Experimental Study of Wettability Alteration of Limestone Rock from Oil ...

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SPE 157801 Experimental Study of Wettability Alteration of Limestone Rock from OilWet to Water-Wet using Various Surfactants 1

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Elyas Golabi , Fakhry Seyedeyn Azad , Sayed Shahabuddin Ayatollahi , Sayed Nooroldin Hosseini , Naser 1 Akhlaghi 1 Department of Petroleum Engineering, Omidiyeh Branch, Islamic Azad University, Omidiyeh, Iran. 2 Department of Chemical Engineering, University of Isfahan, Isfahan, Iran 3 EOR Research Center, School of Chemical and Petroleum Engineering, Shiraz University, Shiraz, Iran. Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Heavy Oil Conference Canada held in Calgary, Alberta, Canada, 12–14 June 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract The water flooding in the carbonate fracture reservoir is low efficiency because of higher permeability in fractures than in matrix, and water will not imbibe spontaneously into the matrix due to a negative capillary pressure. Spontaneous imbibition of water into carbonate fracture reservoir is a very important issue in secondary oil recovery method. However, almost more than 80% of the entire known carbonate reservoir can be categorized as oil wet. It is therefore important to find methods to alter the wettability from oil-wet to water-wet conditions that are effective in order to improve the recovery from carbonate fracture reservoir. So far, two methods have been developed wettability alterations: 1) addition of certain chemical surface active agent to the injection water, and 2) thermally wettability alteration by steam injection. In this study, an oil sample with 20 API was used to investigate the effect of the understudied surfactants on wettability alteration in the oil-water-limestone system. Understudied surfactants were SDBS (sodium dodecylbenzene sulfonate), C12TAB (dodecyl trimethyl ammonium bromide), C16TAB (hexadecyl trimethyl ammonium bromide) and Triton X-100 that were utilized at 0.5, 1.5 and 2.5 wt% concentrations. The experiments were performed several times (0, 1, 6, 12, o 24, 48, 72, 96 h) after injection of oil drop under limestone rock sample at reservoir temperature of 80 C. The obtained results showed that the increasing each of the surfactant could cause wettability alteration of the rock from oil-wet towards water-wet situation by passing of time. This alteration was very sharp at the beginning, but it was increases slightly at the time. It was observed that Triton X-100 was more efficient than C16TAB, C12TAB and SDBS to alter the wettability of the rock. 1. Introduction About half the world’s discovered oil reserves are in carbonate reservoir forms and many of them are naturally fractured (Roehl and Choquette, 1985). The Total oil recovery does not exceed generally 30%. Such reservoirs are often characterized by high-permeability fractures and a low permeability matrix medium. Most of the injected water will pass through the fracture network and displaces only the oil residing in the fracture (Cuiec, 1984; Treiber et al., 1972). Spontaneous imbibition of water from the fractures into the matrix takes place if the reservoir is water-wet. However, up to 65% of carbonate rocks are oil-wet and 12% are intermediate-wet (Chillingar and Yen, 1983). Most of the oil reservoirs are found in carbonate rocks, many of which contain fractures with high hydraulic conductivity surrounding low-permeability matrix blocks that are mixed-wet to oil-wet (Allan and Sun, 2003; Roehl and Choquette, 1965; Salehi, et al., 2008). After the primary production period, water flooding is often performed to increase the recovery efficiency. In fractured reservoirs, oil recovery from water flooding relies on the spontaneous imbibition of water to expel oil from the matrix into 1

Corresponding Author E-mail addresses : [email protected] (Elyas Golabi)

