Experimental Investigation of Wettability Alteration of Oil-Wet

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Experimental Investigation of Wettability Alteration of Oil-wet Carbonates by Nonionic Surfactant Maissa Souayeh, Rashid S. Al-Maamari, Mohamed Aoudia, Mahvash Karimi, and Moundher Hadji Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.8b02373 • Publication Date (Web): 26 Sep 2018 Downloaded from http://pubs.acs.org on September 29, 2018

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Experimental Investigation of Wettability Alteration of Oil-wet Carbonates by Nonionic Surfactant Maissa Souayeh1, Rashid S. Al-Maamari1,*, Mohamed Aoudia2, Mahvash Karimi1, and Moundher Hadji3 1

Department of Petroleum and Chemical Engineering, College of Engineering, Sultan Qaboos University, P.O. Box 33, Muscat 123, Oman

2

Department of Chemistry, College of Science, Sultan Qaboos University, P.O. Box 36, Muscat 123, Oman 3

Corporate Research and Development Direction, Sonatrach, Avenue 1 Novembre 35000, Boumerdes, Algeria

ACS Paragon Plus Environment

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ABSTRACT: Wettability alteration towards more water-wet state was found to be a promising approach for oil recovery improvement in oil-wet and naturally fractured carbonate reservoirs. This approach has been extensively studied in literature using low salinity/smart water and surfactant injection separately. However, application of surfactants in enhanced oil recovery is limited by their compatibility with the reservoirs’ conditions. In this study, polyethoxylated nonionic surfactants with different EO units were combined with low salinity brine for more efficient and cost effective process. The compatibility of the surfactant solutions highly improved by reducing the salinity in the range of 200 to 2 g/L. IFT measurements revealed that IFT decreased with increasing salinity. Contact angle measurements of calcite surfaces showed that wettability can be altered from strong oil-wet to water-wet state after treatment with nonionic surfactants’ solutions over a wide range of salinities (~2 – 110 g/L). Zeta potential, FTIR and TGA analysis revealed that the nonionic surfactant could partially displace carboxylate compounds from the surface and adsorb by forming hydrogen bond with the hydroxyl group on the calcite surface. The formation of hydrogen bonds between ethoxy groups of surfactant and hydroxyl groups or carboxylic groups on the solid surface can result in the replacement of organic compounds on the calcite surface. The organic compounds could form a new layer on the adsorbed surfactant molecules’ layer via hydrophobic interactions. In addition, adsorption of hydrophobic part of the nonionic surfactant on the hydrophobic calcite surface and formation of a surfactant double layer could partially contribute to the wettability alteration process.


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1. INTRODUCTION More than 50% of discovered oil reserves are found in carbonate formations. Most of these formations are known to be oil-wet and naturally fractured. The efficiency of waterflooding is often low in these reservoirs due to oil microscopic trapping and macroscopic bypassing.1,

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Injected water bypasses the matrix blocks through fractures and cannot invade the matrix blocks to displace oil. If water can overcome a capillary barrier, then suction of water into the matrix blocks leads to expelling oil towards fractures and accordingly to production wells. Interfacial tension (IFT) reduction along with wettability alteration toward a water-wet state can overcome oil retention caused by capillarity.3 Wettability alteration to a preferentially water-wet state was found to be a promising approach for improving oil recovery in oil-wet and naturally fractured carbonate reservoirs.3-5 Low salinity waterflooding and smart water injection have shown a great potential for wettability alteration towards water-wetness in carbonate formations.6-10 Nevertheless, the incremental oil recovery by such techniques is still not satisfactory.11 Besides, surface-active agents can reduce the capillary barrier by IFT reduction and wettability alteration to preferentially water-wet conditions. Application of different types of surfactants as wettability modifying agents has been extensively investigated.3,

12-22

It is believed that cationic surfactants can change wettability of oil-wet

carbonates to water-wet state irreversibly. However, their application is limited due to high cost. Anionic surfactants are found to be less effective in wettability alteration of oil-wet carbonate rocks compared to cationic surfactants and results in higher amount of adsorption on the rock surface.3 Nonionic surfactants are mainly used as co-surfactant to enhance the compatibility of ionic surfactant.23 Few studies used nonionic surfactant alone in carbonate reservoirs. It is reported that nonionic surfactants at high concentrations (up to 0.35 wt.%) can alter the


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wettability of oil-aged carbonates towards a less oil–wet to intermediate-wet state.24 In addition, some studies showed that nonionic surfactants could change the wettability of oil-wet carbonate towards water-wet state.21,

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Despite the lower cost of nonionic surfactants, their activity is

limited due to poor compatibility with high salinity and high temperature.26,

27

Figure 1

summarizes salinity and temperature conditions of several studies that used nonionic surfactant alone as a wettability modifying agent in carbonates. As shown in the figure, mainly at high temperatures, application of nonionic surfactants is limited to low salinities. On the other hand, few reported studies were conducted at higher temperatures and salinities. To overcome this limitation, a combination of low-salinity brine and nonionic surfactant can be used. Combinations of low salinity and surfactant effects, wettability alteration toward a favorable wetting state and IFT reduction could improve oil recovery remarkably from high-temperature oil-wet carbonates. Several studies in sandstone reservoirs showed that surfactant assisted low salinity or low salinity surfactant, can result in high oil recovery and overcome some of the limitations associated with using each technique alone.28-34 The results of these studies revealed that noticeable improvement in oil recovery was achieved with a collaborative contribution of mobilization of oil by IFT reduction and wettability alteration. The same approach can be extended to carbonate reservoirs. The present study tried to combine polyethoxylated nonionic surfactant with low salinity brine through conventional dilutions. In such combination, the compatibility of the nonionic surfactant can be enhanced. Furthermore, an attempt has been made to tailor the nonionic surfactant through modifying the number of ethylene oxide (EO) units in the hydrophilic group generating different surfactant systems, which can be used at different fields’ conditions. Low salinity nonionic surfactant systems with different EO units, C13EOx (x = 12, 16 and 20), were evaluated


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using cloud point and IFT measurements. Contact angle was utilized to examine effect of the low salinity surfactant solutions on wettability alteration of oil-wet calcite surfaces. In addition, zeta potential measurements, Fourier transform infrared (FTIR) spectroscopy and thermogravimetric analysis (TGA) were used to characterize changes of calcite surfaces. Observations from these experiments provides a better understanding of the dominant mechanisms of wettability alteration process after surface treatment with anionic surfactant solutions.

