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Water pH and surfactant addition effects on the stability of an Algerian crude oil emulsion
Journal of Saudi Chemical Society (2012) 16, 333–337
King Saud University
Journal of Saudi Chemical Society www.ksu.edu.sa www.sciencedirect.com
ORIGINAL ARTICLE
Water pH and surfactant addition effects on the stability of an Algerian crude oil emulsion Mortada Daaou
a,*
, Dalila Bendedouch
b
a
Department of Industrial Chemistry, Faculty of Sciences, University of Sciences and Technology of Oran, P.O. Box 1505, El m’naouer, Oran 31000, Algeria b Laboratory of Macromolecular Physical Chemistry, Faculty of Sciences, University of Oran (Es-senia), Oran 31000, Algeria Received 25 January 2011; accepted 29 May 2011 Available online 1 July 2011
KEYWORDS Emulsion stability; Test-bottle; Optical microscopy; pH; Crude oil; Surfactant
Abstract In many oil production sites water injection is used as a piston to push the crude out of the well. As the age of the field progresses, the ratio of water to oil produced increases. Agitation of a water and crude oil mixture may give stable water-in-oil emulsion in which the water remains dispersed for a long period of time. These emulsions can cause severe problems in production and transport processes since they normally possess high stability and viscosity. The most important water properties which may contribute to the emulsion stability include pH and additive content. In this study, we report on the effect of both, water pH and the presence of surfactant molecules (anionic, cationic or non-ionic) on the stability of an Algerian crude oil (Haoudh el Hamra well) aqueous emulsion prepared by a mechanical agitation procedure. The stability was followed by the test-bottle method to measure the resolved water separated from the emulsion, and optical microscopy to visualize the dispersed water droplets in the oil phase. The results of the effects of varying the aqueous-phase pH suggest that the neutral medium is more efficient than acidic or basic environment for stabilizing the emulsions. The addition of non-ionic surfactants has a better potential to improve crude oil emulsion stability with respect to both cationic and anionic surfactants which do not show any improvement in the oil/water phase compatibility. ª 2011 King Saud University. Production and hosting by Elsevier B.V. Open access under CC BY-NC-ND license.
* Corresponding author. Tel.: +213 550444965. E-mail address: [email protected] (M. Daaou). 1319-6103 ª 2011 King Saud University. Production and hosting by Elsevier B.V. Open access under CC BY-NC-ND license. Peer review under responsibility of King Saud University. doi:10.1016/j.jscs.2011.05.015
Production and hosting by Elsevier
1. Introduction Water in oil emulsion formation occurs at many stages in the production and treatment of crude oil. Water is used as a piston to push the crude out of the well during the process of oil production and to remove species such as chloride salts which poison refinery catalysts and enhance corrosion problems during refinery treatment. Agitation of a water and crude oil mixture may yield stable water-in-oil emulsion in which water remains dispersed for a long period of time. These emulsions can cause severe problems in production, transport and
334 treatment processes since they normally possess high stability and viscosity. Water can form gas hydrates and is also responsible for corrosion problems. Thus, for other reasons too, it is of interest to dehydrate the crude oils. An understanding of the stabilization mechanism and knowledge of the factors which affect this stabilization is a major concern of several authors (Mingyuan et al., 1992; McLean and Kilpatrick, 1997b; Gafonova and Yarranton, 2001; Li et al., 2002; Havre and Sjo¨blom, 2003; Ese and Kilpatrick, 2004). It is shown (McLean and Kilpatrick, 1997a,b; Yarranton et al., 2000) that the stability of water in crude oil emulsion depends mainly on a rigid protective film encapsulating the water droplets. It is believed that this interfacial film is composed predominantly by natural surfactants contained in crude oil i.e. asphaltenes, resins and fatty acids (Sjo¨blom et al., 1992; Spiecker and Kilpatrick, 2004). These substances may accumulate at the water–oil interface and hinder the droplets to coalesce and phase separate. Among these components, asphaltenes are believed to be the major ones stabilizing the emulsion. Indeed, most of the time, the other two components, cannot alone produce stable emulsions (Lee, 1999). Moreover, they may in some cases associate to asphaltene molecules and affect emulsion stability. In particular, resins could solubilize asphaltenes in oil by the way preventing them from associating in order to form the interfacial film and, therefore, lower the emulsion stability. The asphaltenes represent the heaviest and most polar fraction of the crude oil and their representative molecule contains mainly a sheet of more or less condensed aromatic rings with aliphatic side chains and various functional groups (Strausz et al., 1992; Daaou et al., 2006; Bouhadda et al., 2007; Daaou et al., 2009). With these structural characteristics, asphaltenes exhibit surface activity and act as natural emulsifiers (see Fig. 1; Taylor, 1992; Sheu et al., 1995; Schildbreg et al., 1995; McLean and Kilpatrick, 1997a,b; Sztukowski et al., 2003). However, they
Figure 1 Mechanism of emulsion stabilization: asphaltenic thin film formation at the oil/water interface (McLean and Kilpatrick, 1997a,b).
