Article pubs.acs.org/EF
Possible Role of Asphaltenes in the Stabilization of Water-in-Crude Oil Emulsions Jan Czarnecki,*,† Plamen Tchoukov,†,‡ and Tadeusz Dabros‡ †
Department of Chemical and Materials Engineering, University of Alberta, Edmonton, Alberta T6G 2G6, Canada CanmetENERGY, Natural Resources Canada, Devon, Alberta T9G 1A8, Canada
‡
ABSTRACT: Asphaltene hierarchical aggregation contributes to water-in-oil (W/O) emulsion stability by forming a network structure within thin oil film, separating approaching water droplets. This structure changes the rheology of the film-forming oil to non-Newtonian, which prevents the film drainage at thickness less than about 50−100 nm. It also provides a steric stabilization mechanism to the system. Asphaltenes do not have well-defined hydrophilic heads and hydrophobic tails and, thus, do not have amphiphilic character. Therefore, they are not similar to surfactants and cannot stabilize emulsions the way classic emulsifiers do. The proposed stabilization mechanisms do not invoke any surfactant-like behavior of asphaltenes. Instead, they solely rely on asphaltene aggregation propensity.
■
To illustrate this point a little further, let us compare “typical” structures of a surfactant and asphaltene molecules shown in Figure 1
INTRODUCTION Emulsions create problems and challenges in many industries, but it is in the petroleum industry, in particular, that these problems are very well-recognized and dealt with on a large scale. Crude oil always contains some brine; it may be as little as below 1% or as much as over 70% of the total volume of the produced liquids. Most of the produced water is present in the form of large drops and lenses and can be easily removed. When the liquids start to flow from the reservoir into the well bore or through turbulent flow on chokes and valves and on centrifugal pump impellers, the liquids are subjected to vigorous agitation, resulting in emulsification. Emulsification is aided by the presence of natural surfactants, always present in crude oils with widely varying content. The emulsified water, often in the form of small 1−5 μm droplets, is very difficult to separate. Salts carried with the emulsified water pose serious corrosion problems for pipelines and downstream refineries. Millions of dollars are spent daily on preventing the formation of water-incrude oil (W/CO) emulsions or on breaking them once they have formed. Despite the enormous industrial significance of W/CO emulsions, their exact stabilization mechanism is not yet fully understood. The existing and widely accepted paradigm claims that W/CO emulsions are almost exclusively stabilized by asphaltenes, and hundreds of papers in the scientific literature support this claim with experimental data (see, e.g., refs 1−4 and references therein). Asphaltenes are defined as a solubility class and not as a specific family of chemicals with common functional groups. Individual chemical molecules in the asphaltene group differ in molecular weight, composition, functionality, polarity, and just about any property, except their insolubility in n-alkanes. However, general statements are often made referring to asphaltenes as the most heavy, polar, and surface-active components of crude oils. Such generalizations are misleading, especially when discussing the role of asphaltenes in the stabilization of petroleum emulsions, where a specific functionality rendering them surface-active is necessary. © 2012 American Chemical Society
Figure 1. (a) Typical molecular structure of a surfactant molecule (SDS, a widely used surfactant, is shown) and (b) molecular structure of an asphaltene molecule (according to the “island” model).