2. MATERIALS Oil. Crude oil sample was provided by Petroleum Development Oman (PDO) from a carbonate reservoir. The properties of used crude oil are summarized in Table 1. The oil was decanted and filtered before experiments in order to remove water traces and any coarse particles. Brines. Synthetic formation brine was prepared based on the compositional analysis of the reservoir formation water. In order to investigate the effect of salinity, various dilutions (100 times, 20 times, 10 times, 4 times, 2 times) of this synthetic brine were prepared by adding deionized water (DIW). Synthetic formation brine composition is shown in Table 2. NaCl (Daejung, >99.5%), CaCl2.2H2O (Daejung, ≥98%), MgCl2.6H2O (Daejung, ≥98%) and Na2SO4 (Sigma Aldrich, ≥99%) were used to prepare the synthetic brine. Surfactants. Two series of polyethoxylated nonionic surfactants H27C13-(OCH2CH2)7OH, (C13EO7), and H27C13-(OCH2CH2)20OH, (C13EO20), provided by Sasol were used in this study. Surfactants are 100% active. These two surfactant were mixed at different proportions to produce different EO group numbers C13EOx given by C13EOx = (7 fC13EO7) + (20 fC13EO20)

(1)


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where fC13EO7 and fC13EO20 are the molar fractions of C13EO7 and C13EO20, respectively. According to the supplier, C13EO7 and C13EO20 revealed similar EO Gaussian distribution with a maximum at 7 and 20, respectively. In this study, surfactant solutions were prepared at concentration of 0.3 wt. % which is well above the critical micelle concentration (CMC). Solid surfaces. Iceland spar calcite crystals provided by Ward’s Science were used in this study as solid surfaces to mimic the carbonate rock for wettability alteration. The calcite crystals were cut using a sharp blade along the cleavage plane and then polished using fine polishing plates. Then, the solid surfaces were rinsed with DIW and dried overnight at 50 °C. These surfaces were used for contact angle measurements. Some of the calcite crystals were crushed and then sieved to obtain particles in the range of 50 to 125 µm. The calcite powder sample was characterized using X-Ray diffraction (XRD) as shown in Figure 2. The main peak was obtained at 29.43°, which indicated that the sample was pure calcite.

3. METHODS 3.1. Cloud point measurements Cloud point measurements were conducted by immersing sealed glass tubes containing 5 ml of surfactant solutions at different salinities into a temperature-controllable water bath. The temperature at which the clear solution turn turbid was detected visually and it was considered as the cloud point of the system. 3.2. Interfacial tension measurements The interfacial tension measurements were performed using a spinning drop tensiometer, SVT 10 Data Physics. In all measurements, a drop of crude oil (~ 1-2 µL) was injected into a capillary


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tube containing 1 ml of the surfactant solution at different salinities. The spinning speed and temperature were set at 4000 rpm and 75 °C, respectively.

3.3. Treatment of calcite surfaces and powder Calcite surfaces were first soaked in the formation brine for 2 hours at 75 °C to mimic the presence of the original brine film on the rock surface. After that, the surfaces were aged in crude oil for 3 weeks at 75 °C to restore the original wettability. Then, the surfaces were rinsed with toluene and n-heptane in order to remove any extra crude oil on the surface and dried overnight.15, 16 As for the calcite powder, it was first aged in formation brine for 2 hours using orbital shaker at 180 rpm and 75 °C. Then, the brine was removed and the crude oil was added (10 ml of crude oil per 1 g of calcite). The powder was aged for 10 days using orbital shaker at 180 rpm and 75 °C. The calcite powder was then rinsed with n-heptane to remove the excess crude oil and then centrifuged for 20 min at 6000 rpm to separate the powder. Finally, the oilaged powder was dried in an oven at 120 °C overnight to evaporate any n-heptane traces.

3.4. Contact angle measurements Contact angle measurement was used to examine the wettability alteration of calcite surfaces after treatment with different surfactant solutions. The oil-wet calcite surfaces were soaked in the treatment solutions (low salinity surfactant solutions) for 48 hours at 75 °C. Figure 3 shows the set-up used for contact angle measurements. The calcite surface is placed at the edge of the glass cube filled with formation brine and a drop of crude oil was placed beneath the surface. The drop was left for few minutes to reach equilibrium and then the angle was measured using DinoCapture 2.0 imaging software.


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3.5. pH measurements pH of the low salinity surfactant solutions was measured before and after calcite surface treatment using Mettler Toledo SevenCompact pH meter.

3.6. Fourier transform infrared (FTIR) analysis Fourier transform infrared (FTIR) spectroscopy was used to identify the structure changes of functional groups of compounds adsorbed on the oil-aged calcite after treatment with surfactant solutions. Perkin-Elmer Frontier FTIR spectrometer was used to record the spectra in the range of 400 - 4000 cm-1. All spectra were acquired by averaging 40 scans at a resolution of 4 cm-1. For analysis, 1 mg of the sample was added to 99 mg of KBr, the mixture was compressed using a pallet die for 15 minutes and the applied force was 10 tons.

3.7. Thermogravimetric analysis (TGA) Thermogravimetric analysis (TGA) was conducted to characterize and measure the weight loss of the calcite powder sample before and after treatment with low salinity surfactant solutions when heated from 30 to 990 °C. A Perkin-Elmer Model STA 6000 system was used to perform TGA analysis. Around 20 µg of the sample was placed in an alumina pan and heated at 10 °C/min under a constant flow of nitrogen (20 mL/min).

3.8. Zeta potential measurements Zeta potential measurements were conducted using Anton Paar SurPass analyzer. 0.15 mg of the sample was pressed to a uniform disk and loaded to the system. A stream of 0.001 M KCl


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solution flowed through the sample. During the rinsing process, zeta potential was measured across the disk. The pH was adjusted to 8 using 0.05 M HCl and 0.05 M NaOH. The measurements were repeated at least three times and the average value of zeta potential is reported.