M. Daaou, D. Bendedouch do not operate as individual molecules, but through an aggregated state (McLean and Kilpatrick, 1997a). The interfacial film is not monomolecular but is constituted by asphaltene aggregates which accumulate at the surface of the water droplets. Consequently, the propensity of asphaltenes to flocculate in crude oil enhances the water-in-oil emulsion stability (Sztukowski et al., 2003). This is the case of the Algerian crude oil from the Haoudh El Hamra well in the Hassi Messaoud oil field whose production is continuously perturbed by the aggregation and deposition of asphaltenes (Daaou et al., 2009). Therefore, it appeared of some interest to study the stability of aqueous emulsions containing this particular oil. The interfacial film and hence the emulsion stability can be affected by many factors like water-pH and additive content (Schramm, 1992; Poteau et al., 2005; Fortuny et al., 2007). Literature reports a multitude of pH and chemical addition effects on crude oil/water systems which show different behaviors for different oil origins (Strassner, 1968; Pathak and Kumar, 1995; McLean and Kilpatrick, 1997a; Goldszal et al., 2002). For instance, Poteau et al.(2005), show that pH has a strong influence on interfacial properties of asphaltenes at the Venezuelan crude oil/water interface and that at high or low pH, asphaltenes functional groups become charged, enhancing their surface activity. Recently, Fortuny et al. (2007) studied the effects of salinity, temperature, water content and pH on the stability of crude oil emulsions upon microwave treatment and found that the demulsification process was achieved with high efficiencies for emulsions containing high water contents except when high pH and salt contents were simultaneously involved. Emulsion destabilization occurs in several steps (Graham et al., 2008): flocculation, coalescence, and finally phase separation or sedimentation. The flocculation of water droplets in water-in-oil emulsions involves their aggregation in order to form clusters. During the coalescence step, the clusters fuse to form larger droplets, this process can eventually lead to phase separation or sedimentation under the influence of gravity. Emulsion stability may be determined by a number of methods, such as the bottle test and electrical methods (Wang and Alvarado, 2009). The most common method in the labscale is the simple bottle test: varied amounts of potential demulsifiers are added into a series of tubes or bottles containing each the same amount of an emulsion to be broken (Mat, 2006). More recently, Moradi et al. (2011) studied the effect of salinity on water-in-crude oil emulsion through the measure of droplet-size distribution visualized by an optical microscopy method. They indicate that emulsions are more stable at lower ionic strength of the aqueous phase, a result consistent with those obtained by electrorheology and bottle tests (Wang et al., 2010). The present work investigates the influence of both water pH and the addition of surfactants (cationic, anionic and non ionic) on the stability of a model emulsion made of 40 vol.% of the Algerian Haoudh El Hamra crude oil and 60 vol.% of water. It is designed as an attempt to contribute to the understanding of this water-in-oil emulsion behavior in order to provide ultimately technologic responses to some oil production problems specific to this crude. Sodium dodecyl sulfate (SDS), dodecyl triphenylphosphonium bromide (DTPB) and decyl-tri-oxyethylene alcohol (C10E3) are selected since they are well known compounds representative of each surfactant type. The optical microscopy is used to confirm
Water pH and surfactant addition effects on the stability of an Algerian crude oil emulsion the water-in-oil emulsion type and the bottle test method is employed to evaluate the emulsion stability. 2. Experimental
335
droplets in the oil phase to confirm the existence of water in oil (w/o) type emulsion (Balinov et al., 1994; Nandi et al., 2003; Zhang et al., 2009; Moradi et al., 2011). The sample images corresponding to a stable emulsion are taken with a digital Sony camera.
2.1. Chemicals 3. Results and discussion The oil is from Haoudh el Hamra well of the Algerian HassiMessaoud field. Its general specifications are given in Table 1 as determined by the Refinery Company laboratory. The different chemicals used in this work were purchased from Sigma products Company with a nominal purity of 98%. 2.2. Emulsion preparation 2.2.1. Water pH effect The aqueous solutions of different pH were prepared by mixing adequate amounts of NH4OH in demineralized distilled water for basic solutions (pH: 8–13), whereas acidic medium (pH: 2–6) was prepared with HCl in water. The pH value for each solution was controlled by a digital pH meter – Model IN-112 apparatus. Sixty milliliters of the aqueous phase at different pH was added to 40 ml of the crude oil. The mixture was then homogenized by mechanical agitation (Ultra Turrax T 25 basic, IKAWerke) at 2500 rpm during 15 min at 20 C.
