Zeinab Derikvand (Conceptualization) (Methodology) (Software) (Validation) (Formal analysis) (Investigation) (Data curation)Writing-original draft)Writing-review and editing) (Visualization), Amin Rezaei (Methodology) (Software) (Validation) (Formal analysis) (Investigation)Writing-review and editing), Rafat Parsaei (Conceptualization) (Methodology) (Software) (Formal analysis) (Resources)Writing-review and editing) (Supervision)Funding), Masoud Riazi (Conceptualization) (Methodology) (Resources) (Supervision) (Project administration)Funding), Farshid TorabiWriting-review and editing)

PII:

S0927-7757(19)31325-1

DOI:

https://doi.org/10.1016/j.colsurfa.2019.124327

Reference:

COLSUA 124327

To appear in:

Colloids and Surfaces A: Physicochemical and Engineering Aspects

Received Date:

18 September 2019

Revised Date:

6 December 2019

Accepted Date:

8 December 2019

Please cite this article as: Derikvand Z, Rezaei A, Parsaei R, Riazi M, Torabi F, A mechanistic experimental study on the combined effect of Mg2+ , Ca2+, and SO4 2− ions and a cationic surfactant in improving the surface properties of oil/water/rock system, Colloids and Surfaces A: Physicochemical and Engineering Aspects (2019),

doi: https://doi.org/10.1016/j.colsurfa.2019.124327

This is a PDF file of an article that has undergone enhancements after acceptance, such as the addition of a cover page and metadata, and formatting for readability, but it is not yet the definitive version of record. This version will undergo additional copyediting, typesetting and review before it is published in its final form, but we are providing this version to give early visibility of the article. Please note that, during the production process, errors may be discovered which could affect the content, and all legal disclaimers that apply to the journal pertain. © 2019 Published by Elsevier.

A mechanistic experimental study on the combined effect of Mg2+, Ca2+, and SO42- ions and a cationic surfactant in improving the surface properties of oil/water/rock system Zeinab Derikvand1,2, Amin Rezaei1,2, Rafat Parsaei3, Masoud Riazi1,3, and Farshid Torabi4 Enhanced Oil Recovery Research Center, IOR/EOR Research Institute, Shiraz University, Shiraz, Iran 2 Abdal Industrial Projects Management Co. (MAPSA), Tehran, Iran 3 Department of Petroleum Engineering, School of Chemical and Petroleum Engineering, Shiraz University, Shiraz, Iran 4 Petroleum Systems Engineering, Faculty of Engineering and Applied Science, University of Regina, Regina, SK, Canada 1

Highlights

The effect of magnesium, calcium and sulfate ions in the presence of a cationic surfactant on improving calcite rock wettability was examined. Combination of three ions leads to more wettability alteration and IFT reduction. A comprehensive study was implemented on the surface properties of the rock sample and the adsorption of the utilized surfactant on the rock surface. Alteration of wettability was evaluated through the measurement of the contact angle data as well as the oil/water relative permeability curves. The phase behavior of the utilized surfactant and formation of different types of microemulsions was investigated.

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Graphical abstract

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Corresponding author, Email: [email protected]

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Abstract

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More than half of the discovered hydrocarbon reservoirs in the world are the oil-wet carbonates. Enhanced oil recovery (EOR) from these reservoirs is challenging because of their tendency to retain oil at the rock surface. The use of low salinity (LS) water injection to recover more oil from these types of oil reservoirs has been recommended by several researchers. There are possible mechanisms concerning LS water flooding that have been introduced in the literature; a distinct lack of experimental investigation to enhancing the efficiency of this method is still felt. In this work, a detailed and comprehensive study was carried out on using LS + surfactant (LSS) to improve the surface and interface properties of oil + water + calcite rock samples. In the first step, the point of zero charge of the rock sample was determined. Then, the effect of different salts including MgCl 2, CaCl2, and Na2SO4 at different concentrations on improving the oil-water interfacial tension and wettability alteration of the rock surfaces was investigated in the presence and absence of a cationic surfactant, cetyl methylammonium bromide (CTAB), in the operational range of pH. Emulsion formation and adsorption measurement tests were performed for a deep investigation of the performance of the cationic surfactant in the presence of different salts. Finally, waterflooding experiments were carried out and the water/oil relative permeabilities, amount of recovery and wettability alteration were thoroughly investigated for three different injection scenarios. The results showed that the co-presence of magnesium, calcium and sulfate ions all in the presence and absence of CTAB surfactant causes a significant reduction in IFT and contact angle values, especially at the lower ranges of salinity. The addition of divalent cations, i.e., Mg2+ and Ca2+, could reduce the amount of surfactant adsorbed on the calcite rock surfaces, especially in the low ranges of salinities. Also, in flooding tests, an increase in differential pressure between the inlet and outlet faces of the core samples from about 2.9 MPa for LS to about 4.7 MPa for LSS flooding, at the breakthrough time, was observed which was related to the formation of water in oil emulsions during LSS flooding. Comparison of the ratio of the residual to initial oil saturation (Sor/Soi) for different flooding scenarios (i.e., injection of saline water (SW), LS and LSS solutions) indicates that as the salinity of water reduces, the efficiency of CTAB surfactant in improving oil recovery increases.

1.

Introduction

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Keywords: Wettability Alteration, Interfacial Tension, Cationic Surfactant, Adsorption, Emulsion, Core Flooding.