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the fracture system. The spontaneous imbibition process is most efficient in strongly water-wet rock where the capillary driving force is strong. In oil-wet or mixed wet fractured carbonate reservoirs, however, the capillary driving force for the spontaneous imbibition process is weak and therefore, the water flooding oil recoveries are low. The recovery efficiency in fractured oil-wet or mixed-wet carbonate reservoirs can be improved by dissolving low concentrations of surfactants in the injected water to alter the wettability of the reservoir rock to a more water-wet state. Wettability alteration accelerates the spontaneous imbibition of water into matrix blocks, thereby increasing the oil recovery during water flooding. Several mechanisms have been addressed to explain the wettability alteration by surfactants, but none have been proved experimentally. Understanding of the mechanisms behind wettability alteration could help to improve the performance of the process and aid in identification of alternative surfactants for use in field applications. Several researchers noted that for a given rock type, the effectiveness of wettability alteration is highly dependent upon the ionic nature of the surfactant involved (Salehi, et al., 2008). Wettability is a very important parameter in oil recovery processes, because it has strong impact on the distribution, location and flow of oil and water in the reservoir during production (Anderson, 1986b; Anderson, 1987a; Anderson, 1987b; Anderson, 1987c; Cuiec, 1991; Hjelmeland and Torsaeter, 1980; Morrow, 1990). Wettability is defined by Anderson (1986a) as “the tendency of one fluid to spread on or adhere to a solid surface in the presence of other immiscible fluids”. The reservoir rock may be water-wet, oil-wet, or neutral-wet if both fluids have equal affinity for the rock surface. The wettability may be non-uniform; various types of fractional wettability exist where isolated areas are water-wet and oil-wet, mixed wettability is a special case where the oil- and water-wet areas are each continuous (Anderson, 1986b; Milter, 1996; Standnes, 2001). Carbonate rocks are naturally water-wet (Hognesen, 2005) and the surface possesses higher affinity for water than for oil. When crude oil migrates from a source rock and invades an originally water-filled reservoir, the capillary pressure increases and can exceed the force barrier which keeps the water-wetting film in place. As the water wetting film becomes ultra-thin and ruptures, the wetting molecules are displaced and replaced by surface-active polar components in the oil, which adsorbs irreversibly onto the rock surface, effectively altering the wettability towards oil-wet (Milter, 1996). For wettability alteration, two different methods have been presented including addition of a certain amount of surfactant chemicals (Chen, et al. 2000; Downs, and Hoover, 1989; Standnes, and Austad, 2000a) and thermally wettability alteration by steam injection (Al-Hadhrami, and Blunt, 2000; Macaulay, et al., 1995; Ayatollahi, et al., 2005). Surfactants are amphiphilic molecules, consisting of a hydrophilic head group and a hydrophobic hydrocarbon chain of various lengths. The head group may be non-ionic, cationic, anionic, or zwitter-ionic. In order to alter wettability by using surfactants, three different types of surfactants including anionic surfactants (Standnes, and Austad, 2000a, Ronaldo, et al., 2006; Golabi, et al., 2008), non- ionic surfactants (Chen, et al. 2000; Golabi, et al., 2009), and ammonium type of cationic surfactants are used (Tabatabal, et al., 1993; Xie, et al., 2004, Golabi, et al., 2009). In this experimental research, four surfactants including anionic surfactant (sodium dodecylbenzene sulfonate), cationic surfactants (dodecyl trimethyl ammonium bromide and hexadecyl trimethyl ammonium bromide) and non-ionic surfactant (Triton X-100) were used for wettability alteration of core sample that was obtained from Iranian fracture carbonate reservoir. 2. Experimental 2.1. Materials The anionic surfactant used in this study was sodium dodecylbenzene sulfonate (CH3 (CH2)11C6H4SO3Na) with molecular weight 347.48 gr/mol. The critical Micelle Concentration (CMC) of this surfactant at 25 0C is 0.526 wt% and the grade was equals or greater than 80%. The structure of the surfactant is shown in Fig. 1. Two cationic surfactants used in this study were dodecyl trimethyl ammonium bromide (C12TAB) with the formula of C12N (CH3)3Br, molecular weight 308.34 gr/mol, CMC of 0.418 wt% at 25 0C as well as hexadecyl trimethyl ammonium bromide (C16TAB) with chemical formula of C16N (CH3)3Br, molecular weight of 364.45 gr/mol, CMC of 0.032 wt% at 25 0C. The grades of both cationic surfactants were equal or greater than 98%. The structures of C12TAB and C16TAB are shown in Fig. 2 and Fig. 3, respectively. A Non-ionic surfactant, Triton X-100 (C14H22O(C2H4O)10) with molecular weight of 646.85 gr/mol, CMC of 0.194 wt% at 25 0C and grade of equals or greater than 99% was also used. The structure of the Triton X-100 is shown in Fig. 4. These surfactants were purchased from Sigma-Aldrich and Fluka Company. Also, Lauric acid (CH3 (CH2)10COOH) from Carboxylic acids group and sodium carbonate (Na2CO3) were purchased from Merck Company. The oil and the core sample were obtained from a reservoir that was located in southern part of Iran. The oil properties, composition, and the reservoir brine composition are given in Tables 1 to 3. Core specifications including porosity, permeability and compressibility are also presented in Table 4.