3.1. Effect of water pH The emulsion samples left to stand are observed and the results are depicted in Fig. 2a. Obviously, aqueous-phase pH affects the emulsion stability. For acidic medium, the separated water volume varies from 3 vol.% to 36 vol.% as water pH varies from 1 to 6. The largest volume (36%) is reached at pH = 6. In the basic medium (pH = 8–13), separated water is comprised between 2 vol.% and 15 vol.%. The least stable emulsion occurs for weakly acid environment. At pH = 7, the emulsion is the most stable since no water separates and the w/o emulsion type is confirmed by optical microscopy which visualizes the dispersion of water droplets in the oil phase (Fig. 2b). The system is also relatively stable at very low and moderately basic pH. These results are comparable to those obtained by Strassner (1968) who studied crude oil emulsions at different pH values and found that Venezuelan crude oil
2.2.2. Surfactant addition effect Sixty milliliters of brine water containing 3.5 wt% of NaCl and 100 ppm of one of the surfactants were added to 40 ml of crude oil and homogenized as described in the previous section. The operation was repeated for each surfactant. An aliquot of each sample was immediately poured into a 10 ml graduated bottle which was left to stand at 20 C up to 24 h until water separated (Daaou et al., 2005a,b). 2.3. Emulsion stability determination The stability was monitored by measuring the volume of separated water from the emulsion by the test bottle method. Indeed, the lower the emulsion stability, the larger the water partition. The amount of separated water is directly correlated to the instability of the emulsion since destruction of the interfacial film and subsequent water droplet coalescence is the determinant step in the demulsification process (McLean and Kilpatrick, 1997a). 2.4. Water droplet dispersion visualization An Axiostar optical microscope (Carl Zeiss) using a 40· objective with 0.45 lm resolution is used to visualize dispersed water
Table 1
General characteristics of Hassi-Messaoud crude oil. ðd20 4 Þ
Density Total acid number (mg KOH/1 g) Asphaltenes (wt%) Resins (wt%) Resins/asphaltenes
0.83 0.28 0.60 6.50 10.80
Figure 2 (a) Separated water volume for various water pH. (b) Water droplet dispersion in the crude oil at pH = 7 (optical microscopy).
336
M. Daaou, D. Bendedouch
Figure 3
pH of separated water vs. emulsified water pH.
100
82
Separated water (%vol.)
90
85
80 70
Figure 5 Surfactant type effect on kinetic stability of surfactant in brine water/crude oil emulsion.
the film that destroy the film structure (McLean and Kilpatrick, 1997a,b). 3.2. Effect of surfactant addition
60 50 40 30 20
18
10 0
C10E3
DTPB
SDS
Surfactants
Figure 4
Effect of surfactant type on emulsion stability after 24 h.
emulsions at pH < 6 are highly stable, while those at pH > 10 exhibit low stability or are highly unstable although at pH = 13 the emulsion was very stable. The pH effect on emulsion stability is usually attributed to ionization of polar groups of surface active components which induce sufficient electrostatic repulsive interactions to break down the interfacial film cohesion (McLean and Kilpatrick, 1997a). The residual aqueous-phase pH after demulsification is plotted as a function of the corresponding initial pH in Fig. 3. The plot shows that it is consistently less acidic when the initial pH is acidic and less basic when the initial pH is basic. This suggests that the native surface active compounds in the crude adsorbed at the oil/water interface contain strongly basic as well as weakly to strongly acidic functional groups. Indeed, the total acid number of this Algerian crude oil, as given on Table 1 classes it among the less acidic crudes. Depending on the pH, the functional groups may dissociate into the aqueous phase upon emulsification giving rise to large surface charge densities and subsequent internal repulsion in
Fig. 4 is a plot of the amounts of separated water against added surfactant type (anionic, cationic and non-ionic) 24 h after the sample preparation. It is noticed that the maximum stability is observed for the emulsion containing the non-ionic surfactant, whereas the ionic surfactants confer lesser stability to the emulsion. Fig. 5 shows the kinetic emulsion stability for each of the three surfactants. After 24 h, separated water is equal to 85, 82 and 18 vol.% for added DTPB, SDS and C10E3, respectively. These observations confirm that the emulsion which contains the non-ionic surfactant remains the most stable one. In the case of the ionic surfactants the polar head groups probably prevent or inhibit the formation of the associated asphaltene film at the oil/water interface leading to important emulsion instability. 4. Conclusion The instability of this Algerian crude oil-in-water emulsion is enhanced either by water pH induced ionization of the polar groups of the surface active components or the presence of electrically charged ionic surfactant heads imbedded in the interfacial film. Both circumstances induce sufficient electrostatic repulsive interactions to break down the interfacial film cohesion. This observation may be straightforwardly valued in an efficient demulsification process. References Bouhadda, Y., Bormann, D., Sheu, E., Bendedouch, D., Krallafa, A., Daaou, M., 2007. Characterization of Algerian Hassi-Messaoud Asphaltene structure using Raman spectrometry and X-ray diffraction. Fuel 86 (12–13), 1855–1864.