4. RESULTS AND DISCUSSION 4.1. Surfactant solutions’ compatibility and IFT reduction At the cloud point, the nonionic surfactant molecules will separate from the solution creating two immiscible phases: a phase containing very high concentration of surfactant and a phase containing low surfactant concentration equals to its CMC value.35 This makes the cloud point an important parameter for various surfactant applications in oilfields, for example, surfactant flooding, drilling and stimulation.36 Separation of surfactant from the solution by clouding phenomena may plug the formation resulting in poor productivity or injectivity.37 In addition, surfactant loss due to retention or adsorption at and above the cloud point is promoted.38 Figure 4 shows the cloud point measurements of the surfactant solutions with varying EO units (12, 16, and 20) as a function of salinity. The results showed that at any given salinity, the cloud point increases with increasing the degree of ethoxylation. This trend of the cloud point of nonionic surfactant is well addressed in the literature39 and it is due to increasing solubility of hydrophilic portion of the surfactant with increasing EO units. The ether oxygen atoms in the structure of the EO units of the surfactant can form hydrogen bonds with water molecules. This leads to high solubility of nonionic surfactant in water.40, 41 Similar finding is reported by Sharma and Mohanty (2013)2, where they concluded that the cloud point reaches a plateau with increasing the number of EO units beyond 30.


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Furthermore, Figure 4 shows that the cloud point increases with decreasing salinity for three tested nonionic surfactant systems. The salt content of the brine solution influences the solubility of the surfactant molecules remarkably. Presence of anions and cations, except divalent ions (Mg2+ and Ca2+), in the brine leads to the formation of water clusters and as a result, the free water molecules to form hydrogen bonding with the EO units of the surfactant decreases.39-44 Therefore, the solubility of organic compounds in the aqueous phase can be improved by removing salt from the water.45 Figure 4 (inset) shows the effect of concentration on the cloud point of the surfactant solutions prepared at formation brine salinity (196 g/L). . Insignificant increase in the cloud point (< 2°) was observed when the surfactant concentration decreased from 1– 0.1 wt. %. The slight decrease in cloud point with increasing concentration is due to increase in micelle concentration, which enhances micelle-micelle interactions resulting in phase separation.40 Figure 5 shows the IFT measurements of clear surfactants solutions at 75 °C, obtained from the cloud point survey at different salinities. The IFT measurements revealed that at any salinity, the IFT increases with increasing the degree of ethoxylation. This observation is in line with the findings of Sharma and Mohanty (2013).2 The more surfactant molecules adsorbed at the oil/water interface, the lower is the resultant IFT. As the number of EO units increases, the size of the surfactant molecule becomes larger and the surface area per molecule at the oil/brine interface increases. This leaves fewer molecules at the interface compared to the surfactant having lower number of EO units and the IFT increases.46 The IFT decreased with increase in salinity as shown in Figure 5. It was found that the minimum IFT was in the order of 10-2 mN/m and was achieved at the salinity with a cloud point close to the reservoir temperature (around 1 °C above 75 °C). Hadji et al. (2016)47 reported a


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similar trend, where they tested three alkyl ether surfactants C13EOx (x = 10, 13 and 18) and the lowest IFT at the oil-water interface was obtained for the surfactant closest to its cloud point at the measuring temperature. Possible explanation of such trend is that, at increased salinity closer to the cloud point the hydration of the EO chain is reduced. Na+ and Cl- could remove the hydrated water molecules around the surfactant and decrease the solubility of the surfactant. Hence, more surfactants tend to transfer to the oil/water interface or into the oil phase. As a result, the concentration of the surfactants at the interface increases and IFT decreases.48 Dynamic IFT of three nonionic surfactant systems at 75 °C and salinity of 1.96 g/L is depicted in Figure 6. It is clear that the IFT reach equilibrium faster with increasing EO units. As stated earlier, the size of the molecule increased with increasing EO units and as a result the oil/brine interface would be saturated faster as it would require less number of molecules and hence the equilibrium would be reached faster.46

4.2. Aging of calcite surfaces in crude oil Wetting properties of calcite surfaces before and after aging in crude oil were characterized using different techniques: contact angle measurements, zeta potential measurements, TGA and FTIR. Characterization of calcite surfaces can help to identify the main changes of surface after aging process as well as after surface treatment with surfactant solutions. Figure 7 shows contact angle and zeta potential measurements of calcite surface before and after aging in crude oil. The contact angle of the fresh polished calcite surface was measured to be 34°, which indicates a strong water-wet condition. After aging in crude oil at 75 °C, the average contact angle of 160° was achieved indicating a strong oil-wet condition. During the aging process, acidic components of crude oil adsorbed on the surface and hence altered its


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wettability. Zeta potential was measured at ambient temperature and pH of 8 for fresh and agedcalcite (Figure 7). The zeta potential of fresh calcite was +8.0 mV. After aging in crude oil, the zeta potential decreased to negative value of -26.7 mV. This can be interpreted by the adsorption of the negatively charged carboxylic acids on the calcite surface during the aging process. Thermo-gravimetric analysis was used to investigate the amount of adsorbed components on the calcite particles. Figure 8 presents the weight loss versus temperature for fresh calcite and oil-aged calcite when temperature increases from 30 to 800 ºC. As can be seen for the fresh calcite sample, from 30 to 570 ºC the weight of the sample was almost constant. From 570 ºC onwards, a slow decomposition of calcite starts. A sharp weight loss was observed after 600 ºC. These observations are in good agreement with those reported in the literature.49-52 For the oilaged sample, a rapid weight loss was observed when the temperature increased from room temperature to around 100 ºC. The weight loss in this region can be attributed to desorption of water molecules from the surface. When the temperature increased from 100 °C to 150 °C, physically adsorbed components removed from the surface and caused a relatively sharp weight loss.52,

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For the temperature range of 200-500 ºC, elimination of chemically adsorbed

compounds from the surface resulted in an apparent weight loss of the oil-aged sample. Finally, decomposition of calcite (CaCO3 → CaO+CO2) caused a sharp weight loss when the temperature increased from 570 °C. Comparison between TGA curves of fresh calcite and oil-aged calcite samples revealed physical and chemical adsorption of organic compounds on the calcite surface during the aging process. To identify the molecular structure of the adsorbed compounds on the calcite surface after aging in crude oil, FTIR analysis was performed. In addition, attenuated total reflection (ATR) FTIR analysis was conducted to examine the crude oil sample. Figure 9 shows the FTIR spectra


