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Salt SpheressInorganic Structures Isolated from Petroleum-Based Emulsions† Richard W. Cloud,‡ Samuel C. Marsh,§ Becky L. Ramsey,§ Robert A. Pultz,§ and Michael K. Poindexter*,§ Nalco Company, 1601 West Diehl Road, NaperVille, Illinois 60563-1198, and Nalco Energy SerVices, 7705 Highway 90-A, Sugar Land, Texas 77478 ReceiVed August 24, 2006. ReVised Manuscript ReceiVed December 31, 2006
The characterization of water-in-crude-oil emulsions can be more challenging than resolving such emulsions. In production, achieving dry crude oil and clean water is a key requirement for uninterrupted operation. Minimizing the buildup of unresolved emulsion at the oil-water interface is another closely related element in the overall process of demulsification. Most oilfield emulsions are never completely resolved before being sent downstream for refining. For example, Karl Fisher measurements always show some water present in the oil phase. Investigations were performed to probe select features of unresolved emulsions. Using the American Society for Testing and Materials D4807-88 procedure, which involves diluting samples with hot toluene, emulsion solids were isolated and then studied using scanning electron microscopy and energy dispersive spectrometry. The characterization of the solids from several different oilfield emulsions revealed interesting structures that might be called “salt spheres” or “salt scaffolds”. These skeletal structures appear to outline once existent water droplets. In one case study, partly flocculated or coalesced salt structures were identified. The occurrence of these more complex structures gives the impression that the demulsification process was frozen in time. In another study, a partially filled salt sphere was isolated. Such a structure would likely remain with the crude oil in downstream processing as undesaltable solids and cause corrosion in the high-temperature process vessels as well as contribute to the poisoning of catalyst beds. It is not clear whether these inorganic artifacts contributed to the stability of the original emulsion or resulted from the lab isolation method. Nonetheless, the existence of these intriguing structures provides indirect evidence regarding the importance of solids in stabilizing emulsions.
Introduction Dependent upon process conditions and fluid properties, the separation of crude oil and water can be a challenge in the oilfield. With regard to process conditions, low process temperatures,1-3 short-residence times in separation vessels,4 and high shear across chokes5 are several parameters that can hinder emulsion resolution. Likewise, crude oils with high interfacial viscosity,6,7 high bulk viscosity3 (which is often associated with high asphaltene content), asphaltenes near their solubility limit,8 naphthenic acids,9 solids,10-12 and paraffins † Presented at the 7th International Conference on Petroleum Phase Behavior and Fouling. * To whom correspondence should be addressed: Nalco Energy Services, 7705 Highway 90-A, Sugar Land, TX 77478. Telephone: 281-263-7505. Fax: 281-263-7221. E-mail:
[email protected]. ‡ Nalco Company. § Nalco Energy Services. (1) Jones, T. J.; Neustadter, E. L.; Whittingham, K. P. Water-in Crude Oil Emulsion Stability and Emulsion Destabilization by Chemical Demulsifiers. J. Can. Pet. Technol. 1978, 17, 100-108. (2) Benayoune, M.; Khezzar, L.; Al-Rumhy, M. Viscosity of Water in Oil Emulsions. Pet. Sci. Technol. 1998, 16, 767-784. (3) Hemmingsen, P. V.; Silset, A.; Hannisdal, A.; Sjo¨blom, J. Emulsions of Heavy Crude Oils. I: Influence of Viscosity, Temperature and Dilution. J. Dispersion Sci. Technol. 2005, 26, 615-627. (4) Simmons, M. J. H.; Wilson, J. A.; Azzopardi, B. J. Interpretation of the Flow Characteristics of a Primary Oil-Water Separator from the Residence Time Distribution. Chem. Eng. Res. Des. 2002, 80, 471-481. (5) Kokal. S.; Al-Juraid, J. Quantification of Factors Affecting Emulsion Stability. J. Petrol. Technol. 2000, 52, 41-42. (6) Gladden, G. P.; Neustadter, E. L. Oil/Water Interfacial Viscosity and Crude Oil Emulsion Stability. J. Inst. Petrol. 1972, 58, 351.