Water pH and surfactant addition effects on the stability of an Algerian crude oil emulsion Balinov, B., Urdahl, O., Soderman, O., Sjoblom, J., 1994. Characterization of water-in-crude oil emulsions by the NMR self-diffusion technique. Colloids Surfaces A: Physicochemical and Engineering Aspects 82, 173–181. Nandi, A., Agterof, W.G.M., Van den Ende, D., Mellema, J., 2003. Investigation of the effect of a simple salt on the kinetics of gravity induced coalescence for a viscosity matched emulsion system. Colloids Surfaces A: Physicochemical and Engineering Aspects 213, 199–208. Daaou, M., Bendedouch, D., Bouhadda, Y., 2005. Treatment of hydrocarbon waste water by demulsification process. In: 1st International Seminar in Environment and their Connected Problem (SIEPC2005), Universite´ Abderrahmane Mira, Be´jaia, Algeria (June 2005). Daaou, M., Bendedouch, D., Bouhadda, Y., 2005. Surfactants and water pH effect on the stability of an Algerian crude oil emulsion. In: Jordan International Chemical Engineering Conference V (JICCE05), University of Jordan, Jordan, September 2005. Daaou, M., Bendedouch, D., Bouhadda, Y., 2006. Structural characterization of a Hassi-Messaoud petroleum asphaltene. Journal of Saudi Chemical Society 10 (2), 339–346. Daaou, M., Bendedouch, D., Bouhadda, Y., Vernex-Loset, L., Modaressi, A., Rogalski, M., 2009. Explaining the flocculation of Hassi Messaoud asphaltenes in terms of structural characteristics of monomers and aggregates. Energy Fuels 23, 5556–5563. Ese, M.H., Kilpatrick, P.K., 2004. Stabilization of water-in-oil emulsions by naphthenic acids and their salts: model compounds, role of pH, and soap: acid ratio. Journal of Dispersion Science and Technology 25 (3), 253–261. Fortuny, M., Oliveira, C.B.Z., Melo, R.L.F.V., Nele, M., Coutinho, R.C.C., Santos, A.F., 2007. Effect of salinity, temperature, water content, and ph on the microwave demulsification of crude oil emulsions. Energy Fuels 21, 1358–1364. Gafonova, O.V., Yarranton, H.W., 2001. The stabilization of water inhydrocarbon emulsions by asphaltenes and resins. Journal of Colloid and Interface Science 241, 469–478. Graham, B.F., May, E.F., Trengove, R.D., 2008. Emulsion inhibiting components in crude oils. Energy Fuels 22, 1093–1099. Goldszal, A., Bourrel, M., Hurtevent, C., Volle, J.-L., 2002. The Third International Conference on Petroleum Phase Behavior and Fouling, New Orleans, USA. Havre, T.E., Sjo¨blom, J., 2003. Emulsion stabilization by means of combined surfactant multilayer (D-phase) and asphaltene particles. Colloids and Surfaces A: Physicochemical and Engineering Aspects 228, 131–142. Lee, R.F., 1999. Agents which promote and stabilize water in- oil emulsions. Spill Science and Technology Bulletin 5, 117–126. Li, M., Xu, M., Ma, Y., Wu, Z., Christy, A.A., 2002. The effect of molecular parameters on the stability of water-in-crude oil emulsions studied by IR and UV spectroscopy. Colloids and Surfaces A: Physicochemical and Engineering Aspects 197, 193–201. Mat, H.B., 2006. Study on demulsifier formulation for treating Malaysian crude oil emulsion. PhD Thesis, Department of Chemical Engineering, Faculty of Chemical and Natural Resources Engineering, Universiti Teknologi Malaysia. McLean, J.D., Kilpatrick, P.K., 1997a. Effects of asphaltene aggregation in model heptane–toluene mixtures on stability of water-in-oil emulsions. Journal of Colloid and Interface Science 196, 23–34.