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(absorbance mode) of fresh calcite and oil-aged calcite samples as well as ATR-FTIR spectrum of the crude oil sample within the wavenumber range of 4000 – 400 cm-1. The calcite is identified by the broad smooth band at 1427.99 cm-1 that is attributed to the asymmetric stretching of C-O and a smaller sharp band at 1798.86 cm-1 attributed to the symmetric stretching of C-O. The bands at 712.38 cm-1 and 876.06 cm-1 are resulted from in-plane and out-plane deformation vibration of the planar carbonate anion unit, respectively. These observations are in good agreement with those reported in the literature.54-57 The band at 3447.79 cm-1 is assigned to the O-H stretching vibration, which is referred to adsorbed water molecule on the surface.52, 53, 58, 59

The FTIR spectrum of oil-aged calcite sample showed the presence of methyl and methylene C-H stretching vibration bands. As can be seen in Figure 9, the adsorbed bands are matching with the bands obtained from ATR-FTIR analysis of the crude oil sample within the same range of wavenumber. ATR-FTIR spectrum illustrates the characteristic bands at 2957.49 cm-1, 2918.97 cm-1, 2873.63 cm-1 and 2850.13 cm-1 that are ascribed to methyl symmetric C-H stretching vibrations, methylene asymmetric C-H stretching, methyl asymmetric C-H stretching, methylene symmetric C-H stretching vibrations, respectively.59-61 The peak at 1631.94 cm-1 that appeared in the oil-aged calcite sample can be attributed to the stretching of the carboxylic group. ATR-FTIR of the crude oil sample shows bands at 1370.56 cm-1, 1458.45 cm-1 and 1605.88 cm-1 which are assigned to the symmetric deformation of C-H, asymmetric stretching vibration of carbonyl group C-O and bending vibration of carboxylic acid C-O-H, respectively. However, these bands were overlapped by the intense symmetric peak of calcite at 1427.99 cm-1 and they are absent in the FTIR spectrum of oil-aged calcite.59, 61 Deviations in band symmetry of the main calcite characteristic band, a broad smooth band at 1427.99 cm-1, confirms the


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existence of overlapping bands. Presence of adsorbed water on the calcite surface resulted in the O-H stretching vibration peak at 3432.57 cm-1 in the FTIR spectrum of oil-aged calcite.

4.3. Treatment of oil aged calcite surfaces with low salinity surfactant solutions The potential of different nonionic surfactant systems to modify wettability of oil-wet calcite surfaces were investigated using contact angle measurements. The measurements were performed at surfactant concentration of 0.3 wt.% over a salinity range of 1.96 – 109.7 g/L. For each nonionic surfactant, clear systems were considered (1.96 – 9.8 g/L, 1.96 – 78.3 g/L and 1.96 – 109.7 g/L for C13EO12, C13EO16 and C13EO20, respectively). The results of contact angle measurements for oil-aged calcite surfaces after treatment with low salinity nonionic surfactants are shown in Figure 10. Contact angle measurements for different brine dilutions are also presented in the Figure. As can be seen, various brine dilutions could slightly affect wettability of oil-wet calcite surface. The contact angle of the calcite surface after treatment with formation brine was 156° indicating strongly oil-wet state. However, minimum contact angle of 108° was obtained at salinity of 19.6 g/L. The effect of low salinity on wettability alteration of carbonate surfaces has been widely investigated with no clear conclusion.6-10, 62-64 Chen et al. (2018)62 have investigated the effect of reduction of salinity level on wettability alteration of aged carbonate surfaces. They observed that the wettability of carbonate surfaces shifted towards more oilwetness with reduction of brine salinity. Alameri et al. (2014)65 observed wettability alteration from oil-wet to intermediate-wet in oil-aged carbonate surfaces as brine salinity decreased. Saikia et al. (2017)64 have reported that there is an optimum dilution, which results in a pronounced wettability alteration. Similar findings were presented in the literature.65-67 In the


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present study, none of the brine dilutions could alter the surface wettability to a water-wet state. Hence, wettability changes of surfactant systems can be attributed to the nonionic surfactant on the surface not the low salinity effects. Figure 10 shows that all surfactant solutions were able to alter the wettability from strongly oil-wet towards water-wet state (~ 30 – 60°) in the studied salinity range. As can be seen from the figure, there is no clear trend for the effect of salinity on wettability alteration of surfactant systems. As an example, negligible changes of contact angle were observed after treatment of the oil-aged surface with C13EO12 when salinity changes from 1.96 – 9.8 g/L. Similar trend was observed for the surfaces treated with C13EO16 when salinity changes from 9.8 – 78.3 g/L. It is interesting to note that contact angles of the calcite surfaces treated with C13EO20, were slightly lower in the salinity range 19.6 – 49 g/L. However, the minimum contact angle was achieved at 109.7 g/L where it gave strong water-wet state with an angle of 27°. The results of contact angle measurements showed that the treatment of calcite surfaces with C13EO20 which has the highest degree of ethoxylation, resulted in lower contact angles. To explain the experimental results obtained from contact angle measurements, two possible mechanisms of wettability alteration by polyethoxylated nonionic surfactant can be proposed: (1) Adsorption of hydrophobic part of the nonionic surfactant on the hydrophobic calcite surface and the formation of a surfactant double layer could be a possible interpretation of the wettability alteration process. Therefore, hydrophilic ethoxy groups in the surfactant structure could alter the surface wettability towards water-wetness by forming hydrogen bonds with water molecules (Figure 11a). (2) It has been reported that hydrogen bonding can occur between ethoxy groups of surfactant and hydroxyl groups or carboxylic groups on the solid surface.68 In the presence of ethoxy


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groups in surfactant structure, organic compounds on the calcite surface could be replaced. Surfactant molecules could occupy active sites of the calcite surface. Then, organic compounds could form a new layer on the adsorbed surfactant molecules’ layer via hydrophobic interactions (Figure 11b). When carbonate surface is in contact with water, the pH of the solution increases due to calcite dissolution. The reaction is expressed by: CaCO3 (s) + H2O ↔ Ca2+ + HCO3- + OHAs shown in Figure 12, pH increased to around 7-8 for all systems. Hence, partial dissolution of calcite resulted in an increase in concentration of hydroxide ions in solutions. It has been reported that an ion exchange between adsorbed carboxylate compounds on the surface and hydroxide ions can occur.59 Consequently, carboxylate compounds can be released from the surface and replaced by hydroxide ions. As adsorption of polyethoxylated nonionic surfactant is through the formation of hydrogen bonding between EO units and hydroxyl groups on the surface 35, 69, the presence of hydroxyl groups on the calcite surface could enhance adsorption of the surfactant. This reinforces the hypothesis of wettability alteration by mechanism No. (2). The zeta potential as well as contact angle measurements of the treated surfaces with nonionic surfactants at salinity of 1.96 g/L are presented in Figure 13. The zeta potential results revealed that the negative charge of the surface slightly decreased as the number of EO units increased. However, the zeta potential changes were over a narrow range (less than 4 mV). As mentioned earlier, zeta potential of the oil-aged calcite was measured to be -26.7 mV. Zeta potential measurements of surfaces after treatment with nonionic surfactant revealed negligible changes compared to that of oil-aged calcite surface before treatment. Contrary to zeta potential measurements, contact angle results show considerable changes after surfactant treatment. It