Figure 1a shows the molecular structure of sodium dodecyl sulfate (SDS), a widely used surfactant. A hydrophobic tail and hydrophilic head can be easily identified. This amphiphilic molecular structure is necessary for a chemical compound to be a surfactant. The term surfactant originates from “surface-active substance”. Here, surface activity is usually interpreted as the ability of a substance to decrease surface or interfacial tension of a liquid in which the substance is dissolved. This is a very broad Received: May 24, 2012 Revised: July 28, 2012 Published: August 13, 2012 5782
dx.doi.org/10.1021/ef300904a | Energy Fuels 2012, 26, 5782−5786
Energy & Fuels
Article
is flexible and very stable water-in-oil (W/O) emulsions are easily formed. Above the critical dilution, the oil−water interface is rigid and W/O emulsion droplets flocculate (this finding led to a new commercial froth treatment technology). Composition of the material collected from the emulsified droplets also changes at critical dilution.13,14 Above the critical dilution (or above the onset of asphaltene precipitation), the H/C ratio of the surface material is about 1.15, which is similar to the H/C ratio of asphaltenes.13 However, below the critical dilution (or below the onset of asphaltene precipitation), the H/C ratio of the surface material is much higher than that of asphaltenes, being about 1.32. This indicates that, under those conditions, emulsions are stabilized by other crude components, perhaps naphthenates, but not by asphaltenes.12 The question remains, how asphaltenes, which are not surfaceactive, act as emulsion stabilizers above or around the onset of asphaltene precipitation. The current paper is an attempt at answering this question based on reinterpretation of our previously published results of thin W/O emulsion liquid film studies.15
definition, because just about any dissolved substance, with the exception of strong electrolytes in water, would decrease surface tension. To be more specific, it is generally accepted that, to classify a substance as a surfactant, it must reduce surface tension very sharply at low concentrations. It has been suggested that, for water solutions, it must reduce the water surface tension by about 30 mJ/m2 or more at concentrations of 0.01 M or less.5 In this paper, we use the latter definition and use the term “surfactant” only for substances that strongly decrease surface tension. Figure 1b shows the molecular structure of a typical asphaltene molecule according to the “island” model.6 There are several alternative models of asphaltene molecules, which will be not discussed here. However, according to all of the models, no hydrophilic head can be clearly identified and asphaltene molecules consist mostly of hydrophobic moieties. Therefore, asphaltene molecules do not have amphiphilic character, which is necessary for strong surface activity and to be classified as a surfactant according to our criteria outlined above. It does not preclude weak surface activity of asphaltenes. Before roughly 1980, asphaltenes were believed to be present in crude oils in the form of colloidal-sized aggregates containing several high-molecular-weight molecules. Asphaltene aggregates were believed to be kept suspended in the parent oil by resins of substantially lower molecular weight. This model of resins peptizing asphaltene micelles was introduced by Nellensteyn7 and refined by Pfeiffer and Saal,8 resulting in the widely accepted “colloidal model” of asphaltene aggregates. In this model, asphaltene aggregates were referred to as micelles and were considered to be similar to inverted micelles formed in non-aqueous solutions of surfactants. Belief in the analogy between asphaltene aggregates and surfactant micelles is so widespread that there are numerous reports in the scientific literature on measurements of critical micelle concentration (cmc) for asphaltenes in organic solvents (usually from surface tension versus asphaltene concentration). However, the cmc concept, valid for surfactants in aqueous solutions, even with a very liberal interpretation of the micellization term, is certainly not applicable for asphaltenes and not even for surfactants in nonpolar, organic solvents.9 Asphaltenes are only weakly surface-active. Therefore, they cannot stabilize emulsions the way typical emulsifiers do. However, as mentioned above, there are literary hundreds of papers in scientific journals with experimental data supporting the notion that the W/CO emulsions are stabilized by asphaltenes. In the following, we will be trying to address this obvious contention. Learning from Previous Studies. Substantial new knowledge on emulsion stabilization in petroleum systems was gained from studies related to the extraction of bitumen from Canadian oil sands in northern Alberta. Because the density of bitumen is very close to that of water, a light hydrocarbon solvent has to be added to bitumen to lower the oil-phase density and viscosity, facilitating various water-removal operations. Studies of the impact of the solvent/bitumen ratio and solvent composition on the properties of water-indiluted bitumen emulsion provided important insight to W/CO emulsion stabilization mechanisms. The most important finding was that there is a critical solvent/bitumen ratio or critical dilution at which properties of the system drastically change.10−12 The critical dilution, which coincides with the onset of asphaltene precipitation, depends upon the solvent composition. Below the critical dilution, the oil−water interface
■
EXPERIMENTAL SECTION
Thin Liquid Film Technique. The properties of thin oil film that separate two water droplets play a key role for the stability of emulsion as a whole. The microinterferometric thin liquid film technique has been widely used for studies of foams and O/W emulsions and, recently, W/CO emulsions.16 When two water droplets approach each other, an approximately flat thin oil film is formed between them, as shown on the left-hand side of Figure 2. A similar film can be formed in the thin film