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McLean, J.D., Kilpatrick, P.K., 1997b. Effect of asphaltene solvency on stability of water-in-crude-oil emulsion. Journal of Colloid and Interface Science 189, 242–253. Mingyuan, L., Christy, A.A., Sjoblom, J., 1992. Emulsions: A Fundamental and Practical Approach, NATO ASI Ser., vol. 363. Kluwer Academic publishers, Dordrecht, pp. 157. Moradi, M., Alvarado, V., Huzurbazar, S., 2011. Effect of salinity on water-in-crude oil emulsion: evaluation through drop-size distribution proxy. Energy Fuels 25, 260–268. Pathak, A.K., Kumar, T., 1995. Study of indigenous crude oil emulsions and their stability. In: Proceedings of PETROTECH95, the first International Petroleum Conference and Exhibition, New Delhi, January 9–12, 1995. Poteau, S., Argillier, J.F., Langevin, D., Pincet, F., Perez, E., 2005. Influence of pH on stability and dynamic properties of asphaltenes and other amphiphilic molecules at the oil–water interface. Energy Fuels 19, 1337–1341. Schildbreg, Y., Sjoblom, J., Christy, A.A., Volle, J., Rambeau, O., 1995. Characterization of interfacially active fractions and their relations to water-in-oil emulsion stability. Journal of Dispersion Science and Technology 16 (7), 575–605. Schramm, L.L. (Ed.), 1992. Emulsions: Fundamentals and Applications in the Petroleum Industry. Advances in Chemistry Series. American Chemical Society, Washington, DC. Sheu, E.Y., Storm, D.A., Shields, M.B., 1995. Adsorption kinetics of asphaltenes at toluene/acid solution interface. Fuel 74, 1475–1479. Sjo¨blom, J., Urdahl, O., Børve, K.C.N., Mingyuan, L., Saeten, J.O., Christy, A.A., Gu, T., 1992. Stabilization and destabilization of water-in-crude oil emulsions from the Norwegian continental shelf. Advances in Colloid and Interface Science 41, 241–271. Spiecker, M.P., Kilpatrick, P.K., 2004. Interfacial rheology of petroleum asphaltenes at the oil–water interface. Langmuir 20, 4022– 4032. Strassner, J.E., 1968. Effect of pH on interfacial films and stability of crude oil–water emulsions. Journal of Petroleum Technology 20 (3), 303–312. Strausz, O.P., Mojelsky, T.W., Lown, E.M., 1992. The molecular structure of asphaltene: an unfolding story. Fuel 71, 1355–1363. Sztukowski, D.M., Jafari, M., Alboudwarej, H., Yarranton, H.W., 2003. Asphaltene self-association and water-in-hydrocarbon emulsions. Journal of Colloid and Interface Science 265, 179–186. Taylor, S.E., 1992. Resolving crude oil emulsions. Chemical Industry 20, 770–773. Wang, X.Y., Alvarado, V.J., 2009. Direct current electrorheological stability determination of water-in-crude oil emulsions. Journal of Physical Chemistry B 113, 13811–13816. Wang, X.Y., Brandvik, A., Alvarado, V.J., 2010. Probing interfacial water-in-crude oil emulsion stability controls using electrorheology. Energy Fuels 24 (12), 6359–6365. Yarranton, H.W., Hussein, H., Masliyah, J.H., 2000. Water-inhydrocarbon emulsions stabilized by asphaltenes at low concentrations. Journal of Colloid and Interface Science 228, 52–63. Zhang, Y., Gong, J., Ren, Y., Wang, P., 2009. Energy Fuels 24, 1146– 1155.