processed at low temperatures13 can all be problematic. These two primary factors, process conditions and crude oil properties, periodically couple in such a way to produce extremely stable water-in-oil emulsions. In some production schemes, vessels upstream of the primary separation vessel, often called freewater knockouts,14 allow for the removal of nonemulsified water, (7) Neustadter, E. L.; Whittingham, K. P.; Graham, D. E. Interfacial Rheological Properties of Crude Oil/Water Systems. In Proceedings of the Symposium on Surface Phenomena in Enhanced Oil RecoVery; Shah, D. O., Ed.; Plenum: New York, 1981 (meeting date 1979); pp 307-326. (8) Kilpatrick, P. K.; Spiecker, P. M. Asphaltene Emulsions. In Encyclopedic Handbook of Emulsion Technology; Sjo¨blom, J., Ed.; Marcel Dekker: New York, 2001; Chapter 30, pp 707-730. (9) Goldszal, A.; Bourrel, M.; Hurtevent, C.; Volle, J.-L. Stability of Water in Acidic Crude Oil Emulsions. In Spring AIChE Meeting; American Institute of Chemical Engineers (AIChE): New Orleans, LA, March 1114, 2002; pp 386-400. (10) Aveyard, R.; Clint, J. H. Solid Particles at Liquid Interfaces, Including Their Effects on Emulsion and Foam Stability. In Adsorption and Aggregation of Surfactants in Solution; Surfactant Science Series; Marcel Dekker: New York, 2003; Vol. 109, Chapter 3, pp 61-90. (11) Menon, V. B.; Wasan, D. T. A Review of the Factors Affecting the Stability of Solids-Stabilized Emulsions. Sep. Sci. Technol. 1988, 23, 21312142. (12) Menon, V. B.; Wasan, D. T. Characterization of Oil-Water Interfaces Containing Finely Divided Solids with Applications to the Coalescence of Water-in-Oil Emulsions: A Review. Colloids Surf. 1988, 29, 7-27. (13) Thompson, D. G.; Taylor, A. S.; Graham, D. E. Demulsification and Demulsification Related to Crude Oil Production. Colloid Surf. 1985, 15, 175-189. (14) Manning, F. S.; Thompson, R. E. Dehydration of Crude Oil. In Oilfield Processing. Volume 2: Crude Oil; PennWell: Tulsa, OK, 1995; Chapter 6, pp 79-112.
10.1021/ef060431o CCC: $37.00 © 2007 American Chemical Society Published on Web 02/14/2007
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which readily separates from the incoming production. To speed and enhance oil-water separation for the remainder of the produced emulsion, downstream vessels often employ heat treatment to reduce viscosity, centrifuges, and electrostatic coalescers.15,16 Proper level control within each of the separation vessels is critical to achieve oil-water separation.14 Even though oil-water separation problems arise and can be severe at times, adjustments to the process can generally be found such that on-specification crude oil is produced for pipeline delivery. The addition of chemicals1,17-19 that aid in demulsification often plays a significant role in achieving dry oil because this method allows for periodic optimization as the field and emulsion evolve with time. Certain demulsifiers can also handle temporary upsets because of processing well workover fluids.20 Blends of chemicals can (1) greatly accelerate the coalescence of water droplets, (2) flocculate small water droplets remaining in the oil phase, and (3) maintain oil-water interfaces such that unwanted rag layers (i.e., unresolved emulsion) do not build in size and limit production. It is the combination of these three parameters that ultimately determines whether the emulsion is effectively resolved. While optimized treatment conditions result in on-specification crude oil, there remains the nagging question concerning the origin of emulsion stability. Because crude oils are highly complex and crude oil composition varies widely from oil to oil, answering such questions remains a formidable challenge.21 In this regard, the origins of emulsion stability remain crudeoil-specific because each is likely unique in composition. Still, commonality exists among many of the crude oils produced, and elegant model studies have attempted to identify the role of certain crude oil components toward stabilizing emulsions. Asphaltenes alone, asphaltenes with resins,22,23 naphthenic acids, paraffins, inorganic solids, and solvency of the dispersion media24 have all been studied, with asphaltenes receiving the bulk of the attention. Recent work using crude oil emulsions from the oilfield, not lab model studies, has demonstrated that inorganic solid content is the factor that most readily predicts emulsion stability.25 In these studies, solids from the field emulsions were isolated using (15) Eow, J. S.; Ghadiri, M.; Sharif, A. O.; Williams, T. J. Electrostatic Enhancement of Coalescence of Water Droplets in Oil: A Review of the Current Understanding. Chem.sEng. J. 2001, 84, 173-192. (16) Eow, J. S.; Ghadiri, M. Electrostatic Enhancement of Coalescence of Water Droplets in Oil: A Review of the Technology. Chem.sEng. J. 2002, 85, 357-368. (17) Staiss, F.; Bohm, R.; Kupfer, R. Improved Demulsifier Chemistry: A Novel Approach in the Dehydration of Crude Oil. SPE Prod. Eng. 1991, 6, 334-338. (18) Becker, J. R. Oil Emulsion Breakers. In Crude Oil Waxes, Emulsions and Asphaltenes; PennWell: Tulsa, OK, 1997; Chapter 4, pp 67-81. (19) Mikula, R. J.; Munoz, V. A. Characterization of Demulsifiers. In Surfactants: Fundamentals and Applications in the Petroleum Industry; Schramm, L. L., Ed.; Cambridge University Press: Cambridge, U.K., 2000; Chapter 2, pp 51-77. (20) Hyne, N. J. Dictionary of Petroleum Exploration, Drilling, and Production; PennWell: Tulsa, OK, 1991. (21) Marshall, A. G.; Rodgers, R. P. Petroleomics: The Next Grand Challenge for Chemical Analysis. Acc. Chem. Res. 2004, 37, 53-59. (22) Schorling, P.