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2.2. Wettability alteration In order to study the effects of the four mentioned surfactants as well as acid and alkaline at various concentrations at 80 oC on wettability alteration, the limestone core with dimensions of 16.8!5 cm!cm was divided into four parts with dimensions of (5.2, 5.1and 5.0 cm) ! 5 cm. The limestone core plugs were sampled from a well drilled in a reservoir. Firstly, the cores were cleaned by immersing in solvent, and then they were polished to remove the surface layer. They were saturated with the reservoir brine and after that were saturated with the oil sample by a core flood injection apparatus. Each segment of the samples was first immersed in surfactant solutions inside the experimental cell and then oil drop was injected through an orifice at the bottom of the cell. In addition, the wettability alteration was also verified by measuring and comparing the contact angle between the oil drop and the rock after aged the rock at the specified temperature and the concentrations of the surfactants. The contact angle was measured by an imaging system (Fig. 5). 3. Result and Discussion 3.1. Contact angle in reservoir brine/ core sample/ oil drop system After saturation of cores by reservoir brine and oil, the first step was measuring contact angle between the oil drop and the core sample in the reservoir brine/ core sample/ oil drop system, as shown in Fig 6. The oil drop was dispersed on the core and the contact angle between oil drop and core was measured. The contact angle was 162 degree. The result showed that the core sample was strongly oil-wet. In the next step, the effect of four surfactants with sodium carbonate or lauric acid was investigated for wettability alteration towards water-wet. 3.2. Contact angle reduction and wettability alteration by SDBS In this section the effect of various concentrations (0.5, 1.0 and 1.5 wt%) of SDBS with 0.0, 0.5, 1.0, 1.5, and 2.0 wt% Na2CO3 at 80oC and after 0, 1, 6, 12, 24, 48, 72, and 96 h on wettability alteration towards water-wet was investigated. The results are shown in Table 5. As shown in Figs 7 and 8, with increasing Na2CO3 concentration, the contact angle was decreased for various concentrations of SDBS and more wettability alteration was observed towards water-wet. Na2CO3 could change the wettability in chalk towards more water-wet by interaction. The potential of the adsorption of the SO32- on the chalk surface could result in lowering the positive charge density. Due to less electrostatic repulsion, more Na+ can be attached to the rock surface to displace some of the carboxylic materials. Also, the effect of the increasing of sodium concentration on the contact angle reduction was more pronounced with passing the time (Fig 9). Fig. 9 shows the various concentrations of surfactant in the presence of Na2CO3 reduced contact angle more than by the absence of Na2CO3. Also results indicate in the primary times the reduction of contact angle is sharp and after 48 h contact angle curve is almost smooth. The least contact angle (66 degree) obtained at 1.5 wt% SDBS and wt% Na2CO3 after 96 h. 3.3. Contact angle reduction and wettability alteration by C12TAB and C16TAB In this part, the effect of various concentrations (0.5, 1 and 1.5 wt%) of C12TAB and C16TAB with 0.0, 0.05, 0.10, 0.15, and 0.02 mol of Lauric acid after 0, 1, 6, 12, 24, 48, 72, and 96 h at 80oC on wettability alteration was investigated. The results showed that the wettability was altered towards water-wet. The results are shown in Table 6 and Table 7. The cationic surfactants and the carboxylic acids have electrostatic interactions between the positively charged of head groups of the first and the negatively charged carboxyl groups of the latter. Therefore, the cationic surfactant monomers have the ability to desorb the organic material from the rock surface as surfactant carboxylic acid ion-pairs (Austad et al., 1998; Standnes, 2001), and alter the wettability towards water-wet. Hydrophobic interactions between the hydrocarbon chains alleviate the ion-pairs (Standnes and Austad, 2000). As shown in Figs. 10, 11, 13 and 14, the contact angle was decreased by increasing the Lauric acid concentration at different concentrations of C12TAB and C16TAB and therefore more wettability alteration towards water wet was obtained. Also, result shown in Figs. 10 and 13, changed to contact angle at 0.0, 0.05 and 0.10 mol Lauric acid is sharply more than this concentrations after 96 h (Fig. 11 and 14), but after 96 h obtain lower contact angle than immediately after aged oil drop. Figs. 12 and 15 were showed very similar results for C12TAB and C16TAB surfactant. The results Shows that the various concentrations of surfactant in the presence of Lauric acid reduced the contact angle compared to when the Lauric acid was absent. Also, the results indicate that at the beginning the contact angle was reduced sharply, whereas by passing the time the reduction was less pronounced. For C16TAB, minimum contact angle of 56 degree aws obtained at 1.5 wt% C16TAB and 0.20 mol Lauric acid after 96 h, whereas for C12TAB the least contact angle was 60 degree which was obtained at 1.5 wt% C12TAB and 0.20 mol of Lauric acid after 96 h. Also C16TAB wettability alteration towards water-wet was more than C12TAB. The same trend was also reported by Standnes and Austad (2003).