Figure 2. Principles of the thin liquid film technique. apparatus, as shown on the right-hand side of Figure 2. The details of the apparatus have been described in several books and numerous review papers.17,18 In our case, the cell holding the studied emulsion film housed in a thermostatted chamber (1) is placed on top of the Zeiss Axio Observer inverted microscope (2), equipped with a Leica DFC500 chargecoupled device (CCD) camera (3) and a Hamamatsu photodiode (4), enabling photo-interferometric measurements of the film thickness (see Figure 3). Pressure transducers Pg and Pr, via the pressure control system, allow for manipulation of the film diameter and thickness as well as provide information on the film disjoining pressure. The National Instruments (NI) data acquisition system feeds all of the data to a computer running NI LabVIEW custom interface, allowing for automation of many experimental functions. The thin liquid film technique allows for measurements of the thickness of common thin emulsion films with an accuracy of about 2 nm or so. The dependence of the thickness upon time gives information on the film drainage kinetics. The film thickness in combination with the known pressure applied to the film allows for estimation of the disjoining pressure isotherm. Our recent 5783
dx.doi.org/10.1021/ef300904a | Energy Fuels 2012, 26, 5782−5786
Energy & Fuels
Article
dimple as before, but contrary to typical behavior, the dimple does not drain. The area of the film outside the dimple is filled with discrete white dots (Figure 5a), which indicate that there are variations in the film thickness, with dots corresponding to a locally thicker film. Estimated thickness of those dots is about 50 nm or so. Their lateral dimensions are about a few micrometers. Also, inside the dimple, a number of local thicker areas become clearly visible (Figure 5b). We believe this behavior is caused by asphaltene aggregation. Shortly after film formation, very small aggregates are formed. They are likely identical to nanoaggregates postulated by Mullins.20 According to Mullins, nanoaggregates associate further, forming nanoaggregate clusters,20 which, through fractal-type association, eventually form an asphaltene precipitate. There is likely a continuous growth of asphaltene particles from nanoaggregates to nanoaggregate clusters to even larger assemblies of clusters, eventually leading to precipitation, without any sharp boundaries between them. Above the critical dilution ratio in heptane equal to about 1.6 (39 wt % bitumen),15,21 where the solubility of asphaltenes is even lower than in heptol 80:20, irregularities of the contact lines between the film and meniscus, non-draining lenses of trapped liquid, and precipitated particles are clearly visible in the emulsion film after aging the film for about 4 h (Figure 6). The lateral dimension of the liquid lenses in the film can be as large as tens of micrometers, and judging from several Newton rings around them, they can be above 1 μm thick. When the same solution (shown in panels a and b of Figure 5) was centrifuged at 20000g to remove all precipitated asphaltenes, allowed to age until the next day, and centrifuged again, the emulsion films prepared from this aged solution were very stable and homogeneous (Figure 5c). The film drainage of these films initially followed the prediction of Reynold’s law, shown as a dashed line in Figure 7b, until the film became about 65 nm thick, where the further drainage stopped and film thickness did not change further for the time of our experiment (i.e., for more than 20 min). At this stage, the film is about 3 times thicker than the final thickness of the film made from 50 wt % bitumen in heptol 80:20, which is shown in Figure 7a. This finding is counterintuitive. After the bitumen concentration was reduced and a significant amount of asphaltenes (a potentially stabilizing agent) was rejected, the film thickness increases. Although this result is unexpected on the basis of the thin film literature, it agrees well with our previous studies of the properties of the water−diluted bitumen interface. This finding supports the notion that only a small subfraction of the total asphaltenes is responsible for emulsion stabilization.11 Let us summarize the observations that do not fit the classical picture: (1) Dilution of bitumen and removing some of the “surface-active” material results in thicker and more stable films.
Figure 3. Thin liquid film apparatus. modifications to the technique allow for probing of the film with direct current (DC) and alternating current (AC) electrical signals, opening new ways of studying W/O emulsion films, including the stability.19
■
RESULTS AND DISCUSSION In this paper, we focus on drainage kinetics of the films made of Athabasca bitumen dissolved in heptol (a mixture of heptane and toluene at various solvent ratios). Figure 4 shows the typical behavior of the films below the critical dilution (the figure shows thinning of the film formed from 50 wt % bitumen solution in heptol 80:20, i.e., a heptane/toluene mixture at 80:20 by volume). For heptol 80:20, the critical dilution is about 3, corresponding to a bitumen concentration of about 25 wt %.15 As seen in the figure, shortly after formation, the film forms a thick dimple in the center, which quickly drains to the meniscus in one or several points, and after several minutes, the film reaches thickness below 50 nm. The film thinning follows theoretical predictions based on Reynold’s equation, as shown in Figure 7a below. This behavior is well-known and characteristic for foam and emulsion films stabilized by surfactants. This is in agreement with the finding reported by Czarnecki and Moran12 that, below critical dilution, the emulsions are likely stabilized by surfactants (e.g., sodium naphthenates). Above the critical dilution, the film thinning is quite different. All films prepared above the critical dilution, regardless of the bitumen concentration or solvent composition, behave in the way similar to that shown in panels a and b of Figure 5. Here, as an example, thinning of a film made from 10 wt % solution of bitumen in heptol 80:20 is shown. The film forms a thick
Figure 4. Film drainage below critical dilution (50 wt % bitumen in heptol 80:20). Stamps show the time after film formation (minutes:seconds). 5784
dx.doi.org/10.1021/ef300904a | Energy Fuels 2012, 26, 5782−5786
Energy & Fuels
Article
Figure 5. Film drainage above the critical dilution (10 wt % bitumen in heptol 80:20). Aging: (a) 15 min, (b) 2.5 h, and (c) solution aged 24 h and centrifuged.