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Oil recovery, during the tertiary mode, mainly depends on the overall efficiency of different pertinent parameters during oil displacement by other fluids. When the displacing fluid is brine, the displacement is described by viscous, capillary, and surface forces. Manipulation of viscous force is limited due to technical and operational considerations. Therefore, capillary and surface forces would play important roles in oil production and in determining the amount of waterflood residual oil saturation. The value of interfacial tension governs the magnitude of these forces [1–4]. So far, many studies have been conducted on the effect of different salts on the IFT of crude oil + water systems [5–9]. It is known that due to the salting-in effect, salts accelerate the diffusion of surface-active components from the bulk solution to the interface at low concentration. On the contrary, the solubility of petroleum hydrocarbon species in the aqueous phase decreases with increasing salinity at the high salt concentrations (the salting-out effect) [10]. IFT between the oil and the aqueous phase will be reduced due to salting-in effect and affinity of some natural surfactant to produce complex ions with some specific ions in the aqueous phase [11,12]. The salting-out effect is a phenomenon in which the polar organic components preferentially enter the oil phase or move to the solid surface by the increase in salinity (at high salt concentrations) [13]. However, the reverse trend of this phenomenon is called the salt-in effect which occurs by increasing the solubility of polar organic species in brine (at low salt concentrations) [14]. Reducing IFT can also be achieved by adding surface-active materials to the injecting fluid [2,15,16]. It has been repeatedly confirmed that surfactant injection can considerably improve oil recovery through oleic/aqueous phase interfacial tension reduction. Moreover, because of the nature of the ionic surfactants not only interfacial tension between crude oil and the aqueous phase reduces, but also wettability alteration of the rock surface towards more water-wet conditions occurs [17–22]. However, the use of surface-active materials alone is costly [23]. Therefore, finding a method that uses a small amount of expensive chemicals and, at the same time, changes the surface properties of crude oil/brine /rock towards favorable conditions is necessary. A combination of ions, which are effective in reducing IFT, with surfaceactive materials has been recently offered by several researchers [18,24–29]. It has been found that better oil recovery

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will be obtained when using treated water instead of natural saline water as the bulk phase for surfactant flooding [24]. Smart water, which is the water containing determining ions is one of the promising bulk solutions used to improve the performance of surfactant flooding. The main mechanism of the combined low salinity brine and surfactant injection that leads to a reduction in residual oil saturation is destabilization and movement of oil ganglia due to IFT reduction. In addition, in the low salinity water, surfactant solubility increases; therefore, adsorption or retention of surfactant reduces that makes this hybrid EOR process more economically attractive compared to applying low salinity waterflooding or surfactant flooding alone [25].

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Altering rock wettability from oil-wet to water-wet conditions is another crucial feature of an enhanced oil recovery process for carbonate reservoirs [26,28,30–35]. A number of experimental studies have demonstrated the favorable effect of ions along with surfactants on wettability alteration [24,26,27,29–32,36,37]. The ability of sulfate [24,26,27,32,36], magnesium [24,26,32,37], and calcium [24,26,27,29,32,36] ions on altering the wettability of carbonate rock towards more water wetness in the presence and absence of surfactants was investigated in those studies. Pierre et al. (1990), showed that sulfate is a strong potential determining ion for the carbonate surface and alters the wettability of the surface of this type of rock from oil-wet to water-wet at typical pH values [29]. Knowing that the concentration of SO42− in seawater is about twice the concentration of Ca2+, seawater can be considered as a reference fluid to examine the ability of a solution to reverse the wetting conditions in carbonates [36]. Although the results found by the Pierre et al. is quite logical in terms of wettability alteration, the seawater increases the interfacial tension due to its high salinity, so they concluded that the seawater is not the best option for EOR. Magnesium ions also change the wettability of rock from oilwet to water-wet by removing the adsorbed carboxylate group from the surface; cationic surfactants improve the wettability alteration process and promote it towards the more water-wet condition [37]. Standnes et al. performed experimental work on the performance of different cationic and anionic surfactants in wettability alteration of oil-wet carbonate core plugs through spontaneous imbibition tests. They asserted that the cationic surfactants show better results than anionic surfactants and the performance of the surfactants in wettability alteration towards water-wetness is related to properties such as IFT and the CMC value, hydrophobicity and steric effects close to the nitrogen atom [38]. Despite the economic efficiency and technical strength of the method of combination of lowsalinity and surfactant to enhance oil recovery, there is a lack of a detailed study of the type and concentration of ions for preparing the treated water. Therefore, it seems to be necessary to have a deep understanding of this reliable EOR method. In this study, we investigated the combined effects of various ions and a cationic surfactant at different ranges of salinity and surfactant concentrations on wettability alteration of calcite rock surfaces, reduction of the oil-aqueous phase IFT, emulsion formation, adsorption of surfactant on the rock surfaces, determination of oil-water relative permeabilities and the amount of oil recovered from carbonate core plugs through core flooding experiments. Experimental section 2.1. Materials 2.1.1. The oleic phase. A crude oil (Saturates 43.5%, Aromatics 35.6%, Resins 12.9%, Asphaltene 8.0%) from an Iranian carbonate reservoir was used in our experiments. Also, a diluted crude oil made from 80% crude oil and 20% n-heptane was used in displacement experiments. 2.1.2. The aqueous phase. Solutions of magnesium chloride, [MgCl2.6H2O], (>99% purity, Merck), sodium sulfate anhydrous, [Na2SO4], (>99% purity, Merck), calcium chloride, [CaCl2], (>99% purity, Merck) were prepared. Also, combinations of these salts were prepared by dissolving the appropriate amounts of the material in deionized water (DIW). Synthetic formation brine contained 198 g/L NaCl in DIW was used to saturate the core plugs before the aging process and also in displacement experiments as the displacing phase. 2.1.3 Surfactant. The cationic surfactant, cetyltrimethylammonium bromide (CTAB), [(C16H33)N(CH3)3Br], of 99% purity was selected as a chemical agent to treated contact angle and IFT. Figure 1 represents the chemical structure of this surfactant. The Critical Micelle Concentration (CMC) of CTAB in DIW is reported in the literature to be 1.0 mM [39].