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3.4. Contact angle reduction and wettability alteration by Triton X-100 In this section of investigation effect of nonionic Surfactant Triton X-100 at different concentrations with and without Na2CO3 at 80oC was studied on reduction contact angle and wettability alteration that results shown in table 8. The concentrations of Triton X-100 are 0.5, 1 and 1.5 wt% and Na2CO3 concentrations are 0.0, 0.5, 1.0, 1.5 and 2.0 wt% was used in this part. Fig. 16 and Fig. 17 show the variation of contact angle versus Na2CO3 concentration for various amounts of Triton X-100 concentrations at the beginning and after 96 h of the addition of aged oil drop at different Triton X-100 concentrations at different Triton X-100 concentrations at different Triton X-100 concentrations. As shown, with increasing Na2CO3 concentration the contact angle was decreased and the wettability alteration moved towards water-wet. Fig. 18 was indicates the variation of contact angle versus the time for various amounts of Triton X-100 surfactant and Na2CO3 concentrations. As the Fig. show, increasing three factors including the surfactant concentration, the Na2CO3 concentration and the time was effective on the contact angle reduction and the wettability alteration. It worth mentioning that the minimum contact angle of 47 degree was obtained at 1.5 wt% Triton X-100 and wt% Na2CO3 after 96 h. Comparing the performance of surfactants used in this study, the most reduction of contact angle and wettability alteration towards water-wet was obtained by Triton X-100 and then by C16TAB, C12TAB and SDBS, respectively (Fig. 19). Austad and et al. (1998) and also Standnes and Austad (2000) were reported that in oil-wet chalk cores observed that cationic surfactants showed better performance than anionic surfactants in changing the rock wettability to a more water-wet state. Conclusion 1. In this study various surfactants including Triton X-100, C16TAB, C12TAB and SDBS and also Sodium Carbonate and Lauric acid were used for wettability alteration of a core sample from one of Iranian south fracture reservoir towards waterwet. Results confirmed that these materials efficiently altered the wettability alteration of the studied core and oil sample. 2. Increasing the surfactant concentration, the time and the concentration of Sodium Carbonate and Lauric acid cause altered the wettability towards water-wet. 3. Results indicated that at the beginning of the experiment, the contact angle was reduced sharply, whereas after 48 h the contact angle curve did not show much variation. The least contact angle was 66 degree which was obtained at 1.5 wt% SDBS and wt% Na2CO3 after 96 h. 4. For C16TAB, minimum contact angle of 56 degree was obtained at 1.5 wt% C16TAB and 0.20 mol Lauric acid after 96 h, whereas for C12TAB the least contact angle of 60 degree was obtained at 1.5 wt% C12TAB and 0.20 mol of Lauric acid after 96 h. 5. Comparing the performance of surfactants used in this study, the maximum reduction of contact angle and wettability alteration toward water-wet was performed by Triton X-100, and then by C16TAB, C12TAB and SDBS, respectively. References: Allan, J., Sun, S. Q., 2003. In Controls on Recovery Factor in Fractured Reservoirs: Lessons Learned from 100 Fractured Fields Paper SPE 84590 presented at the SPE Annual Technical Conference and Exhibition, Denver, CO, USA, 5-8 October. Al-Hadhrami, H. S., and Blunt, M. J., 2000. Thermally induced wettability alteration to improve oil recovery in fractured reservoirs, Paper SPE 59289 presented at the SPE/DOE Improved Oil Recovery Symposium held in Tulsa, OK, April 3– 5. Anderson, W.G., 1986a. Wettability literature survey – part 1: rock/oil/brine interactions and the effects of core handling on wettability. Journal of Petroleum Science and Engineering: 1125-1144. Anderson, W.G., 1986b. Wettability literature survey – part 2: wettability measurement. Journal of Petroleum Science and Engineering: 1246– 1262. Anderson, W.G., 1987a. Wettability literature survey- Part 6: The effect of wettability on waterflooding. Journal of Petroleum Technology: 1605-1622. Anderson, W.G., 1987b. Wettability Literature Survey - Part 4: Effects of wettability on capillary pressure. Journal Of Petroleum Technology, October: 1283-1300. Anderson, W.G., 1987c. Wettability Literature Survey - Part 5: The effects of wettability on relative permeability. Journal of Petroleum Technology, November: 1453-1468. Austad, T., Matre, B., Milter, J., Saevareid, A., Oyno, L., 1998. Chemical Flooding of Oil Reservoirs and Spontaneous Oil Expulsion from Oil-and Water-wet Low Permeable Chalk Material by Imbibition of Aqueous Surfactant Solutions, Colloids and Surfaces A: Physicochemical and Engineering, 137, 117-129. Ayatollahi S., Lashanizadegan A., and Kazemi, H., 2005. Temperature Effects on Heavy Oil Relative Permeability during Gas-Oil Gravity Drainage (GOGD), Energy and Fuels Journal, Volume 19 Issue 3, pp 977 - 983. Chen, H. L., Lucas, L. R., Nogaret, L. A. D., Yang, H. D., and Kenyon,D.E., 2000. Laboratory monitoring of surfactant imbibition using computerized tomography, Paper SPE 59006 presentedat the SPE International Petroleum Conference, Villahermosa,Mexico. Chilingar, G.V. and Yen, T.F., 1983. Some notes on wettability and relative permeability of carbonate rocks. II. Energy and Sources, 7: 67-75.