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appears that if surfactant adsorption occurred during treatment, electric charge of the surface was not disturbed. In case the first proposed mechanism (Figure 11a) is the active mechanism of wettability alteration, the surface charge would be expected to be unaffected. In this mechanism, the surfactant molecules form a double layer on the adsorbed carboxylate on the solid surface. However, the formation of the double layer via weak hydrophobic interactions is reported to be reversible process14 which could not displace the adsorbed carboxylate from the surface. On the other hand, in the second proposed mechanism possibility of desorption of carboxylate compounds from the surface as well as hydroxide adsorption on the surface, could slightly affect the surface charge. The results obtained from zeta potential, strengthen the second hypothesis of wettability alteration. FTIR analysis of the oil-aged calcite sample after treatment with surfactant solutions (C13EO12 and C13EO20) along with ATR-FTIR analysis of the surfactant stock solutions (C13EO7 and C13EO20) are displayed in Figure 14. The nonionic surfactant is characterized by the strong etheric C-O stretching bands53 placed at 1103.26 cm-1 and 1106.58 cm-1 for C13EO7 and C13EO20, respectively. The bands at 2860.51 cm-1 and 2864.06 cm-1 attributed to the symmetric stretching C-H methylene group in C13EO7 and C13EO20, respectively. In addition, C13EO7 displayed other two bands at 2954.87 cm-1 and 2922.45 cm-1 ascribed to asymmetric stretching of methyl (C-H) and methylene (C-H) groups. These two bands were overwhelmed by the symmetric stretching C-H methylene band at 2864.06 cm-1 for C13EO20. This may be attributed to the fact that this surfactant contains more EO units with higher molecular weight (1080 g/mole) compared to C13EO7 (508 g/mole). FTIR analysis of the oil aged calcite treated with surfactant solutions at salinity of 1.96 g/L (solid lines) are also shown in Figure 14. After treatment of oil-aged calcite surfaces, the intensity of the band at 1605.88 cm-1 attributed to the bending vibration of


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carboxylic acid C-O-H was reduced. This suggests the partial removal of the adsorbed carboxylate groups from the surface, which can modify its wettability toward water-wetness state. Moreover, the symmetric and asymmetric stretching vibrations’ bands of methyl and methylene groups were detected. These bands can be assigned either to the remaining adsorbed carboxylate groups or adsorbed surfactant molecules. The sample treated with C13EO12 shows a higher intensity of methyl symmetric and asymmetric stretching vibrations as well as the bending vibration of carboxylic group compared to C13EO20. Moreover, due to overlapping with the characteristic broad carbonate band of calcite at 1428 cm-1, the characteristic etheric C-O stretching band of surfactant appears as very lowintensity peaks on the absorbance spectra. These evidences support the adsorption of the surfactant molecules on the calcite surfaces and partial desorption of carboxylates from the surface during the treatment process. It is interesting to note that etheric C-O stretching band has higher intensity for the sample treated with C13EO12 compared to that of C13EO20. This can lead to that adsorption of surfactant on the calcite surfaces decreases with increasing EO units.69-71 Finally, TGA analysis was conducted for oil-aged samples treated with C13EO12 and C13EO20 at 1.96 g/L. Figure 15 shows the measured weight of the sample as a function of temperature in the range of 30 – 715 ºC. As stated earlier, calcite decomposition occurs at 570 ºC indicated by the rapid loss of weight above that temperature. Similar to the oil-aged sample, TGA curves of the treated calcite samples show two stages of weight loss. The first stage is in the temperature range of 30 - 150 ºC describing weight loss for physically adsorbed components. The second stage is in the range of 150 – 400 ºC associated with the weight loss due to the decomposition of organic compounds such as carboxylate compounds and surfactant molecules chemically adsorbed on the surface. Estimation of the weight loss amount in the temperature range 150 –


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400 ºC can give an insight into the quantity of adsorbed organic compounds on the calcite surface. Weight loss of organic compounds for the oil-aged calcite sample before treatment was around 1.46 %, which indicates that adsorbed oil compounds makes up about 1.46 % of the sample weight. After treatment with surfactant solution C13EO20, the weight loss was reduced to about 0.78 %. This amount can include the remaining adsorbed oil along with the adsorbed surfactant on the surface. A reduction of weight loss compared to the untreated oil-aged sample reveals that surfactant molecules could partially displace organic compounds from the surface. This observation is in good agreement with the FTIR results. However, the sample treated with C13EO12 resulted in weight loss of about 2.50 %. Higher amount of weight loss compared to that of the sample treated with C13EO12, suggests higher adsorption levels of C13EO12 on the surface. This finding is in line with the FTIR results as well. Figure 15 (inset) shows the TGA analysis of C13EO20 and C13EO7 stock solutions. It can be seen that the thermal stability of the nonionic surfactant increases with increasing the number of EO units included in its hydrophilic part. For instance, the stock solution of C13EO7 starts to show noticeable weight loss after a temperature of 100 °C followed by a sharp weight loss at 300 °C. As for C13EO20, slight weight loss was observed after 200 °C followed by sharp weight loss above 350 °C indicating the degradation of the surfactant. The weight loss values of the two surfactants before their degradation temperature were 17.5% at 300 °C and 5.8% at 350 °C for C13EO7 and C13EO20, respectively. The weight % trend observed in the oil aged calcite treated with C13EO12 is similar to that of C13EO7. As presented earlier, contact angle results show that the polyethoxylated nonionic surfactant is able to alter the wetting properties of the oil-aged calcite surface from strongly oil-wet state to a water-wet condition. Two different mechanisms of wettability alteration by nonionic surfactant were proposed. Zeta potential measurements show a slight decrease of the surface negative