-C.; Kessel, D. G.; Rahimian, I. Influence of the Crude Oil Resin/Asphaltene Ratio on the Stability of Oil/Water Emulsions. Colloids Surf., A 1999, 152, 95-102. (23) Yang, X.; Lu, W.; Ese, M.-H.; Sjo¨blom, J. Film Properties of Asphaltenes and Resins. In Encyclopedic Handbook of Emulsion Technology; Sjo¨blom, J., Ed.; Marcel Dekker: New York, 2001; Chapter 23, pp 525-540. (24) McLean, J. D.; Kilpatrick, P. K. Effects of Asphaltene Aggregation in Model Heptane-Toluene Mixtures on Stability of Water-in-Oil Emulsions. J. Colloid Interface Sci. 1997, 196, 23-34. (25) Poindexter, M. K.; Chuai, S.; Marble, R. A.; Marsh, S. C. Solid Content Dominates Emulsion Stability Predictions. Energy Fuels 2005, 19, 1346-1352.
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the American Society for Testing and Materials (ASTM) D480788 procedure.26 This method involves diluting the crude oil, which contains residual emulsion, with hot toluene, followed by filtration and further washing of the residue with hot toluene. The identity of the isolated solids was accomplished using scanning electron microscopy (SEM) and energy dispersive spectrometry (EDS).27 In some cases, the solids were composed mostly of common salts, specifically, sodium chloride and calcium sulfate, while in other cases, noticeable amounts of silica, aluminum, and iron were present. For three different crude oils, very interesting structures were identified that might be called “salt spheres” or “salt scaffolds”. In most instances, the salt spheres were truly scaffolds where the interior was hollow. These structures appear to outline water droplets that once existed in an oil continuous phase. In one instance, several salt spheres were found fused together leaving the impression that flocculation or coalescence was possibly captured. Another inorganic structure showed a salt sphere partially filled with sodium chloride. Should the isolated structures be representative of real-world processing conditions and not the result of the ASTM isolation method, the implications for downstream processing become apparent. These structures may provide examples of the very entities responsible for crude oils that are resistant to salt removal. Experimental Section Materials. Toluene used for dilution of the crude oils as well as the model studies was HPLC-grade and used as received from J.T. Baker. Light mineral oil (8042-47-5) and heptane for the model studies were used as received from Aldrich and EMD, respectively. Nylon membrane filters (0.45 µm pore size, 47 mm in diameter) were from Whatman. Crude Oil and Model Emulsions. Crude oil emulsions were obtained in the field just after the wellhead and were initially free of demulsifier. However, some of the crude oils characterized in this study contained demulsifiers because they were subsequently treated with demulsifier in field bottle testing.28,29 Demulsified crude oil was subsequently used for the crude oil characterizations. Notes will be made in the text regarding the presence or absence of demulsifier for each crude oil analyzed. Similar to real-world crude oils containing residual water, which age before arriving at the refinery, these emulsions were allowed to age for a period of months before the solids were isolated and characterized. Model emulsions were generated by adding field process water to the organic phase with continuous shearing followed by an additional 3 min of shearing using a Sentry/Tempest IQ2 mechanical homogenizer from VirTis. Characterization of Crude Oil and Water Samples. A literature procedure was used to fractionate the oil phase of the resolved emulsions into their saturate, aromatic, resin, and asphaltene (SARA) components.30 It is important to realize that SARA results are dependent upon the fractionation procedure.31 Only the (26) ASTM D4807-88. Standard Test Method for Sediment in Crude Oil by Membrane Filtration, 1999. (27) Cloud, R. W.; Ramsey, R. L.; Pultz, R. A.; Poindexter, M. K. Characterization of Solids from Oilfield Emulsions. Microscopy Today 2005, November, 28. (28) Leopold, G. Breaking Produced-Fluid and Process-Stream Emulsions. In EmulsionssFundamentals and Applications in the Petroleum Industry; Schramm, L. L. Ed.; American Chemical Society: Washington, D.C., 1992; Chapter 10, pp 341-383. (29) Manning, F. S.; Thompson, R. E. Dehydration of Crude Oil. In Oilfield Processing Volume 2: Crude Oil; PennWell: Tulsa, OK, 1995; Chapter 7, pp 113-143. (30) Poindexter, M. K.; Zaki, N. N.; Kilpatrick, P. K.; Marsh, S. C.; Emmons, D. H. Factors Contributing to Petroleum Foaming. 1. Crude Oil Systems. Energy Fuels 2002, 16, 700-710. (31) Speight, J. G. The Chemistry and Technology of Petroleum, 3rd ed.; Marcel Dekker: New York, 1998; pp 269-278.