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Cuiec, L., 1984. Rock/crude-oil interactions and wettability: An attempt to understand their interrelation. Paper SPE 13211 presented at the 59th Annual Conference and Exhibition, Houston, Texas, 16-19 September. Cuiec, L.E., 1991. Evaluation of reservoir wettability and its effect on oil recovery, Surfactant science series, 36. Golabi, E., Seyedeyn-Azad, F., Ayatollahi. Sh., 2009. Chemical induced wettability alteration of carbonate reservoir rock, Iranian Journal of chemical engineering, Vol. 6, No. 1, 66-73. Downs, H. H., and Hoover, P. D., 1989. Enhanced oil recovery by wettability alteration In: Borchardt, J.K., Yen, T.F. (Eds.), Oil-Field Chemistry. Enhanced Recovery and Production Stimulation, ACS Symposium Series, vol. 396. Washington, DC, pp, 577–595. Golabi, E., Seyedeyn-Azad, F., Ayatollahi. Sh., 2008. An experimental study of effect of Anionic and cationic surfactant on Enhanced Oil Recovery of Aghajari Reservoir, 5th international chemical engineering congress Kish, Iran. Hjelmeland, O.S. and Torsaeter, O., 1980. Wettability, the key to proper laboratory waterflooding experiments. U.S. DOE CONF-8004140, Proc., International Energy Agency Workshop on EOR, OK, USA: 1-24. Hognesen, E. J., 2005. EOR in fractured oil-wet chalk. Spontaneous imbibition of water by wettability alteration, Dr. Ing. Thesis no. 20, Faculty of Science and Technology, Department of Petroleum Engineering, University of Stavanger. Leirvik, A., 2011. Evaluation of experimental methods to determine wettability. MSc. Ing. Thesis, Faculty of Science and Technology, Department of Petroleum Engineering, University of Stavanger. Milter, J, 1996. Improved oil recovery in chalk. Spontaneous imbibition affected by wettability, rock framework, and interfacial tension, PhD thesis, Department of Chemistry, University of Bergen. Morrow, N.R., 1990. Wettability and its effect on oil recovery, Journal of Petroleum Technology, December: 1476-1484. Roehl, P. O. and Choquette, P. W., 1985. Carbonate Petroleum Reservoirs. Springer-Verlag, New York, 622 pp. Ronaldo, G., Rahoma, S., Antonio, C., and Watson, L., 2006. Contact angle measurements and wetting behavior of inner surfaces of pipelines exposed to heavy crude oil and water", Journal of Petroleum Science and Engineering Volume 51, Issues 1-2, Pages 9-16. Salehi, M., Johnson, S. J., and Liang, J., 2008. Mechanistic Study of Wettability Alteration Using Surfactants with Applications in Naturally Fractured Reservoirs. Langmuir, The ACS Journal Of Surfaces And Colloids, 24(24):14099-107. Standnes, D. C., and Austad, T., 2000a. Wettability alteration in chalk 2, Mechanism for wettability alteration from oilwet to water-wet using surfactants, Journal , Petroleum, Science, Engineering , 28, 123–143. Standnes, D. C., and Austad, T., 2000. Wettability Alteration in Chalk 2. Mechanism for Wettability Alteration from Oilwet to Water-wet using Surfactants, Journal of Petroleum Science and Engineering, 28, 123-143. Standnes, D. C., 2001. Enhanced oil recovery from oil-wet carbonate rock by spontaneous imbibition of aqueous surfactant solutions. Dr.ingenioravhandling, ISSN 0809-103X; 2001:81, NTNU Trondheim. Tabatabal, A., Gonzalez, M.V., Harwell, J.H., & Scamehorn, J.F., 1993. Reducing surfactant adsorption in carbonate reservoirs, Soc. Pet. Eng., Reservoir Eng., 5. Treiber, L.E., Archer, D.L. and Owens, W.W., 1972. A laboratory evaluation of the wettability of fifty oil producing reservoirs. SPE03526, SPE Journal, December: 531-540. Xie, X., Weiss, W.W., Tong, Z., and Morrow, N.R., 2004. Improved oil Recovery from carbonate reservoirs by chemical stimulation, SPE 89424.