King Saud University
Journal of Saudi Chemical Society www.ksu.edu.sa www.sciencedirect.com
ORIGINAL ARTICLE
Water pH and surfactant addition effects on the stability of an Algerian crude oil emulsion Mortada Daaou
a,*
, Dalila Bendedouch
b
a
Department of Industrial Chemistry, Faculty of Sciences, University of Sciences and Technology of Oran, P.O. Box 1505, El m’naouer, Oran 31000, Algeria b Laboratory of Macromolecular Physical Chemistry, Faculty of Sciences, University of Oran (Es-senia), Oran 31000, Algeria Received 25 January 2011; accepted 29 May 2011 Available online 1 July 2011
KEYWORDS Emulsion stability; Test-bottle; Optical microscopy; pH; Crude oil; Surfactant
Abstract In many oil production sites water injection is used as a piston to push the crude out of the well. As the age of the field progresses, the ratio of water to oil produced increases. Agitation of a water and crude oil mixture may give stable water-in-oil emulsion in which the water remains dispersed for a long period of time. These emulsions can cause severe problems in production and transport processes since they normally possess high stability and viscosity. The most important water properties which may contribute to the emulsion stability include pH and additive content. In this study, we report on the effect of both, water pH and the presence of surfactant molecules (anionic, cationic or non-ionic) on the stability of an Algerian crude oil (Haoudh el Hamra well) aqueous emulsion prepared by a mechanical agitation procedure. The stability was followed by the test-bottle method to measure the resolved water separated from the emulsion, and optical microscopy to visualize the dispersed water droplets in the oil phase. The results of the effects of varying the aqueous-phase pH suggest that the neutral medium is more efficient than acidic or basic environment for stabilizing the emulsions. The addition of non-ionic surfactants has a better potential to improve crude oil emulsion stability with respect to both cationic and anionic surfactants which do not show any improvement in the oil/water phase compatibility. ª 2011 King Saud University. Production and hosting by Elsevier B.V. Open access under CC BY-NC-ND license.
* Corresponding author. Tel.: +213 550444965. E-mail address: [email protected] (M. Daaou). 1319-6103 ª 2011 King Saud University. Production and hosting by Elsevier B.V. Open access under CC BY-NC-ND license. Peer review under responsibility of King Saud University. doi:10.1016/j.jscs.2011.05.015
Production and hosting by Elsevier
1. Introduction Water in oil emulsion formation occurs at many stages in the production and treatment of crude oil. Water is used as a piston to push the crude out of the well during the process of oil production and to remove species such as chloride salts which poison refinery catalysts and enhance corrosion problems during refinery treatment. Agitation of a water and crude oil mixture may yield stable water-in-oil emulsion in which water remains dispersed for a long period of time. These emulsions can cause severe problems in production, transport and
334 treatment processes since they normally possess high stability and viscosity. Water can form gas hydrates and is also responsible for corrosion problems. Thus, for other reasons too, it is of interest to dehydrate the crude oils. An understanding of the stabilization mechanism and knowledge of the factors which affect this stabilization is a major concern of several authors (Mingyuan et al., 1992; McLean and Kilpatrick, 1997b; Gafonova and Yarranton, 2001; Li et al., 2002; Havre and Sjo¨blom, 2003; Ese and Kilpatrick, 2004). It is shown (McLean and Kilpatrick, 1997a,b; Yarranton et al., 2000) that the stability of water in crude oil emulsion depends mainly on a rigid protective film encapsulating the water droplets. It is believed that this interfacial film is composed predominantly by natural surfactants contained in crude oil i.e. asphaltenes, resins and fatty acids (Sjo¨blom et al., 1992; Spiecker and Kilpatrick, 2004). These substances may accumulate at the water–oil interface and hinder the droplets to coalesce and phase separate. Among these components, asphaltenes are believed to be the major ones stabilizing the emulsion. Indeed, most of the time, the other two components, cannot alone produce stable emulsions (Lee, 1999). Moreover, they may in some cases associate to asphaltene molecules and affect emulsion stability. In particular, resins could solubilize asphaltenes in oil by the way preventing them from associating in order to form the interfacial film and, therefore, lower the emulsion stability. The asphaltenes represent the heaviest and most polar fraction of the crude oil and their representative molecule contains mainly a sheet of more or less condensed aromatic rings with aliphatic side chains and various functional groups (Strausz et al., 1992; Daaou et al., 2006; Bouhadda et al., 2007; Daaou et al., 2009). With these structural characteristics, asphaltenes exhibit surface activity and act as natural emulsifiers (see Fig. 1; Taylor, 1992; Sheu et al., 1995; Schildbreg et al., 1995; McLean and Kilpatrick, 1997a,b; Sztukowski et al., 2003). However, they
Figure 1 Mechanism of emulsion stabilization: asphaltenic thin film formation at the oil/water interface (McLean and Kilpatrick, 1997a,b).