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charge after surface treatment with surfactant. Although both of the proposed hypotheses can result in water-wet condition, the charge of the surface could be altered only if the surfactant could partially desorb the carboxylate compounds from the surface. This can occur only if the second mechanism is the dominant mechanism of wettability alteration. In addition, both TGA analysis and FTIR results confirm that nonionic surfactant could partially remove the adsorbed carboxylates from the surface. Moreover, FTIR results indicate that the surfactant could adsorb on the surface. As mentioned earlier, in the first proposed mechanism surfactant adsorbed on the surface via hydrophobic interactions and could not displace the adsorbed carboxylate from the surface. However, in the second proposed mechanism ion exchange with hydroxide ions as well as adsorption of surfactant via hydrogen bonding could displace the carboxylate compounds from the surface. Hence, the second mechanism appears to be the dominant mechanism of wettability alteration by polyethoxylated nonionic surfactant. However, the first mechanism could partially contribute to the wettability alteration process. It is worth noting that Jarrahian et al. (2012)53 have proposed a similar mechanism for wettability alteration by nonionic surfactant, Triton X-100. They reported that after treatment of carbonate surface with Triton X-100, surfactant molecule adsorbed on the surface by polarization of π electrons due to the presence of benzene ring in the surfactant molecule. The benzene ring would replace the adsorbed carboxylic acids on the surface and the released acids would adsorb again on the newly layer of surfactants’ molecules through hydrophobic interaction. Although in the current study, the selected surfactant does not contain a benzene ring in the molecule structure, which act as an electron source, they have ethoxy groups, which can form hydrogen bonds with the surface.


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5. CONCLUSIONS In this study polyethoxylated nonionic surfactant and low salinity brine were used to overcome compatibility limitations of the surfactant at high temperatures and improve its performance in order to achieve higher oil recovery in oil-wet fractured carbonate reservoirs. In addition, different surfactant systems were generated by modifying the number of EO units in the hydrophilic part of the surfactant molecule. Different analytical tools (contact angle, zeta potential, FTIR and TGA) were used to investigate the impact of the polyethoxylated nonionic surfactant on the wettability alteration of oil-aged carbonate surface and examine potential mechanisms of wettability changes. The cloud point increases with increasing the number of EO units and decreasing salinity for three different EO units. IFT measurements showed that at any salinity the IFT increases with increasing the degree of ethoxylation. The IFT decreased with increase in salinity and the minimum IFT was achieved at the salinity with a cloud point close to the reservoir temperature (around 1 °C above 75 °C). Minimum IFT achieved using different surfactant systems was in the order of 10-2 mN/m. In addition, phase behavior observations showed that surfactant solutions were not able to generate strong microemulsion. Therefore, this nonionic surfactant can be favorable for application in low permeability formations where generated microemulsions can cause formation damage Contact angle measurements revealed that all surfactant solutions are able to alter the wettability of calcite surfaces from strongly oil-wet towards water-wet state (~ 30 – 60°). The treatment of calcite surfaces with C13EO20 that has the highest degree of ethoxylation resulted in lower values of contact angle. Two potential mechanisms of wettability alteration by polyethoxylated nonionic surfactant were proposed:


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(1) Adsorption of hydrophobic part of the nonionic surfactant on the hydrophobic calcite surface and the formation of a surfactant double layer. (2) Formation of hydrogen bonds between ethoxy groups of the surfactant and hydroxyl groups or carboxylic groups of crude oil on the solid surface, which can result in replacement of organic compounds on the calcite surface. Surfactant molecules could occupy active sites of the calcite surface. Then, organic compounds could form a new layer on the adsorbed surfactant molecules’ layer via hydrophobic interactions. Zeta potential measurements showed a slight decrease in surface negative charge after surface treatment with surfactant. Although both of the proposed hypotheses can result in water-wet condition, the charge of the surface could be altered only if the surfactant could partially desorb the carboxylate compounds from the surface. This can occur only if the second mechanism is the dominant mechanism of wettability alteration. In addition, both TGA analysis and FTIR results confirmed that nonionic surfactant could partially remove the adsorbed carboxylates from the surface. Moreover, FTIR results indicated that the surfactant could adsorb on the surface. Hence, the second mechanism appears to be the dominant mechanism of wettability alteration by polyethoxylated nonionic surfactant and the first mechanism could partially contribute to the wettability alteration process.


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ACKNOWLEDGMENT The authors gratefully acknowledge the support of Sultan Qaboos University.

AUTHOR INFORMATION Corresponding Author *Tel: (+968) 24141361. E-mail: [email protected] Notes The authors declare no competing financial interest.


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(33) Spildo, K.; Sun, L.; Djurhuus, K.; Skauge, A., A strategy for low cost, effective surfactant injection. Journal of Petroleum Science and Engineering 2014, 117, 8-14. (34) Tichelkamp, T.; Vu, Y.; Nourani, M.; Øye, G., Interfacial tension between low salinity solutions of sulfonate surfactants and crude and model oils. Energy & Fuels 2014, 28, (4), 24082414. (35) Rosen, M. J.; Kunjappu, J. T., Adsorption of surface‐active agents at interfaces: the electrical double layer. Surfactants and Interfacial Phenomena, Fourth Edition 2004, 39-122. (36) Jachnik, R.; Green, P. In Horizontal well drill-in fluid utilising alcohol ethoxylate, SPE International Symposium on Oilfield Chemistry, 1995; Society of Petroleum Engineers: 1995. (37) Al-Ghamdi, A. M.; Nasr-El-Din, H. A., Effect of oilfield chemicals on the cloud point of nonionic surfactants. Colloids and Surfaces A: Physicochemical and engineering aspects 1997, 125, (1), 5-18. (38) Lewis, S.; Verkruyse, L.; Salter, S. In Selection of nonionic surfactants for minimized adsorption and maximized solubilization, SPE Enhanced Oil Recovery Symposium, 1986; Society of Petroleum Engineers: 1986. (39) Materna, K.; Cote, G.; Szymanowski, J., Cloud point of aqueous solutions containing oxyethylated methyl dodecanoates: effects of surfactant hydrophilicity, nature of added electrolyte, and water activity. Journal of colloid and interface science 2004, 269, (2), 466-471. (40) Sharma, K. S.; Patil, S. R.; Rakshit, A. K., Study of the cloud point of C12En nonionic surfactants: effect of additives. Colloids and Surfaces A: Physicochemical and Engineering Aspects 2003, 219, (1-3), 67-74. (41) Endo, S.; Pfennigsdorff, A.; Goss, K.-U., Salting-out effect in aqueous NaCl solutions: trends with size and polarity of solute molecules. Environmental science & technology 2012, 46, (3), 1496-1503. (42) Na, G. C.; Yuan, B. O.; Stevens, H. J.; Weekley, B. S.; Rajagopalan, N., Cloud point of nonionic surfactants: modulation with pharmaceutical excipients. Pharmaceutical research 1999, 16, (4), 562-568. (43) Schott, H.; Royce, A. E., Effect of inorganic additives on solutions of nonionic surfactants VI: further cloud point relations. Journal of pharmaceutical sciences 1984, 73, (6), 793-799. (44) Schott, H.; Royce, A. E.; Han, S. K., Effect of inorganic additives on solutions of nonionic surfactants: VII. Cloud point shift values of individual ions. Journal of Colloid and Interface Science 1984, 98, (1), 196-201. (45) 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. (46) Mirchi, V.; Saraji, S.; Akbarabadi, M.; Goual, L.; Piri, M., A Systematic Study on the Impact of Surfactant Chain Length on Dynamic Interfacial Properties in Porous Media: Implications for Enhanced Oil Recovery. Industrial & Engineering Chemistry Research 2017, 56, (46), 13677-13695. (47) Hadji, M.; Aoudia, M.; Al-Rubkhi, A.; Al-Maamari, R. S.; Hadj-Ziane-Zafour, A., Effect of Sodium Carbonate on the Cloud Point in Alkyl Ether/Brine Systems: Apparent Relation with Dynamic Interfacial Tension Minimum. Journal of Surfactants and Detergents 2016, 19, (6), 1223-1229.