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Figure 1. Schematic of the chemical structure of the used cationic surfactant, cetyltrimethylammonium bromide

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2.1.4 Core sample. Core samples, used for flooding experiments and preparing thin sections, were taken from the outcrop of an Iranian formation with properties shown in Table 1. Samples were first cleaned by the routine cleaning procedure for cores, followed by drying in an oven and measuring their porosity/gas permeability. A schematic of the procedure used for core sample cleaning is shown in Figure 2.

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Figure 2. A schematic view of the core cleaning procedure (left) and a Soxhlet used for cleaning the core by solvents (right)

Length

Area

(cm) 3.81 3.81 3.81

(cm) 4.91 4.86 4.86

(cm2) 11.38 11.38 11.38

Kgas

φL

(mD) 3.81 8.00 4.99

(%) 4.48 12.30 13.00

Liquid pore volume (cc) 4.18 6.80 7.19

Swi (Fraction) 0.41 0.35 0.40

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A-1 A-2 A-3

Diameter

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Sample ID

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Table 1. Properties of core samples used in flooding experiments

In order to establish the connate water saturation, the rock samples were centrifuged (at 9000 rpm for 24 h.) in the presence of crude oil, and the diluted crude oil (80% crude oil/20% n-heptane) was flooded into the core plugs at 80 ℃. After that, the core plugs and the rock sections were soaked in the crude oil for about 4 weeks at 80 ˚C to restore their wettability to the reservoir condition.

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2.2. Experimental procedure 2.2.1. Contact angle and IFT measurements. Synthetic brine solutions were prepared with different concentrations of salt listed in Table 2. The contact angle and IFT (in the range of more than 2 mN/m) between crude oil and aqueous phase were measured using a Drop Shape Analysis apparatus (DSA 100, KRUSS, Germany). A Data Physics Spinning Drop Video Tensiometer SVT-20 was used to measure the IFT in the range of less than 2 mN/m. As the fluid density is required for IFT measurement, it was measured using an Anton Paar DMA 35N (Graz/Austria) densitometer. The results of density measurements are also reported in Table 2. All of the measurements were performed at ambient conditions. Table 2. The density of crude oil and synthetic brine samples (gr/cm³), containing different salts at different concentrations (ppm), at 25 ˚C and 0.09 MPa (B: a combination of magnesium chloride, calcium chloride and sodium sulfate, C: Crude oil) Salt concentration (ppm) MgCl2 CaCl2 Na2SO4 B C 0 0.9979 0.9979 0.9979 0.9979 0.9330 1000 0.9985 0.9991 0.9994 0.9989 ----

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2000 5000 10000

0.9993 1.0060 1.0012

0.9998 1.0010 1.0031

1.0021 1.0034 1.0040

0.9994 1.0014 1.0044

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2.2.2. Spectroscopy tests. For a detailed investigation of the interaction of surfactant and ions on the rock surface, a Thermo Scientific™ GENESYS 10S UV-Vis spectrophotometer was used. This apparatus utilizes a high-intensity xenon lamp and dual-beam optical geometry to deliver unsurpassed data quality. A UV-VIS spectrum was collected from 190 to 450 nm. Due to the high initial concentration of CTAB in brine, the surfactant solution was diluted by mixing 5 mL of surfactant solution with 20 mL of the base brine solution. The starting solution was further diluted to provide a series of standard solutions. UV-VIS spectrum of surfactant solution was taken and 𝜆𝑚𝑎𝑥 , the wavelength of the highest peak in the UV-VIS spectrum was recorded to be 202 nm. The absorbance at the reference wavelength for each standard solution was measured. The amount of absorbance by surfactant at different wavelengths is shown in Figure 3. For the wavelength of 202 nm, the intensity of the light passing through the reference cell was measured. This is usually referred to as I0. The intensity of the light passing through the sample cell was also measured for that wavelength, given the symbol I. If I is less than I0, then obviously the sample has absorbed some of the light. A simple calculation is then done to convert the intensity data into the absorbance of the sample, A, using the Beer-Lambert law [40,41]: A=Log10 (I0/I)

(1)

To have a more convenient comparison, surfactant concentration was used instead of absorbance. Because Beer-Lambert law applies only in the linear range of absorbance versus concentration, so the concentration of standard solutions was plotted versus the absorbance to reveal the linear region; then, these data were automatically saved in UV-Visible spectrophotometer to convert absorbance (A) to concentration.