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O S ONa O CH3(CH2)10CH2

Fig 1: Chemical structure of SDBS

CH3 Br CH3(CH2)10CH2-N-CH3 CH3 +

Fig 2: Chemical structure of C12TAB

CH3 Br CH3(CH2)14CH2-N-CH3 CH3 +

Fig 3: Chemical structure of C16TAB

O

O

H n

Fig 4: Chemical structure of Triton X-100

Fig 5: Experimental cell and imaging system for contact angle measurement

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Fig. 6: Contact angle in reservoir brine/ core sample/ oil drop system

Fig 7: Variation of contact angle versus Na2CO3 concentration for different amounts of SDBS surfactant concentrations immediately after aged oil drop

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Fig 8: Variation of contact angle versus Na2CO3 concentration for different amounts of SDBS surfactant concentrations 96 h after aged oil drop

Fig 9: Variation of contact angle versus time for different amounts of SDBS surfactant concentrations and Na2CO3 concentrations (N: Na2CO3 & S: SDBS)

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Fig 11: Variation of contact angle versus Lauric acid for different amounts of C12TAB surfactant concentrations 96 h after aged oil drop

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Fig 12: Variation of contact angle versus time for different amounts of C12TAB surfactant concentrations and Lauric acid concentrations (L: Lauric acid & C12: C12TAB)

Fig 13: Variation of contact angle versus Lauric acid for different amounts of C16TAB surfactant concentrations immediately after aged oil drop

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Fig 14: Variation of contact angle versus Lauric acid for different amounts of C16TAB surfactant concentrations 96 h after aged oil drop