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Solid-Stabilized Emulsions and Their Isolation. Numerous model studies have addressed the role that inorganic solids play in stabilizing emulsions, and several thorough reviews on the topic exist.10-12 While solids alone are well-known to stabilize emulsions,33,34 it is the interaction of the more polar crude oil components (e.g., asphaltenes and resins) with inorganic solids that represents and greatly enhances the stability of emulsions encountered in the oilfield.35-39 As noted in laboratory studies by Sztukowski and Yarranton, the combination of asphaltenes
and solids results in some of the most stable emulsions.40 It is important to keep in mind that asphaltenes and resins are not chemical classes but rather solubility/polarity classes.41 They are often described by distributions or ranges of properties (e.g., hydrogen/carbon ratios) rather than by specific functional groups or well-defined molecular weights42 as is generally the case with most organic structures. Asphaltenes and resins are thus naturally rich in complexity, and their interaction with solids remains an active area of research.43 Field studies using crude oil emulsions from numerous production sites have also shown that solids, when compared to 10 other crude oil properties, are the key factor in predicting emulsion stability.25 These studies used several field bottle test results to gauge emulsion stability. Stability was determined by the rate of water drop, the water content remaining in the oil phase, and the oil dryness at the oil-water interface.28,29 The crude oils used in the study covered a broad range of API gravities (10-31°), and thus, the conclusions were not based on a narrow range of crude oil properties or values. Solid content had the greatest ability to predict all of the emulsion stability parameters. No other crude oil property approached the predictive ability of solid content. Furthermore, the nature of the solids was not necessary to describe emulsion stability. This would seem to agree with the importance of inorganic solids interacting with polar organic-based crude oil components to produce entities prone to stabilize water-in-oil emulsions. Once the inorganic solids are coated with the polar crude oil fractions, the resulting solids readily act as emulsion stabilizers. To investigate the nature of the inorganic solids stabilizing these field-based emulsions, the oil phase above the resolved water phase of numerous emulsions was sampled at various depths and subjected to ASTM D4807-88, a method used to quantify the inorganic sediment in crude oil.26 The procedure involves diluting the oil sample with hot toluene, filtering the resulting solution through a tared filter membrane, and then washing the solids with hot toluene. Dilution and washing with toluene effectively strips the solids of their organic coating. Once isolated, the solids were quantified gravimetrically and then subjected to a combination of SEM and EDS.32 This combined technique permits both physical characterization and compositional measurements of select sample features. To highlight differences in elemental composition via imaging with SEM, the backscatter electron detector was used in atomic number contrast mode, which enhances the variation in elemental composition while providing distinct sample morphology information. In the course of these examinations, several unique inorganic structures were identified. Characterization of Isolated Solids. To date, about 50 different SEM/EDS characterizations have been completed on various oilfield solids. In several instances, intriguing inorganic structures, which will be termed “salt spheres” or “salt scaf-
(32) Goldstein, J. I.; Newbury, D. E.; Echlin, P.; Joy, D. C.; Romig, A. D., Jr.; Lyman, C. E.; Fiori, C.; Lifshin, E. Scanning Electron Microscopy and X-Ray Microanalysis: A Text for Biologists, Materials Scientists and Geologists; 2nd ed.; Plenum: New York, 1992. (33) Pickering, S. U. Emulsions. J. Chem. Soc. 1907, 91, 2001-2021. (34) Aveyard, R.; Binks, B. P.; Clint, J. H. Emulsions Stabilized Solely by Colloidal Particles. AdV. Colloid Interface Sci. 2003, 100-102, 503546. (35) Kotlyar, L. S.; Sparks, B. D.; Woods, J. R.; Chung, K. H. Solids Associated with the Asphaltene Fraction of Oil Sands Bitumen. Energy Fuels 1999, 13, 346-350. (36) Yan, N.; Gray, M. R.; Masliyah, J. H. On Water-in-Oil Emulsions Stabilized by Fine Solids. Colloids Surf., A 2001, 193, 97-107. (37) Gafonova, O. V.; Yarranton, H. W. The Stabilization of Water-inHydrocarbon Emulsions by Asphaltenes and Resins. J. Colloid Interface Sci. 2001, 241, 469-478.