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1.8 1.6

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A (-)

1.0

0.6 0.4

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0.2 0.0

190

210

230

250

270

290

310

Wavelength (nm)

Figure 3. Absorbance by surfactant at different wavelengths

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After preparing brine solutions with different salinities of 2000, 8000, 16000, 24000 and 48000 ppm, 200 ppm of surfactant was added to each brine solution in falcon tubes. Next, 2 g of crushed carbonate rock was added to 10 mL of the brine/surfactant solution. In order to obtain the equilibrium isotherm, the tubes were shaken for 24 hours. After achieving equilibrium, the solutions were allowed to settle for another 24 hours. The test samples were then centrifuged at 6000 rpm for 20 minutes. By means of a micropipette, samples were taken in the UV test cell. 2.2.3. Microemulsion evaluation. A high-resolution microscopic camera (HLOT) with a zoom of 500X and resolution of 3.2 megapixels was used for taking images from microemulsions formed in various solutions. A backlight (Tcl, LED Panel light, 18 W) was also used to improve image quality. 2.2.4. PZC determination. When a salt dissolves in water, both negative and positive charged species are present in the solution. There is a particular condition called the isoelectric point at which the two charges are equivalent electrically [42]. A similar situation prevails at the solid-liquid interface, for which H⁺ and OH⁻ have been shown to be potential determining. At a particular solution pH, the surface charge becomes zero which means that the surface is electrically

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neutral. This pH corresponds to the point of zero charge (PZC) [43]. When the solution pH is more than the PZC, the surface charge is negative, because negative ions and complexes are predominant at the surface. Similarly, when the solution pH is more acidic than the PZC, the surface charge will be positive [43]. Knowing the electrical properties of the solid surface is necessary to understand phenomena and mechanisms of alteration of wettability by ions or surfactants. In order to measure the point of zero charge of the rock sample, 40 mL of 0.01 M KCl solution was used as the background electrolyte. The same amount of the background solution was apportioned into 8 different tubes kept in series with increasing pH values from 1 to 14. The pH for different solutions was adjusted using NaOH and HCl. The pH was recorded using a pH meter AZ 86502. A constant mass of crushed rock (0.2 g) was added to each tube and the pH of each solution was recorded after shaking the samples for 24 h [44]. This change in pH is due to the occurrence of one of the following reactions in tubes: )2 ( CaCO3 ↔ Ca2+ + CO2− 3 2− − − )3 ( CO3 + H2 O ↔ HCO3 + OH )4 ( Ca2+ + H2 O ↔ Ca(OH)2 + H +

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Depending on the rock surface charge, each of these reactions may occur and can change pH. By plotting the change in pH versus the initial pH values, the PZC of the rock sample is obtained that is the pH at which ∆pH is equal to zero. The results depicted in Figure 4 show that the PZC of the rock sample used in this study is about 8.96. This is the point above which the surface charge of rock is negative, and below which the surface charge of rock is positive; therefore, in the range of pH used in this study (i.e., 7.00 to 8.70), the surface charge of the rock is positive. 3.00

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8.00

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6.00

10.00

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2.00

12.00

14.00

R² = 0.9935

Initial pH

Figure 4. Determination of Point of Zero Charge (PZC) for the utilized rock sample

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2.2.5. Coreflooding Tests Three limestone core samples, (with specifications shown in Table 1), were used in this study. Each core plug was mounted in a Hassler type core-holder with 60 bars confining pressure. An HPLC pump was used to deliver the displacing fluid into the core at a constant flow rate (0.1 cc/min in all water flooding experiments). First, to displace the crude oil within the plugs with fresh oil, the diluted crude oil was kept injecting into the core until the differential pressure across the core sample became constant. Next, water injection was started and the produced fluid was collected in a graduated cylinder at different time intervals. Water injection continued until no more oil was produced. A schematic of the core flooding apparatus is shown in Figure 5. The formulas developed by Toth et al. were employed to analyze the unsteadystate fluid displacement data to obtain water and oil relative permeabilities [45]. Three types of brine were used to displace oil within the core plugs A-1, A-2 and A-3 are as follows: (a) synthetic seawater (SW) prepared by dissolving MgCl2, CaCl2 and Na2SO4 in DIW with the total concentration of 50,000 ppm, (b) synthetic low-salinity (LS) water prepared using the same salts as in part (a) with the total concentration of 2000 ppm, and (3) combination of low-salinity water having a salinity of 2000 ppm and 300 ppm CTAB surfactant (LSS), respectively.

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Figure 5. Schematic of the experimental set-up for flooding tests

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3. Results and Discussion 3.1. IFT and contact angle measurement In the first part of the experiments, IFT was measured for the systems including crude oil and brine with different concentrations of MgCl2, CaCl2, Na2SO4. Each IFT measurement was repeated at least three times and the average and standard deviation values are reported. As shown in Figure 6, the IFT decreases with increasing MgCl2 and CaCl2 concentration, whereas it increases with an increase in Na2SO4 concentration.