Fig 15: Variation of contact angle versus time for different amounts of C16TAB surfactant concentrations and Lauric acid concentrations (L: Lauric acid & C16: C16TAB)

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Fig 16: Variation of contact angle versus Na2CO3 for different amounts of Triton X-100 surfactant concentrations immediately after aged oil drop

Fig 17: Variation of contact angle versus Na2CO3 concentration for different amounts of Triton X-100 surfactant concentrations 96 h after aged oil drop

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Fig 18: Variation of contact angle versus time for different amounts of Triton X-100 surfactant concentrations and Na2CO3 concentrations (N: Na2CO3 & T: Triton X-100)

Fig 19: Comparing the performance of SDBS, C12TAB, C16TAB and Triton X-100 after 96 h of the addition of aged oil drop

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Table 1: Physical properties of Oil used for recombining Density at Viscosity Compressibility API 25 oC -1 (cp) (Psi ) (g/ml) 0.311 20 2.01!10-5 0.934

Asphaltene (wt %) 11.25

Oil volume Factor (RB/STB) 1.12

Acid number (mg KOH/g oil) 2.52

Table2: Fluid composition used in experiments (mol %) Component Dead Oil Separator Gas

Recombined Fluid

Reservoir Fluid

H 2S N2 CO2 C1 C2 C3 i- C4 n- C4 i- C5 n- C5 C6 C7 C8 C9 C10 C11 C12+

0.04 0.10 2.80 19.50 9.11 8.01 2.39 5.24 1.63 2.11 2.34 2.66 1.33 1.22 2.56 3.45 38.51

0.03 0.11 2.87 16.96 8.15 6.79 1.13 4.26 2.40 2.55 3.50 3.15 1.77 1.01 2.10 3.12 40.10

0 0 0 0 0.25 0.73 1.61 3.30 2.88 3.60 4.99 4.95 2.87 1.50 2.89 4.34 66.09

0.08 0.28 5.62 45.79 20.88 15.25 3.43 4.43 1.80 1.74 0.65 0.05 0.00 0.00 0.00 0.00 0.00

Table 3: Brine Composition used in experiments Ion Na+ K+ Ca2+ Mg2+ ClSO42HCO3Total Dissolved Solid (TDS)

Concentration (g/l) 48.26 1.16 7.80 2.94 97.50 0.90 1.52 160.08

Table 4: Core properties used in each experiment Core L D (cm) (cm) A 5.2 5.0 B 5.1 5.0 C 5.0 5.0

K (md) 15.86 15.94 15.92

(%) 17.2 17.1 17.1

PV (cm3) 15.1 !10-3 15.2 !10-3 15.2 !10-3

Swc (%) 23.2 23.4 23.3

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Table 5: Variation of contact angle (deg) versus time concentrations at constant temperature (80oC) Contact Contact angle SDBS Na2CO3 angle after (Wt %) (Wt %) after 1 aging hr (deg) (deg) 0.5 0.0 145 137 1.0 0.0 142 133 1.5 0.0 140 132 0.5 0.5 139 128 1.0 0.5 135 125 1.5 0.5 133 122 0.5 1.0 132 121 1.0 1.0 130 118 1.5 1.0 128 117 0.5 1.5 131 118 1.0 1.5 128 116 1.5 1.5 127 115 0.5 2.0 130 116 1.0 2.0 127 115 1.5 2.0 126 114

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for different amounts of SDBS surfactant concentrations and Na2CO3 Contact angle after 6 hr (deg)

Contact angle after 12 hr (deg)

Contact angle after 24 hr (deg)

Contact angle after 48 hr (deg)

Contact angle after 72 hr (deg)

Contact angle after 96 hr (deg)