(38) Sullivan, A. P.; Kilpatrick, P. K. The Effects of Inorganic Solid Particles on Water and Crude Oil Emulsion Stability. Ind. Eng. Chem. Res. 2002, 41, 3389-3404. (39) Sztukowski, D. M.; Yarranton, H. W. Characterization and Interfacial Behavior of Oil Sands Solids Implicated in Emulsion Stability. J. Dispersion Sci. Technol. 2004, 25, 299-310. (40) Sztukowski, D. M.; Yarranton, H. W. Oilfield Solids and Waterin-Oil Emulsion Stability. J. Colloid Interface Sci. 2005, 285, 821-833. (41) Speight, J. G. The Chemistry and Technology of Petroleum, 3rd ed.; Marcel Dekker: New York, 1998; pp 31-33. (42) Strausz, O. P.; Peng, P.; Murgich, J. About the Colloidal Nature of Asphaltenes and the MW of Covalent Monomeric Units. Energy Fuels 2002, 16, 809-822. (43) Hannisdal, A.; Ese, M.-H.; Hemmingsen, P. V.; Sjo¨blom, J. ParticleStabilized Emulsions: Effect of Heavy Crude Oil Components Pre-adsorbed onto Stabilizing Solids. Colloids Surf., A 2006, 276, 45-58.
heavier components, resins and asphaltenes, will be reported. Crude oil viscosities were determined at 25 °C using a Brookfield Viscometer Model LVT. Metal content was determined using a Jarrell-Ash 61E inductively coupled argon plasma emission spectrometer. American Petroleum Institute (API) gravities and water densities were obtained using a Paar Density Meter DMA 48 set to 15.56 and 25 °C, respectively. Characterization of Solids. Solid content is defined by the ASTM D4807-88 procedure. In summary, 10 g of crude oil was weighed to the nearest 0.0001 g and then diluted with 100 mL of toluene. The solution was heated to 90 °C and filtered through a tared 0.45 µm pore-size nylon filter membrane. After a hot toluene rinse, the filter paper was dried and weighed to the nearest 0.0001 g. Solid levels are reported in pounds per thousand barrels (PTB).20 Solids isolated from the crude oils were then characterized using SEM and EDS. Most of the initial studies were done using a Cambridge (now Zeiss SMT) 360 SEM equipped with a Noran Instruments (now Thermo Electron Corp.) Vantage II EDS system. Current analyses utilize a Hitachi S-3400N SEM while still using the Vantage system. To provide sample conductivity for the analyses, a thin coating of graphite was evaporated onto each membrane prior to examination. All samples were then examined under normal high vacuum conditions in the SEM. Typical operation of the SEM used an excitation voltage of 20 keV with a variable probe current dependent upon the output type desired. For imaging output, a low probe current was used to reduce any charging artifacts. For EDS compositional analysis, a higher probe current was selected to increase data collected and optimize elemental statistics. With the unusual shapes common to these samples, sites for all EDS analyses were carefully selected to minimize any negative effects, which may result from a poor sample/detector geometry. To best highlight any differences in elemental composition via imaging with the SEM, the backscatter electron detector was used in atomic number contrast mode. Backscatter electron images (BEI) also provide adequate information on distinct sample morphologies. In several instances, EDS analyses for composition are shown for selected solid components. The combined technique of SEM/EDS32 allows for a simple and direct way of providing both physical characterization and direct compositional measurement of discrete sample features. As a result, this technique can best define the formation of these unique features, which form out of the crude oil emulsions.