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IFT (mN/m)

25.00 20.00 15.00

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10.00

5.00

Na₂SO₄

MgCl₂

CaCl₂

0.00

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2000

4000

6000

8000

10000

12000

Salinity (ppm)

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Figure 6. Effect of concentration of different salts on IFT between brine and the crude oil The point that the divalent metal ions such as calcium and magnesium, enhance the complexity has been reported in the literature [46]. These ions can diminish the role of the acid + base interactions between brine + oil and brine + rock interfaces [34,47,48], and thus, due to the salting-in effect, can cause the dissolution of more organic material of the oil phase in the aqueous phase. The remarkable trend in IFT values vs. MgCl2 and CaCl2 concentration (see Fig. 5) may also be related to the fact that the asphaltene within the oil, which acts as a natural surfactant, reacts with these divalent ions (MgCl2 and CaCl2) and, as a result, produces complex ions. These complex ions could be dissolved more quickly in the aqueous phase and further decrease the IFT values. Figure 6 also shows that the performance of MgCl2 in reducing the IFT between the oil and the aqueous phase is more significant than that for CaCl 2 ions, which could be the consequence of higher affinity of Mg2+ to oxygen (present in the asphaltene molecules) than Ca2+ ions [34,49]. The results of IFT measurements in the presence of Na2SO4 show a reduction between 1000 ppm to 2000 ppm and then increase as the concentration of Na2SO4 increases. The observed trend is due to the ability of Na2SO4 to facilitate the movement of natural surfactant from crude oil to the interface of the oil and the aqueous phase. In light of this fact, as the

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concentration of Na2SO4 increases, the Na+ ions will compress the double electric layer of the natural anionic surfactants at the interface. This compression in the double electric layer could cause the electrostatic repulsion forces to be weakened [34]. Hence, the intermolecular distance will reduce, which leads to a decrease in IFT by increasing the methyl group coverage fraction. Thereafter, a further increase of Na2SO4 concentration causes a reduction in methyl group coverage fraction by narrowing the intermolecular distance and so the hydrophobic chains of two neighboring molecules will overlap. Therefore, the IFT between the oil and the aqueous phase will increase.

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Following the IFT tests, the contact angle of the oil droplet on the carbonate rock sections was measured in the presence of different brine solutions as the bulk phase. The contact angles were recorded after 1 and 24 hours for the sake of better comparison. Although the previous studies showed that dilution of brine to a concentration lower than 5000 ppm is capable of changing the wettability of the reservoir rock towards the more water wet condition [50,51], in this study the magnesium ions showed better performance than the other ions in wettability alteration of the oil-wet rock as indicated in Figure 7. This was verified statistically by comparing the performance of different ions on wettability alteration using the analysis of variance (ANOVA) technique. P-values of 1.32×10-6 and 5.97×10-5 were obtained for the contact angle data of 1 hr and 24 hr, respectively. The small amounts of P-values revealed that the variation between the CA data at different ion types is high, meaning that the effect of ion type on contact angle is very significant at both levels of time. Magnesium has a small ionic radius and more positive charge density; consequently, it is more capable of removing oil compounds from the rock surface. Sulfate ions somehow altered the wettability of surface rock towards more water-wet conditions through adsorption on the rock surface.

160 126.06±0.13

120

80 60 40 20 0

52.03±0.03

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100

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135.08±0.34

45.41±0.44

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Contact angle (degree)

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Sulfate Ion

Magnesium Ion

After 1hr.

123.40±0.08

55.61±0.40

Calcium Ion

After 24hr.

Figure 7. Effect of ion type (all at the concentration of 2000 ppm) on wettability alteration of the carbonate rock

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In summary, the results of the experiments presented so far showed that all of the three ions are effective in improving wettability and IFT, although their extent of action is different. Based on these preliminary results, in the second series of experiments, brine solutions were prepared by combining all three ions, in equal proportion, but at different total concentrations, and then the pertinent IFT and contact angle were measured. The results of IFT measurement for these solutions are plotted versus total salinity as shown in Figure 8. As shown in Figure 8, the IFT decreases with increasing salinity. This was also verified by performing the statistical technique of analysis of variance (ANOVA) on the data shown in this figure and a P-value of 3.37×10-9 was obtained. The extremely small amount of P-value shows that the variability between the IFT data at different salinities is significant, meaning that IFT is closely affected by the brine salinity. Overall, it can be concluded that for seawater in comparison to diluted seawater, in terms of time of process and cost of chemicals, the effectiveness of surface-active components in lowering the IFT is more reasonable if all three ions are utilized together, compared to the cases in which they are used individually.

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30 25.00±0.01

25.00±0.04

23.50±0.13

IFT (mN/m)

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21.43±0.07 19.21±0.21

20 15 10 5 0 Distilled Water

1000

2000

5000

10000

Salinity (ppm)

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Figure 8. Effect of combination of magnesium, calcium, and sulfate (in equal proportions) on IFT between crude oil and brine with different salinities

128.08±1.17

124.21±0.87

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108.34±0.40

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60 40

89.52±0.18

78.12±1.07

64.14±0.66

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Contact angle (degree)

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Contact angle measurements also showed that the performance of the combined ions on wettability alteration of oil-wet rock sections is better than the cases in which the ions operate individually (Figure 9). However, as shown in Figure 9, this effect diminishes at high ranges of salinities. This is because, at high ranges of salinities, ions within the aqueous phase have less space to move and their interaction with each other in the aqueous phase reduces. So, their ability to detach the polar components of oil from the rock surface reduces.

20 0

1000

2000

5000

10000

Salinity (ppm)

After 1hr.

After 24 hr.