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(48) Liu, X.; Zhao, Y.; Li, Q.; Jiao, T.; Niu, J., Adsorption behavior, spreading and thermal stability of anionic-nonionic surfactants with different ionic headgroup. Journal of Molecular Liquids 2016, 219, 1100-1106. (49) Trindade, M.; Dias, M.; Coroado, J.; Rocha, F., Mineralogical transformations of calcareous rich clays with firing: a comparative study between calcite and dolomite rich clays from Algarve, Portugal. Applied Clay Science 2009, 42, (3-4), 345-355. (50) Bang, J.-H.; Jang, Y. N.; Song, K. S.; Jeon, C. W.; Kim, W.; Lee, M. G.; Park, S.-J., Effects of sodium laurylsulfate on crystal structure of calcite formed from mixed solutions. Journal of colloid and interface science 2011, 356, (1), 311-315. (51) Nath, S. K.; Bordoloi, S.; Dutta, R. K., Effect of acid on morphology of calcite during acid enhanced defluoridation. Journal of Fluorine Chemistry 2011, 132, (1), 19-26. (52) Karimi, M.; Al-Maamari, R. S.; Ayatollahi, S.; Mehranbod, N., Mechanistic study of wettability alteration of oil-wet calcite: the effect of magnesium ions in the presence and absence of cationic surfactant. Colloids and Surfaces A: Physicochemical and Engineering Aspects 2015, 482, 403-415. (53) Jarrahian, K.; Seiedi, O.; Sheykhan, M.; Sefti, M. V.; Ayatollahi, S., Wettability alteration of carbonate rocks by surfactants: a mechanistic study. Colloids and Surfaces A: Physicochemical and Engineering Aspects 2012, 410, 1-10. (54) Derrick, M. R.; Stulik, D.; Landry, J. M., Infrared spectroscopy in conservation science. Getty Publications: 2000. (55) Stuart, B., Infrared spectroscopy. Wiley Online Library: 2005. (56) Tanur, A. E.; Gunari, N.; Sullan, R. M. A.; Kavanagh, C. J.; Walker, G. C., Insights into the composition, morphology, and formation of the calcareous shell of the serpulid Hydroides dianthus. Journal of structural biology 2010, 169, (2), 145-160. (57) Long, X.; Nasse, M. J.; Ma, Y.; Qi, L., From synthetic to biogenic Mg-containing calcites: a comparative study using FTIR microspectroscopy. Physical Chemistry Chemical Physics 2012, 14, (7), 2255-2263. (58) Tatzber, M.; Stemmer, M.; Spiegel, H.; Katzlberger, C.; Haberhauer, G.; Gerzabek, M., An alternative method to measure carbonate in soils by FT-IR spectroscopy. Environmental Chemistry Letters 2007, 5, (1), 9-12. (59) Karimi, M.; Al-Maamari, R. S.; Ayatollahi, S.; Mehranbod, N., Impact of sulfate ions on wettability alteration of oil-wet calcite in the absence and presence of cationic surfactant. Energy & Fuels 2016, 30, (2), 819-829. (60) Gupta, R.; Mohanty, K., Temperature effects on surfactant-aided imbibition into fractured carbonates. SPE Journal 2010, 15, (03), 588-597. (61) Al-Khafaji, A.; Neville, A.; Wilson, M.; Wen, D., Effect of Low Salinity on the Oil Desorption Efficiency from Calcite and Silica Surfaces. Energy & Fuels 2017, 31, (11), 1189211901. (62) Chen, Y.; Xie, Q.; Sari, A.; Brady, P. V.; Saeedi, A., Oil/water/rock wettability: Influencing factors and implications for low salinity water flooding in carbonate reservoirs. Fuel 2018, 215, 171-177. (63) Rashid, S.; Mousapour, M. S.; Ayatollahi, S.; Vossoughi, M.; Beigy, A. H., Wettability alteration in carbonates during “Smart Waterflood”: Underlying mechanisms and the effect of individual ions. Colloids and Surfaces A: Physicochemical and Engineering Aspects 2015, 487, 142-153.