Results and Discussion
Salt Spheres
Figure 1. (a) BEI of solids isolated from a deepwater GOM crude oil emulsion. (b) EDS reveals that the structure is mostly sodium chloride with a small amount of calcium. The residual carbon (C) and oxygen (O) are from the background filter paper.
folds”, were identified. The first group of salt spheres identified came from emulsion produced on a deepwater Gulf of Mexico (GOM) platform. Their BEI are shown in Figure 1. Initially, these structures, composed of mostly sodium and chloride along with a small amount of calcium, were considered an anomaly. The water phase from the crude oil emulsion was very high in salt content, having a density of 1.1001 g/mL; however, this brine was not at the saturation point.44 Additionally, the sample originated from crude oil containing demulsifier at a level of parts per million. Thus, it was unclear whether these two factors, high salt content or the presence of demulsifier, contributed to the formation of the structures. The structures in Figure 1 depict two, well-defined larger salt spheres and two smaller spheres. They leave the impression that several different sizes of water droplets were stabilized (i.e., emulsified) in the crude oil and were unable to settle out of the continuous oil phase. The diameter of the two larger spheres (ca. 80 µm) is noticeably large compared to many literature values. Model emulsion studies generally report dispersed water droplets in a smaller size range (e.g., 1-3,45 1-30,38 2-50,13 and 5-50 µm46). Clearly, the conditions and oils used to (44) CRC Handbook of Chemistry and Physics; Lide, D. R., Ed.; CRC Press: Boca Raton, FL, 2003; Chapter 8, p 79. (45) Dabros, T.; Yeung, A.; Masliyah, J.; Czarnecki, J. Emulsification through Area Contraction. J. Colloid Interface Sci. 1999, 210, 222-224. (46) McLean, J. D.; Kilpatrick, P. K. Effects of Asphaltene Solvency on Stability of Water-in-Crude-Oil Emulsions. J. Colloid Interface Sci. 1997, 189, 242-253.
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Figure 2. (a) BEI of solids isolated from a deepwater GOM crude oil emulsion, free of demulsifier. (b) EDS spectrum reveals that the structure is mostly sodium chloride with a small amount of calcium and sulfur. Similar to Figure 1, the residual carbon (C) and oxygen (O) are from the background filter paper.
generate the emulsions dictate the observed size ranges for the dispersed phase. However, for certain pressure drops, recent lab studies calculated a maximum surviving drop size of 93 µm. This size was confirmed visually using microscope analyses.47 Thus, the size of the large salt spheres observed in Figure 1, which were derived from a field emulsion, are not unrealistic. A second sample of the GOM emulsion depicted in Figure 1 but free of demulsifier was studied using the same separation and characterization techniques. Examination revealed salt scaffolds as shown in Figure 2. Thus, the presence of demulsifier was not responsible for the formation of the scaffolds. Upon closer examination of the structures, there also appeared a finely divided material embedded between the larger sodium chloride crystals (Figure 3). The particular structure shown in Figure 3 appears to be partially collapsed. From EDS, the finely divided material was high in calcium and sulfur, which indicates that calcium sulfate was participating in the salt-sphere structures. The importance of calcium sulfate in possibly stabilizing the salt spheres will be discussed in more detail later. Examination of other crude oil emulsions also yielded similar structures, with each providing a slightly different perspective on the role inorganic solids may play in stabilizing emulsions. As shown in Figure 4, solids isolated from a South American (47) Fossen, M.; Arntzen, R.; Hemmingsen, P. V.; Sjo¨blom, J.; Jakobsson, J. A Laboratory-Scale Vertical Gravity Separator for Emulsion Characterization. J. Dispersion Sci. Technol. 2006, 27, 453-461.
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Figure 3. (a) BEI of the salt sphere from the GOM, free of demulsifier, with focus on bridging finely divided solids (B). (b) As seen in the EDS spectrum, the bridging material is high in calcium and sulfur.
Figure 4. (a) BEI of South American emulsion, free of demulsifier, revealing the outline of several linked droplets. (b) EDS spectrum represents localized solids (C), which are high in calcium sulfate, between larger sodium chloride crystals.