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Figure 9. Effect of combination of magnesium, calcium, and sulfate at different concentrations on contact angle

According to the IFT and contact angle data obtained at different salt concentrations, we concluded that a combination of magnesium, calcium and sulfate ions at the concentration of 2000 ppm results in a reasonable outcome. This was considered as the optimum concentration of salts in DIW in terms of IFT and contact angle. In another set of experiments, the effect of a cationic surfactant on wettability alteration and oil-water surface tension was investigated. For this purpose, a constant amount of surfactant (200 ppm) was added to the treated brines and IFT measurements were performed. Figure 10 shows the results of IFT measurements.

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0.20 0.1718±0.0004

0.18

0.1596±0.0003

0.16

IFT (mN/m)

0.14

0.1243±0.0012

0.12 0.10 0.08 0.06 0.04 0.02 0.00 1000

2000

5000

Salinity (ppm)

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Figure 10. Effect of salinity on IFT between crude oil and surfactant solution (each solution contains 200 ppm surfactant in brine with an equal proportion of MgCl2, CaCl2, and Na2SO4).

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163.02±1.6

140 120 100 80 60 40

142.11±0.57

81.54±0.23

86.27±0.07

140.43±0.11 131.24±0.13

92.60±0.79

89.70±0.16 138.64±0.26

89.25±0.24

80.60±0.14

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159.04±0.23

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Contact angle (degree)

160

lP

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Regardless of the sharp decrease in IFT in the presence of the surfactant, increasing salinity of the aqueous phase decreases the solubility of the ionic surfactant. As the electrolyte concentration increases, surfactant molecules are driven out of the brine [42]. Increasing salinity also decreases the mobility of the surfactants monomer; therefore, the surfactant monomers cannot easily reach the interface. Consequently, less IFT reduction at high salinities is observed. Also, contact angle measurement results shown in Figure 11 demonstrate that high concentrations of surfactant for wettability alteration is more effective at lower salinities (i.e., 2000 ppm). The capability of CTAB in wettability alteration towards strong water wet conditions was also previously reported for lauric acid, stearic acid and different crude oil samples [38,52,53].

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100 ppm CTAB, 200 ppm CTAB, 300 ppm CTAB, 100 ppm CTAB, 200 ppm CTAB, 300 ppm CTAB, 2000 ppm salt 2000 ppm salt 2000 ppm salt 5000 ppm salt 5000 ppm salt 5000 ppm salt

Aqueous solutions with different compositions Figure 11. Effect of surfactant concentration on contact angle at two levels of salinities (equal proportion of MgCl2, CaCl2, and Na2SO4), after 1 hr. (blue) and 24 hr. (red) We managed to conduct this study under atmospheric conditions, but, more experiments need to be performed to account for the effect of temperature and pressure. It is worth mentioning that the previous studies show that IFT between the oil and the brine phase decreases with increasing temperature and increases with rising the pressure [7,48,54–59]. However,

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the effect of temperature and pressure on the IFT of water/oil in the presence of CTAB surfactant would be different because both temperature and pressure influence the phase behavior of the system. A schematic view of the mechanism of wettability alteration of the rock surface in the presence of surfactant molecules is shown in Figure 12. Surfactant with the hydrophilic group affiliated in the aqueous phase and the hydrophobic group in the oleic phase, adsorbed at the oil molecules clinging on the surface and desorb it from the rock surface. In addition, the hydrophobic group of the surfactant molecules and also the Ca2+ and Mg2+ ions interact with long-chain hydrocarbon of the carboxylate group clinging on the positive surface charge of carbonate rock and desorb them. Therefore, oil film forms a microemulsion phase separated from the surface and the new surface of the rock is exposed to the water phase.

Figure 12. Schematic of the cationic surfactant detaching carboxylate groups from the oil-wet rock surface

𝑀𝑠 (𝐶𝑖 − 𝐶𝑓 ) 𝑀𝑅

(5)

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𝛤=

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3.2. UV-Vis spectroscopy Surfactant loss due to adsorption on the reservoir rock is one of the major concerns in enhanced oil recovery processes where this type of chemicals is used. In addition to the costs imposed on the surfactant flooding scenarios due to the adsorption of surfactant molecules on the rock surfaces, it also attenuates surfactant performance in reducing IFT and altering wettability. In this section of our study, an attempt is made to evaluate the stability of the cationic surfactant in the presence of brines with different salinities and rock surfaces. The solutions listed in Table 2 were analyzed by the UV-VIS spectrophotometer calibrated at 202 nm, the maximum wavelength absorbed by CTAB surfactant (see Figure 3), against the standard solution. Having the measured absorbance and the calibration curve, residual surfactant concentration in brine was estimated. After obtaining final concentration by UV-VIS spectra, assuming all of the lost surfactant molecules adsorbed on the rock surface, the amount of surfactant adsorption on the surface rock was estimated from material balance equation as [60]:

where 𝛤 is the amount of adsorbed surfactant on the rock surface (mg/g), Ms is the mass of surfactant solution (mg), MR is the mass of crushed rock (g), Ci and Cf (mg/L) are initial and final (residual) surfactant concentrations, respectively. From Figure 13, it can be understood that in the presence of sulfate ions, adsorption onto the rock surface occurred due to electrostatic interaction between the head group with a positive charge and the local negative charged rock surface modified by sulfate ion. A relatively sharp increase in adsorption was observed by increasing the salinity of sodium sulfate. This is attributed to change of the surface charge through the interaction of sulfate ions with the carbonate rock surface which increases the tendency of the cationic surfactant to be absorbed on the rock surfaces. In the case of magnesium ion, different trends were observed. The amount of surfactant loss decreased with increasing salinity up to a certain amount, and then it increased with rising salinity. The reason for the observed trend is that by increasing the MgCl2 concentration in the solution, initially, the repulsive forces between the Mg 2+ and the rock surface cause a reduction in surfactant adsorption on the rock surface, and then further increase in MgCl2 concentration, due to the high accumulation