M. Daaou, D. Bendedouch do not operate as individual molecules, but through an aggregated state (McLean and Kilpatrick, 1997a). The interfacial film is not monomolecular but is constituted by asphaltene aggregates which accumulate at the surface of the water droplets. Consequently, the propensity of asphaltenes to flocculate in crude oil enhances the water-in-oil emulsion stability (Sztukowski et al., 2003). This is the case of the Algerian crude oil from the Haoudh El Hamra well in the Hassi Messaoud oil field whose production is continuously perturbed by the aggregation and deposition of asphaltenes (Daaou et al., 2009). Therefore, it appeared of some interest to study the stability of aqueous emulsions containing this particular oil. The interfacial film and hence the emulsion stability can be affected by many factors like water-pH and additive content (Schramm, 1992; Poteau et al., 2005; Fortuny et al., 2007). Literature reports a multitude of pH and chemical addition effects on crude oil/water systems which show different behaviors for different oil origins (Strassner, 1968; Pathak and Kumar, 1995; McLean and Kilpatrick, 1997a; Goldszal et al., 2002). For instance, Poteau et al.(2005), show that pH has a strong influence on interfacial properties of asphaltenes at the Venezuelan crude oil/water interface and that at high or low pH, asphaltenes functional groups become charged, enhancing their surface activity. Recently, Fortuny et al. (2007) studied the effects of salinity, temperature, water content and pH on the stability of crude oil emulsions upon microwave treatment and found that the demulsification process was achieved with high efficiencies for emulsions containing high water contents except when high pH and salt contents were simultaneously involved. Emulsion destabilization occurs in several steps (Graham et al., 2008): flocculation, coalescence, and finally phase separation or sedimentation. The flocculation of water droplets in water-in-oil emulsions involves their aggregation in order to form clusters. During the coalescence step, the clusters fuse to form larger droplets, this process can eventually lead to phase separation or sedimentation under the influence of gravity. Emulsion stability may be determined by a number of methods, such as the bottle test and electrical methods (Wang and Alvarado, 2009). The most common method in the labscale is the simple bottle test: varied amounts of potential demulsifiers are added into a series of tubes or bottles containing each the same amount of an emulsion to be broken (Mat, 2006). More recently, Moradi et al. (2011) studied the effect of salinity on water-in-crude oil emulsion through the measure of droplet-size distribution visualized by an optical microscopy method. They indicate that emulsions are more stable at lower ionic strength of the aqueous phase, a result consistent with those obtained by electrorheology and bottle tests (Wang et al., 2010). The present work investigates the influence of both water pH and the addition of surfactants (cationic, anionic and non ionic) on the stability of a model emulsion made of 40 vol.% of the Algerian Haoudh El Hamra crude oil and 60 vol.% of water. It is designed as an attempt to contribute to the understanding of this water-in-oil emulsion behavior in order to provide ultimately technologic responses to some oil production problems specific to this crude. Sodium dodecyl sulfate (SDS), dodecyl triphenylphosphonium bromide (DTPB) and decyl-tri-oxyethylene alcohol (C10E3) are selected since they are well known compounds representative of each surfactant type. The optical microscopy is used to confirm
Water pH and surfactant addition effects on the stability of an Algerian crude oil emulsion the water-in-oil emulsion type and the bottle test method is employed to evaluate the emulsion stability. 2. Experimental
335
droplets in the oil phase to confirm the existence of water in oil (w/o) type emulsion (Balinov et al., 1994; Nandi et al., 2003; Zhang et al., 2009; Moradi et al., 2011). The sample images corresponding to a stable emulsion are taken with a digital Sony camera.
2.1. Chemicals 3. Results and discussion The oil is from Haoudh el Hamra well of the Algerian HassiMessaoud field. Its general specifications are given in Table 1 as determined by the Refinery Company laboratory. The different chemicals used in this work were purchased from Sigma products Company with a nominal purity of 98%. 2.2. Emulsion preparation 2.2.1. Water pH effect The aqueous solutions of different pH were prepared by mixing adequate amounts of NH4OH in demineralized distilled water for basic solutions (pH: 8–13), whereas acidic medium (pH: 2–6) was prepared with HCl in water. The pH value for each solution was controlled by a digital pH meter – Model IN-112 apparatus. Sixty milliliters of the aqueous phase at different pH was added to 40 ml of the crude oil. The mixture was then homogenized by mechanical agitation (Ultra Turrax T 25 basic, IKAWerke) at 2500 rpm during 15 min at 20 C.