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Table 1. Crude Oil Properties Viscosity (cP)

Density (g/cc)

Total acid number (TAN)

Asphaltene content

(mg KOH/g oil)

(%mass)

0.37

0.2

25 (°C)

75 (°C)

25 (°C) 75 (°C)

11

3.6

0.85

0.81

Table 2. Synthetic brine composition Components

g/L

mmole/L

Na+

60.9

2646.8

Ca2+

11.6

291.0

Mg2+

2.26

94.1

Cl-

120.6

3395.8

SO42-

0.69

7.18

TDS (g/L)

196.01


29

Energy & Fuels

100

Xie et al., 2005 Ayirala et al., 2006

80 Temperature /°C

Wu et al., 2008 Gupta and Mohanty, 2010

60

Mohan et al, 2011 Golabi et al., 2012

40

Jarrahian et al, 2012 Sharma and Mohanty, 2013

20

Ahmadi et al., 2013 Amirpour et al., 2015

0 0

20

40 60 Salinity /g/L

80

100

Figure 1. Conditions of salinity and temperature for some of studies which used nonionic surfactant alone for wettability alteration in carbonate2, 20, 21, 24, 25, 53, 60, 72-74

160000

Calcite

Counts Calcite

90000

40000

Calcite

Calcite Calcite

Calcite Calcite Calcite

Calcite

Calcite Calcite Calcite

Calcite Calcite

Calcite

Calcite

Calcite

Calcite

Calcite

10000 Calcite

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

Page 30 of 41

0 10

20

30

40

50

60

Position [°2Theta] (Copper (Cu))

Figure 2. XRD analysis of clean calcite.


30

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

Energy & Fuels

Figure 3. Set-up of contact angle measurements.


31

Energy & Fuels

120

75

Tcp /ᵒC

65

100

55 45 35 0

Tcp /ᵒC

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

Page 32 of 41

0.2

0.4 0.6 0.8 Concentration /wt%

1

80

60

40 0

50

100 Salinity /g/L

150

200

Figure 4. Variation of cloud point of as a function of salinity and the cloud point measurements at salinity of 196 g/L at varying concentration (inset) of C13EOx: ( ) x = 12, ( ) x = 16, (

)x=

20.


32

Page 33 of 41

0.6 0.5

IFT /mN/m

0.4 0.3 0.2 0.1 0 0

20

40

60 Salinity /g/l

80

100

120

Figure 5. IFT measurements at different salinities at 75 °C of 0.3 wt.% C13EOx: ( ) x = 12, ( ) x = 16, ( ) x = 20. 0.9 0.8 0.7 0.6 IFT /mN/m

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

Energy & Fuels

0.5 0.4 0.3 0.2 0.1 0 0

1000

2000 Time /seconds

3000

Figure 6. Dynamic IFT at salinity of 1.96 g/L and 75 °C of 0.3 wt. % C13EOx: ( ) x = 12, ( ) x = 16, (

) x = 20.


33

Energy & Fuels

Contact Angle

Zeta potential

200 159.6

CA /⁰, ξ /mV

150 100 34.2 50

+[VALUE ]

0 -26.7

-50 Clean calcite

Oil aged calcite

Figure 7. Contact angle and zeta potential of the fresh calcite before and after aging in crude oil

100

95 Weight /%

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

Page 34 of 41

90

Clean calcite

85

Oil aged calcite 80 0

200

400 600 Sample temperature /⁰C

800

Figure 8. TGA analysis of fresh calcite sample (solid line) and calcite sample after aging in crude oil (dotted line)


34

Page 35 of 41

Oil Aged Calcite

Crude Oil

Absorbance

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

Energy & Fuels

Fresh Calcite

4000

3600

3200

2800

2400

2000

1600

1200

800

400

Wavenumber /cm -1 Figure 9. FTIR absorbance spectra of the fresh calcite sample before and after aging in crude oil and ATR-FTIR absorbance spectra of the crude oil.


35

Energy & Fuels

C₁₃EO₁₂

180

C₁₃EO₁₆

Brine Dilution

C₁₃EO₂₀

150 Contact angle /º

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

Page 36 of 41

120 90 60 30 0 1.96

9.8

19.6

49.0 78.3 Salinity /g/L

97.9

109.7

196.0

Figure 10. Contact angle of the oil-aged calcite surfaces after treatment with C12EOx (12, 16 and 20) at different salinities and different brine dilutions.


36

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

Energy & Fuels

H H

H

Water molecule

H

nH Hydrophobic tail

Hydrogen bonding formation

Calcite

(a)

EO units Carboxylic acid

H n Hydrophilic head

H n H H

(b)

H

Hydrogen bonding formation

H

Calcite

Figure 11. Possible mechanisms of wettability alteration of oil-aged calcite surfaces after treatment with nonionic surfactant.


37

Energy & Fuels

10

10

a

b

8

8

6

6

pH

pH

4

4

2

2

0

0 1.96


9.8

19.6 Salinity /g/L

49.0

10

78.3

c

pH

8 6 4 2 0 1.96

9.8


97.9

109.7

10 d

8 pH

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

Page 38 of 41

6 4 2 0 1.96

9.8


97.9

196.0

Figure 12. Initial (■) and final pH of the surfactant solutions used for oil aged calcite surfaces (a) C13EO12, (b) C13EO16, (c) C13EO20, (d) brine dilutions.


38

Page 39 of 41

Contact angle

Zeta potential

100 58.8

60.0

57.4

CA /⁰, ξ /mV

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

Energy & Fuels

50

0

-28.1

-29.1

-25.4

-50 C₁₃EO₁₂

C₁₃EO₁₆

C₁₃EO₂₀

Figure 13. Comparison between zeta potential and contact angle of the oil-aged calcite after treatment with C12EOx (12, 16 and 20) at 1.96 g/L.


39

Energy & Fuels

C₁₃EO₂₀

A

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

Page 40 of 41

C₁₃EO₁₂

4000

3600

3200

2800

2400 2000 1600 -1 Wavenumber /cm

1200

800

400

Figure 14. FTIR absorbance spectra for aged calcite after treatment with nonionic surfactant C13EO20 and C13EO12 (solid line), ATR-FTIR absorbance spectra for C13EO20 and C13EO7 stock solution (dashed line).


40

Page 41 of 41

100

95

100

90

80 Weight /%

Weight /%

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

Energy & Fuels

60 40 C₁₃EO₇ solution

85

20 0 0

100 200 300 400 Sample temperature /⁰C

500

80 0

100

200

300 400 500 Sample temperature /⁰C

600

700

800

Figure 15. TGA analysis of aged calcite after treatment with nonionic surfactant C13EO20 (dashed line) and C13EO12 (solid line) in comparison with the oil aged calcite sample (dotted line), Figure inset shows TGA analysis of C13EO20 (solid line) and C13EO7 (dashed line) stock solution.


41

Experimental Investigation of Wettability Alteration of Oil-Wet

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