11

of Cl- ions and the interactions with rock surfaces and surfactant molecules within the solution creates a tendency for surfactant molecules to attract on the rock surface. Hence, the adsorption of surfactant molecules on the rock surface increases at high concentrations of MgCl2. Moreover, at low concentrations of salts (less than 24000 ppm in this study), surfactant absorption was lower in the presence of magnesium ions than that observed in the presence of calcium and sulfate ions. The trend of surfactant absorption in the presence of calcium ions was almost similar to the trend obtained in the presence of magnesium ions. The small difference, which was appeared at low concentrations of ions, could be due to the higher charge density of Mg2+ ions than Ca2+ ions, because of the smaller ion radius of Mg2+ [61]. This produces stronger repulsive forces between the ions and the surfactant molecules within the solution. These repulsion forces are more intense at higher concentrations of Ca2+. Therefore, the trend of surfactant adsorption in the presence of the Mg2+ and Ca2+ ions becomes similar at high range of salinities (more than 24000 ppm). Hence, in our desired salinity range (<20000 ppm), the adsorption of the surfactant on the rock surface is smaller in the presence of Mg2+ more than that of Ca2+. In all of the three cases, excessive salt concentration caused the degradation of surfactant molecules and decreased their concentration in the brine. 5.5

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Γ (mg / g)

5.0

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Magnesium cloride Calcium cloride

3.0 10000

20000

30000

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Salinity (ppm)

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Figure 13. The effect of salt type on the absorbance of cationic surfactant on the carbonate rock surface

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3.3. Microemulsion generation A visual test was conducted to explore the effect of salinity on the amount of microemulsion formation. For this purpose, 10 cc of brines containing magnesium chloride, calcium chloride, and sodium sulfate, in equal proportion, at different salinities were brought in contact with 5 cc of crude oil in a static state. Images of their interfaces were taken after 24 hours are shown in Figure 14.

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Figure 14. The effect of salinity on the microemulsion formation, images are taken by a Dino-Lite microscope camera with a magnification of 500X.

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As can be seen in Figure 15, spontaneous dispersion of water droplets in oil has occurred. That is, the brines with low electrolyte concentration activate the in-situ surfactants (i.e., asphaltene) of crude oil. Because this type of surfactant is preferentially soluble in the oil phase, water-in-oil microemulsion forms. Figure 15 schematically reveals that the likely reason for the spontaneous dispersion of water droplets in the oil without any external surfactant. Water in oil emulsion was formed because of the interactions between asphaltene molecules and divalent cations in the aqueous phase. Due to the weak hydrophilic part of in-situ surfactants, the process of microemulsion formation may be readily reversible, especially at high concentrations of ions.

Figure 15. Schematic of the microemulsion formation mechanism without external surfactants, the image was taken by a Dino-Lite microscope camera with a magnification of 500X

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The microemulsion formation mechanism was further studied by repeating the previous experiments with the only difference that surfactant at a specific concentration was added to the system. In Figure 16, every three bottles with equal salt concentration are in one group, while each bottle in a group has different surfactant concentrations that are 100, 200 and 300 ppm from the left to the right, respectively.

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Figure 16. Microemulsion formation in surfactant/brine/crude oil system (A): 100 ppm CTAB, (B): 200 ppm CTAB, (C): 300 ppm CTAB

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In general, upon increasing the salinity of a brine phase, the solubility of an ionic surfactant decreases. This means that surfactant comes out of brine as the electrolyte concentration increases, showing that brine salinity has a significant effect on the phase behavior of the surfactant system. Winsor classified the microemulsion phase equilibria into four categories. Type I system which is formed of oil in water microemulsion in equilibrium with an extra oil phase. Type II system which is formed of water in oil microemulsion in equilibrium with an extra aqueous phase. Type III system which is formed of a three-phase system containing extra oil and aqueous phases in equilibrium with a microemulsion phase containing oil, water and surfactant. Type IV is formed of a single-phase system, with uniformly mixed surfactant, water, and oil [62,63]. The visualization test results shown in Figure 16 illustrated that at relatively low brine salinities, solutions were converted into water external microemulsion and an excess-oil phase. Because the microemulsion is the aqueous phase and its density is higher than the oil phase, it resides below the oil phase and is called a lower-phase microemulsion, which Winsor named that the type I microemulsion [64]. There are two phases in the system, oil, and microemulsion; however, because of the dark color of crude oil, the interface between these phases is not clearly detectable. As seen in Figure 16, brine with 2000 ppm salt concentration is of particular interest because of its ultralow IFT. It is clear that at this salinity, high solubilizations of oil and water were achieved by the microemulsion. The results of these experiments also show that the effect of salt concentration on the type of microemulsion formation is more intense compared to the effect of surfactant concentration. Although the formation of microemulsions decreases the IFT between the oleic and aqueous phases, it could induce operational issues in flooding experiments which are discussed in the following.