emulsion, which was demulsifier-free, gave a more complex structure. Several distinct water droplets have aggregated to form a cluster. It is not possible to say if the interior of the structure is completely hollow and coalescence has occurred, if there are salt barriers between each of the aggregates and flocculation has resulted, or if both mechanisms have occurred to some degree. Similar to Figure 3, close examination of this more intricate structure revealed areas high in calcium sulfate. The density of water from the South American emulsion was 1.0411 g/mL. Thus, an extremely high salt content, which was the case for the GOM emulsion, is not a prerequisite for forming salt scaffolds. A third emulsion from the U.S. West Coast also gave salt spheres (Figure 5), but these contained an outer gossamery film (calcium sulfate) that covered much of the bulk structure. This is in contrast to the previous structures that contained calcium sulfate as a bridging material in more localized areas. Furthermore, several of the individual sodium chloride cubes in Figure 5b appear to be almost isolated or suspended from adjacent cubes and held in place by the calcium sulfate film. Additionally, the density of the water phase from this emulsion (1.0086 g/mL) was quite low compared to the other two emulsions. These results further confirm that highly saline water is not necessary for the occurrence of salt scaffolds. Table 1 contains several water and crude oil characteristics for each of the three emulsions containing salt scaffolds. Select crude oil properties include asphaltene contents ranging from 1.7 to 5.7% (by weight), API gravities ranging from 18.0° to
28.8°, and room-temperature viscosities ranging from 18 to 230 cP. On the basis of the properties of these three oils, none would be considered identical. Nonetheless, none of the fluids would be classified at the extremes, i.e., heavy oils or condensates. The tabulated properties do not provide an apparent reason or indication as to when and where salt spheres might arise. As highlighted, water salinity does not determine the occurrence of salt spheres. What is apparent in the salt structures and water analyses is the coexistence of sodium chloride and calcium sulfate. Pioneering work by Neustadter et al. cites the importance of specific ions (particularly calcium) in emulsion stability.1,7 Using North Sea crude oils, they found that the condensing effect of calcium ions caused more stable emulsions as the interfacial films were rendered more incompressible. This was particularly true for two North Sea crude oils (Forties and Ninian), where formation waters having a high calcium/low magnesium ratio gave nonrelaxing films. The total salinity was not considered important in creating stable emulsions. Assuming that there is a connection, the total salinity also does not govern the formation of salt spheres. In continuation with the calcium theme, in a fourth emulsion obtained from eastern Montana and which did not exhibit salt spheres, there appeared an interesting interaction between the two salts under consideration (Figure 6). Thin calcium sulfate rods appear to have solidified first followed by encapsulation of sodium chloride cubes.27 The sodium and chloride levels measured in the rods likely result from the nearby cubic crystals.
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Figure 5. (a) BEI of solids isolated from a West Coast emulsion (magnification of 1500×). The large salt sphere has a diameter of about 40 µm. (b) Further magnification of the salt spheres (4000×). Crystal D is sodium chloride, while film E contains calcium and sulfur. Table 1. Select Properties of the Water and Oil Phases
water water density (g/mL) pH barium (ppm) calcium (ppm) magnesium (ppm) potassium (ppm) sodium (ppm) oil API gravity viscosity (cP at 25 °C) asphaltenes, A (wt %) resins, R (wt %) R/A PTB (ASTM D4807-88)a a
GOM
South America
West Coast
1.1001 5.9 83 4100 1400 320 28 000
1.0411 8.0 3 1100 250 190 21 000
1.0086 8.3 13 33 24 36 5800
18.0 230 3.8 12.3 3.2 173
28.8 18 1.7 7.3 4.3 624
21.5 79 5.7 6.4 1.1 168
PTB, pounds per thousand barrels.
The Montana structure in Figure 6 may provide a further clue as to what is occurring in the salt spheres. To use an analogy, the calcium sulfate may act like a coupler just as rebar is used to reinforce concrete structures or mortar is used to hold brick structures together.48 Thus, the calcium sulfate would act like the rebar or mortar, while the sodium chloride cubes would serve as the concrete or brick. Such a linked structure might have
Figure 6. (a) BEI of cubic (F) and rod (G) shaped crystals isolated from an eastern Montana emulsion containing residual demulsifier. (b) Line spectrum of cubic crystals (sodium chloride) and solid spectrum of thin rods enriched with calcium, sulfur, and potassium. Reproduced with permission from Microscopy Today.
tremendous structural integrity and be able to withstand the filtration conditions. Other emulsions, not illustrated in this paper, also showed salt crystals but no salt spheres nor any type of organized structure. The proper balance of salts and other possible conditions may not have existed in these other emulsions to permit their isolation and identification. Proper conditions may in fact be necessary for the isolation and survival of salt scaffolds. A second sample of the same South American emulsion but one containing demulsifier revealed two-dimensional salt structures (i.e., salt circles; Figure 7) but no three-dimensional structures. The planar structures may have at one time outlined water droplets but, upon filtration, collapsed because of the improper balance or arrangement of a well-developed inorganic framework. The interior of these structures contains higher levels of salt crystals compared to the exterior of the circles, indicating that these were once water droplets. It is clear that subjecting certain crude oils to ASTM D480788 yields salt spheres. However, it is not clear whether the isolation method generated the salt structures or if they were originally present in the emulsion. It is also conceivable that the isolation method enhanced the formation of the salt spheres, meaning that the structures were less prevalent in the original (48) For the use of metaphors, similes, and analogies in science, see Hoffman, R. MarginaliasThe Metaphor, Unchained. Am. Sci. 2006, September-October, 406-407.