Figure 6. Film drainage above the critical dilution (25 wt % bitumen in heptane). Film interfaces were aged for 4 h, and stamps show the time after film formation in minutes:seconds.
required to stop film drainage at hmin = 65 nm. Also, if a liquid is characterized by a non-zero yield stress, some liquid can be trapped in the dimple and will not drain through the surrounding barrier ring area in the film.25 Our estimates show that a yield stress from about 10−3 to 10−2 Pa will be sufficient to stop dimple drainage, as shown in Figure 5a. This Bingham yield stress may be too small to be measured by conventional rheological instruments but large enough to prevent further drainage of the thin oil film separating water droplets, thus providing an effective stabilization of the emulsion.
(2) Non-draining dimples and irregular contact lines appear in the films. Indeed, if the film liquid behaves as Newtonian, the liquid from the dimple has to drain out because of the pressure difference in the dimple and film meniscus.22 We speculate that the observed behavior is due to asphaltene aggregation into linear nano-sized aggregates, which are anchored at the water− oil interface. The formation of asphaltene nanoaggregates and their further assembly into larger moieties continues for a long time.21 Such behavior is consistent with findings by Gray et al., who analyzed supramolecular assembly of petroleum asphaltenes and model compounds and found evidence for the formation of fibrous, high pore volume, weak organic gels.23 The implications of this finding for emulsion stabilization have not been included in ref 23 but are obvious and outlined in more detail below. A buildup of a network on the length scale comparable to the film thickness must result in a non-Newtonian behavior of the liquid forming the film. Assuming Bingham plastic fluid, there will be a minimum thickness below which the film cannot drain. For a Bingham plastic fluid with yield stress τB and plastic viscosity μB, the relationship between the shear stress τ and shear rate is τ = τB + μB(−du/dy) for τ ≥ τB and 0 = μB(−du/dy) for τ < τB. Hartland and Jeelani24 provided asymptotic solutions to the film drainage problem when the film thickness approaches the limiting thickness hmin. According to eq 16a taken from ref 24, the relationship between hmin and τB is given by hmin = πnτBRf3/3F, where Rf is the film radius, F is the force acting on the film, and n = 2 is the number of immobile film surfaces. In the case of free emulsion films when the surface forces are negligible, the driving force for film drainage is due to the capillary pressure drop in the film Plateau border Pγ = 2γ/r (γ = 16 mJ/m2 is the interfacial tension and r = 400 μm is the radius of the hole in the fritted glass plate holding the film). For the film shown in Figure 7b (film radius Rf = 100 μm), we can estimate that yield stress of 0.078 Pa is
■
CONCLUDING REMARKS Asphaltene hierarchical aggregation (asphaletene molecules → nanoaggregates → aggregates → precipitate) is likely responsible for building a gel-like structure within the oil film separating approaching water droplets. The result of this structure formation is 2-fold: First, it changes the fluid rheology within the film to non-Newtonian with a very small but not negligible Bingham yield stress. This yield stress is too small to be measured in conventional rheometers but large enough to prevent film drainage. Second, it forms a steric layer, providing steric emulsion stabilization. Those mechanisms do not invoke any surfactant-like behavior of asphaltenes. They solely rely on aggregation propensity of asphaltenes. If correct, it calls for a totally different emulsion breaking strategy and likely different types of demulsifiers. Our findings do not contradict a weak adsorption of some asphaltene subfractions. On the contrary, asphaltene aggregates, either formed at the water−oil interface or adsorbed as such, are likely attached to the interface with several weak bonds. Their removal requires breaking multiple bonds at the same time, making it a highly improbable event. A more detailed discussion of asphaltene attachment to the oil−water interface 5785