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3.4. Flooding experiments The combined effect of surfactant and low salinity brine in altering the wettability of carbonate rock at the dynamic state was further evaluated using water/oil relative permeability tests. As shown in Figures 17(a-c), there is a remarkable shift in water saturation (Sw) at cross-point from about 52% in the SW flood (core A-1) to 61% and 67% in the low salinity (core A-2) and the low salinity surfactant scenarios (core A-3), respectively. This shift in the cross-point saturation from SW to LS scenario is most likely because of changing rock wettability from oil-wet to approximately water-wet or intermediate wet. However, in the A-3 case, the phenomenon cannot be related to the wettability alteration. The reason is that when a surfactant is added to the injected water, emulsion formation occurs which causes flow problems so that the shift in the cross-point Sw is due to rising differential pressure as shown in Figure 18. Overall, it can be concluded that wettability alteration by ions has a greater effect on oil production as compared to IFT reduction by surfactant.

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0.8 Kr(Oil)

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Relative permeability

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Water saturation (Fraction) (c) Figure 17. Relative permeability curves for (a) seawater/crude oil system (core A-1), (b) low-salinity/crude oil system (core A-2) and (c) low-salinity-surfactant/crude oil system (core A-3)

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Figure 18. Pressure drop across the inlet and outlet faces of core sample (after breakthrough) during SW, LS and LSS flooding

Table 3. Comparison of the results of relative permeability tests Kw @ Sor Sw @ cross-point (%) Soi (%) Sor (%) 0.72 52 59 19 0.57 61 65 18 0.53 67 60 13

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Scenario A-1 A-2 A-3

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A summary of the results obtained from relative permeability curves for three different flooding scenarios is shown in Table 3. Decreasing the endpoint of the water relative permeability curve and increasing water saturation at cross-point from A-1 to A-3 scenario prove wettability alteration towards more water-wet.

Sor /Soi 0.32 0.28 0.22

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Figure 19 shows the fraction of original oil in place (OOIP) which was recovered vs. pore volume of injected fluid for three scenarios. As listed in Table 3., the ratio of residual to initial oil saturation (Sor/Soi) has been reduced from 0.32 for SW flooding to 0.28 and 0.22 for LS and LSS flooding, respectively. Reduction of residual and initial oil saturation ratios (Sor/Soi) for core samples A-2 and A-3, strongly confirm the enhanced oil recovery due to the injection of LS and LSS in comparison to SW flooding. This result is inconsistent with the contact angle and IFT measurement results obtained by combining low-salinity bine and surfactant reported earlier. The likely reason could be emulsion formation, which could dramatically reduce the displacement efficiency of the low-salinity-surfactant solution.

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Figure 19. Oil recovery during SW, LS and LSS flooding and the ratio of residual to initial oil saturation (Sor/Soi) of core samples used for each flooding scenario

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4. Conclusions Effectiveness of calcium, magnesium, and sulfate ions for reduction of IFT and modification of contact angle of carbonate rock surface was investigated at different levels of salinity. The results indicated that, in an aqueous solution, the calcium and magnesium ions could significantly reduce the IFT and modify the CA, while these effects were weak for the sulfate ion. Subsequently, effect of the simultaneous presence of all three ions in an aqueous solution was further investigated, indicating intensified changes to the wetness (i.e., contact angle). The results also showed that the presence of the CTAB surfactant imposes better contributions to IFT reduction at lower concentrations of the electrolyte. Producing in-situ surfactant, the saline water forms some water-in-oil microemulsion. The presence of such micro-emulsions tends to damage the formation, leading to increased injection pressure when performing flooding tests, with the presence of the surfactant facilitating the movement of the formed microemulsion. The oil and water relative permeabilities plots imply that the Krw@Sor decreases significantly with reducing the level of salinity, confirming the modification of the wetness of the pore surface of the rock. Upon modification of the pore surface wettability toward waterwetness, carboxylate groups of the crude oil are detached from the surface and replaced with the aqueous solution. Consequently, the aqueous solution further enters the small pores of the rock sample, reducing the mobility of the aqueous solution in the porous medium. This can be inferred considering the shift of the intersection of the oil and water relative permeabilities curves as one moves toward higher water saturations. Finally, the results of core flooding tests on the plug samples showed that residual oil saturation to initial oil saturation ratio (S or/Soi) decreased from an initial value of 0.32 for the seawater to 0.28 for low salinity water and 0.22 for the low salinity surfactant solution. In brief, it could be concluded that the addition of small amounts of surfactant in the presence of the existing salts in the seawater at controlled concentrations can result in reduced IFT, modified wetness, and hence enhanced oil recovery. Accordingly, this flooding methodology can be used in carbonate reservoirs, and as showed, the simultaneous presence of these ions at controlled concentrations not only contributes to reduced cost of ion separation but also enhances the oil recovery.

Authors contributions Derikvand: Conceptualization, Methodology, Software, Validation, Formal analysis, Investigation, Data curation, Writing original draft, Writing-Review & Editing, Visualization, 17

Rezaei: Methodology, Software, Validation, Formal analysis, Investigation, WritingReview & Editing

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Parsaei: Conceptualization, Methodology, Software, Formal analysis, Resources, Writing-Review & Editing, Supervision, Funding

Riazi: Conceptualization, Methodology, Resources, supervision, Project administration, Funding

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Declarations of interest: none

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Torabi: Writing-Review & Editing

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Acknowledgments The authors would like to thank the Enhanced Oil Recovery Research Center of Shiraz University and Abdal Industrial Projects Management Co. (MAPSA) for the technical support of this study.

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