130 126 125 120 118 116 111 109 107 110 107 105 106 104 103

123 118 115 113 110 109 104 101 100 101 100 97 98 96 92

117 112 110 107 105 104 98 97 95 97 94 92 91 89 83

113 107 106 103 101 100 94 93 89 93 89 87 85 82 74

107 103 102 99 96 94 89 88 84 88 83 81 79 75 71

103 100 99 97 93 91 86 84 80 84 79 77 74 70 66

Table 6: Variation of contact angle (deg) versus time for different amounts of C12TAB surfactant concentrations and Lauric acid concentrations at constant temperature (80oC) C12TAB (wt Lauric acid Contact Contact Contact Contact Contact Contact Contact Contact %) (mol) angle angle angle angle angle angle angle angle after after 1 after 6 after 12 after 24 after 48 after 72 after 96 aging hr (deg) hr (deg) hr (deg) hr (deg) hr (deg) hr (deg) hr (deg) (deg) 0.5 0.00 138 130 121 118 110 107 101 96 1.0 0.00 135 126 118 113 106 101 97 94 1.5 0.00 133 125 116 110 104 100 96 91 0.5 0.05 132 121 115 108 100 97 93 89 1.0 0.05 129 119 111 105 99 95 91 85 1.5 0.05 127 115 110 104 97 94 88 82 0.5 0.10 125 114 104 101 94 87 84 80 1.0 0.10 123 111 103 100 92 86 82 79 1.5 0.10 121 110 102 97 91 82 79 78 0.5 0.15 124 111 103 95 92 85 77 76 1.0 0.15 120 110 101 94 90 81 76 75 1.5 0.15 119 109 100 93 87 78 75 72 0.5 0.20 122 110 98 92 86 77 71 69 1.0 0.20 118 108 95 90 84 75 69 67 1.5 0.20 117 107 94 88 79 70 66 60

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SPE 157801

Table 7: Variation of contact angle (deg) versus time for different amounts of C16TAB surfactant concentrations and Lauric acid concentrations at constant temperature (80oC) C16TAB Lauric acid Contact Contact Contact Contact Contact Contact Contact Contact (Wt %) (mol) angle angle angle angle angle angle angle angle after after 1 after 6 after 12 after 24 after 48 after 72 after 96 aging hr (deg) hr (deg) hr (deg) hr (deg) hr (deg) hr (deg) hr (deg) (deg) 0.5 0.00 133 126 117 113 105 103 96 87 1.0 0.00 130 122 113 108 100 97 92 85 1.5 0.00 128 121 112 105 98 96 91 82 0.5 0.05 127 117 110 103 95 93 88 83 1.0 0.05 124 114 108 100 93 91 85 80 1.5 0.05 122 111 106 99 92 90 83 78 0.5 0.10 120 110 101 96 87 83 78 77 1.0 0.10 118 107 99 95 86 82 77 75 1.5 0.10 116 106 97 94 84 78 75 73 0.5 0.15 119 107 99 93 86 82 77 72 1.0 0.15 116 105 97 88 83 77 72 68 1.5 0.15 115 104 96 86 78 74 70 66 0.5 0.2 118 105 94 87 80 73 68 64 1.0 0.20 114 103 92 85 78 69 64 62 1.5 0.20 113 102 91 83 74 65 61 56

Table 8: Variation of contact angle (deg) versus time for different amounts of Triton Na2CO3 concentrations at constant temperature (80oC) Triton X-100 Na2CO3 Contact Contact Contact Contact Contact (wt %) (wt %) angle angle angle angle angle after after 1 after 6 after 12 after 24 aging hr (deg) hr (deg) hr (deg) hr (deg) (deg) 0.5 0.0 130 123 117 109 107 1.0 0.0 127 119 113 104 102 1.5 0.0 125 118 112 102 100 0.5 0.5 124 114 107 100 97 1.0 0.5 120 112 105 98 95 1.5 0.5 117 108 103 97 94 0.5 1.0 118 107 100 93 88 1.0 1.0 116 105 98 88 87 1.5 1.0 114 104 95 87 85 0.5 1.5 116 103 90 88 87 1.0 1.5 113 102 96 86 84 1.5 1.5 112 101 94 83 82 0.5 2.0 115 102 93 84 81 1.0 2.0 111 100 91 81 79 1.5 2.0 110 99 89 80 73

X-100 surfactant concentrations and Contact angle after 48 hr (deg)

Contact angle after 72 hr (deg)

Contact angle after 96 hr (deg)

100 96 93 92 88 86 82 80 78 79 76 73 72 69 61

97 94 90 85 81 80 77 74 71 73 71 69 65 63 53

90 87 86 84 80 78 73 70 68 65 62 58 55 50 47