dx.doi.org/10.1021/ef300904a | Energy Fuels 2012, 26, 5782−5786
Energy & Fuels
Article
Heavy Oils, and Petroleomics; Mullins, O., Sheu, E., Hammami, A., Marshall, A., Eds.; Springer: New York, 2007; pp 549−588. (5) Berg, J. C. An Introduction to Interfaces and Colloids; Word Scientific Publishing Co. Pte. Ltd.: Hackensack, NJ, 2010; pp 30−137. (6) Groenzin, H.; Mullins, O. Asphaltene molecular size and weight by time-resolved fluorescence depolarization. In Asphaltenes, Heavy Oils, and Petroleomics; Mullins, O., Sheu, E., Hammami, A., Marshall, A., Eds.; Springer: New York, 2007; pp 17−62. (7) Nellensteyn, F. I. J. Inst. Pet. Technol. 1924, 10, 211. (8) Pfeiffer, J. P.; Saal, R. N. J. J. Phys. Chem. 1940, 44, 139−149. (9) Friberg, S. Micellization. In Asphaltenes, Heavy Oils, and Petroleomics; Mullins, O., Sheu, E., Hammami, A., Marshall, A., Eds.; Springer: New York, 2007; pp 189−203. (10) Dabros, T.; Yeung, A.; Masliyah, J.; Czarnecki, J. J. Colloid Interface Sci. 1999, 210, 222−224. (11) Czarnecki, J. Energy Fuels 2009, 23, 1253−1257. (12) Czarnecki, J.; Moran, K. Energy Fuels 2005, 19, 2074−2079. (13) Wu, X. Energy Fuels 2003, 17, 179−190. (14) Stanford, L. A.; Rodgers, R. P.; Marshall, A. G.; Czarnecki, J.; Wu, X. A. Energy Fuels 2007, 21, 963−972. (15) Tchoukov, P.; Czarnecki, J.; Dabros, T. Colloids Surf., A 2010, 372, 15−21. (16) Taylor, S. D.; Czarnecki, J.; Masliyah, J. J. Colloid Interface Sci. 2002, 252, 149−160. (17) Sheludko, A. Adv. Colloid Interface Sci. 1967, 1, 391−464. (18) Platikanov, D.; Exerowa, D. Thin liquid films. In Fundamentals of Interface and Colloid Science; Lyklema, J., Ed.; Academic Press: New York, 2005. (19) Panchev, N.; Khristov, K.; Czarnecki, J.; Exerowa, D.; Bhattacharjee, S.; Masliyah, J. Colloids Surf., A 2008, 315, 74−78. (20) Mullins, O. Annu. Rev. Anal. Chem. 2011, 4, 393−418. (21) Long, Y.; Dabros, T.; Hamza, H. Selective solvent deasphalting for heavy oil emulsion treatment. In Asphaltenes, Heavy Oils, and Petroleomics; Mullins, O., Sheu, E., Hammami, A., Marshall, A., Eds.; Springer: New York, 2007; pp 511−547. (22) Frankel, S. P.; Mysels, K. J. J. Phys. Chem. 1962, 66, 190−191. (23) Gray, M. R.; Tykwinski, R. R.; Stryker, J. M.; Tan, X. Energy Fuels 2011, 25, 3125−3134. (24) Hartland, S.; Jeelani, S. A. K. Can. J. Chem. Eng. 1987, 65, 382− 390. (25) Hartland, S.; Jeelani, S. A. K. J. Phys. Chem. 1986, 90, 6054− 6059.
Figure 7. Film thinning of bitumen films diluted in heptol 80:20: (a) 50 wt % bitumen (below the critical dilution) and (b) 5 wt % bitumen (above the critical dilution).
and adsorption competition with surfactant-like crude components was presented elsewhere.12
■
AUTHOR INFORMATION
Corresponding Author
*Telephone: 1-780-492-8826. E-mail:
[email protected]. Notes
The authors declare no competing financial interest.
■
ACKNOWLEDGMENTS We thank Dr. Zhenghe Xu for helpful discussions. The authors express their gratitude to the Canadian government’s Panel of Energy Research and Development (PERD) for financial support of this project.
■
REFERENCES
(1) Sjoblom, J.; Johnsen, E. E.; Westvik, A.; Ese, M.-H.; Djuve, J.; Auflem, I. H.; Kallevik, H. Demulsifiers in the Oil Industry; Marcel Dekker: New York, 2001; pp 595−619. (2) McLean, J. D.; Kilpatrick, P. K. J. Colloid Interface Sci. 1997, 189, 242−253. (3) Kilpatrick, P. K.; Spiecker, P. M. Asphaltene emulsions. In Encyclopedic Handbook of Emulsion Technology; Sjoblom, J., Ed.; Marcel Dekker: New York, 2001; pp 707−730. (4) Sjoblom, J.; Hemmingsen, P. V.; Kallevik, H. The role of asphaltenes in stabilizing water-in-crude oil emulsions. In Asphaltenes, 5786
dx.doi.org/10.1021/ef300904a | Energy Fuels 2012, 26, 5782−5786