3.1. Effect of water pH The emulsion samples left to stand are observed and the results are depicted in Fig. 2a. Obviously, aqueous-phase pH affects the emulsion stability. For acidic medium, the separated water volume varies from 3 vol.% to 36 vol.% as water pH varies from 1 to 6. The largest volume (36%) is reached at pH = 6. In the basic medium (pH = 8–13), separated water is comprised between 2 vol.% and 15 vol.%. The least stable emulsion occurs for weakly acid environment. At pH = 7, the emulsion is the most stable since no water separates and the w/o emulsion type is confirmed by optical microscopy which visualizes the dispersion of water droplets in the oil phase (Fig. 2b). The system is also relatively stable at very low and moderately basic pH. These results are comparable to those obtained by Strassner (1968) who studied crude oil emulsions at different pH values and found that Venezuelan crude oil
2.2.2. Surfactant addition effect Sixty milliliters of brine water containing 3.5 wt% of NaCl and 100 ppm of one of the surfactants were added to 40 ml of crude oil and homogenized as described in the previous section. The operation was repeated for each surfactant. An aliquot of each sample was immediately poured into a 10 ml graduated bottle which was left to stand at 20 C up to 24 h until water separated (Daaou et al., 2005a,b). 2.3. Emulsion stability determination The stability was monitored by measuring the volume of separated water from the emulsion by the test bottle method. Indeed, the lower the emulsion stability, the larger the water partition. The amount of separated water is directly correlated to the instability of the emulsion since destruction of the interfacial film and subsequent water droplet coalescence is the determinant step in the demulsification process (McLean and Kilpatrick, 1997a). 2.4. Water droplet dispersion visualization An Axiostar optical microscope (Carl Zeiss) using a 40· objective with 0.45 lm resolution is used to visualize dispersed water
Table 1
General characteristics of Hassi-Messaoud crude oil. ðd20 4 Þ
Density Total acid number (mg KOH/1 g) Asphaltenes (wt%) Resins (wt%) Resins/asphaltenes
0.83 0.28 0.60 6.50 10.80
Figure 2 (a) Separated water volume for various water pH. (b) Water droplet dispersion in the crude oil at pH = 7 (optical microscopy).
336
M. Daaou, D. Bendedouch
Figure 3
pH of separated water vs. emulsified water pH.
100
82
Separated water (%vol.)
90
85
80 70
Figure 5 Surfactant type effect on kinetic stability of surfactant in brine water/crude oil emulsion.
the film that destroy the film structure (McLean and Kilpatrick, 1997a,b). 3.2. Effect of surfactant addition
60 50 40 30 20
18
10 0
C10E3
DTPB
SDS
Surfactants
Figure 4
Effect of surfactant type on emulsion stability after 24 h.
emulsions at pH < 6 are highly stable, while those at pH > 10 exhibit low stability or are highly unstable although at pH = 13 the emulsion was very stable. The pH effect on emulsion stability is usually attributed to ionization of polar groups of surface active components which induce sufficient electrostatic repulsive interactions to break down the interfacial film cohesion (McLean and Kilpatrick, 1997a). The residual aqueous-phase pH after demulsification is plotted as a function of the corresponding initial pH in Fig. 3. The plot shows that it is consistently less acidic when the initial pH is acidic and less basic when the initial pH is basic. This suggests that the native surface active compounds in the crude adsorbed at the oil/water interface contain strongly basic as well as weakly to strongly acidic functional groups. Indeed, the total acid number of this Algerian crude oil, as given on Table 1 classes it among the less acidic crudes. Depending on the pH, the functional groups may dissociate into the aqueous phase upon emulsification giving rise to large surface charge densities and subsequent internal repulsion in
Fig. 4 is a plot of the amounts of separated water against added surfactant type (anionic, cationic and non-ionic) 24 h after the sample preparation. It is noticed that the maximum stability is observed for the emulsion containing the non-ionic surfactant, whereas the ionic surfactants confer lesser stability to the emulsion. Fig. 5 shows the kinetic emulsion stability for each of the three surfactants. After 24 h, separated water is equal to 85, 82 and 18 vol.% for added DTPB, SDS and C10E3, respectively. These observations confirm that the emulsion which contains the non-ionic surfactant remains the most stable one. In the case of the ionic surfactants the polar head groups probably prevent or inhibit the formation of the associated asphaltene film at the oil/water interface leading to important emulsion instability. 4. Conclusion The instability of this Algerian crude oil-in-water emulsion is enhanced either by water pH induced ionization of the polar groups of the surface active components or the presence of electrically charged ionic surfactant heads imbedded in the interfacial film. Both circumstances induce sufficient electrostatic repulsive interactions to break down the interfacial film cohesion. This observation may be straightforwardly valued in an efficient demulsification process. References Bouhadda, Y., Bormann, D., Sheu, E., Bendedouch, D., Krallafa, A., Daaou, M., 2007. Characterization of Algerian Hassi-Messaoud Asphaltene structure using Raman spectrometry and X-ray diffraction. Fuel 86 (12–13), 1855–1864.
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