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Cloud et al.
Figure 7. BEI of two-dimensional salt structures isolated from a South American emulsion.
emulsion but, upon filtration, further crystallization took place to generate the well-defined structures. Evidence for more complete inward crystallization is shown in Figure 8 where another type of salt structure was observed in the South American study. In this instance, the interior is partially filled with sodium chloride. Additionally, an enriched calcium film resides on the filter membrane. When these results are taken together, the BEI appears to depict a once existent water droplet that became highly saturated with salt and eventually crystallized, leaving behind a partially filled structure as opposed to the scaffolds discussed earlier. Another plausible mechanism may also be operative in the reported structures. Asphaltenes are known to have a strong association with water to form “microdroplets”.49 Thus, asphaltenes may have aided the diffusion of water from the droplet, leaving behind a highly concentrated, localized salt solution. The study by Andersen et al. also revealed that the addition of resins reduces the asphaltene-water interaction. Thus, the idea of asphaltenes aiding water diffusion may not apply to emulsified crude oils, which contain ample amounts of resin. As shown in Table 1, the resin content for the three crude oils containing salt spheres ranges from 6.4 to 12.3% (by weight) with resin/asphaltene ratios ranging from 1.1 to 4.3. These crude oils are not heavily weighted toward asphaltenes versus their lower molecular-weight resin counterparts. The ordered inorganic structures observed at the once existent oil-water interface may be in place as a result of ionic interactions with the more polar crude oil species (i.e., resins and asphaltenes) that are known to aggregate at the same interface. In essence, there could be both an organized organic film at the interface as well as a corresponding inorganic film. No matter what the mechanism or mechanisms are regarding emulsion stability, the presence of salts in crude oils has serious consequences in downstream processing. Certain crude oils are resistant to salt removal, and this results in both chloride corrosion and catalyst poisoning.50 The salt structures reported here, if truly present in crude oils and not an artifact of the isolation procedure, may illustrate part of the problem encountered in processing difficult to desalt crude oils. Removal of (49) Andersen, S. I.; Manuel del Rio, J.; Khvostitchenko, D.; Shakir, S.; Lira-Galeana, C. Interaction and Solubilization of Water by Petroleum Asphaltenes in Organic Solution. Langmuir 2001, 17, 307-313. (50) Batra, B.; Borchert, C. A.; Lewis, K. R.; Smith, A. R. Design Process Equipment for Corrosion Control. Chem. Eng. Prog. 1993, May, 68-76.
Figure 8. (a) BEI of a partially filled salt sphere isolated from a South American emulsion. (b) EDS spectrum shows the bulk solid (H) to be mostly sodium chloride, (c) while the faint residual film (I) in the BEI is enriched in calcium.
salts precipitated at the oil-water interface would likely be much more difficult to achieve than removal of water droplets containing dissolved salt. Resolving the former situation would require not just contact with wash water but also dissolution of precipitated salt. Preliminary Model Studies. Laboratory-based model systems are often used to study real-world crude oil emulsion stability mechanisms. Varying amounts of asphaltenes and/or resins are typically added to heptol (i.e., heptane-toluene mixtures). Shearing the organic phase with added water makes emulsions. In a similar fashion, model studies using crude oil fractions isolated from the GOM and West Coast emulsions were conducted to try to recreate the salt spheres. For the oil phase, heptane-precipitated asphaltenes or asphaltenes plus resins were added to a toluene/heptane mixture (45:55 by volume). This ratio of toluene/heptane is prone to induce asphaltene precipitation and enhance emulsion stabilization.24 Process water from the original emulsions was used as the dispersed phase.
Salt Spheres
After the phases were mixed at 15 000 rpm for 3 min, the emulsions were allowed to age for 4 days. For model studies, this time frame has been reported sufficient to form nonrelaxing organic films.1 The solutions were then filtered and subjected to the same SEM procedures. Only in one study was a thin film of salt mildly organized, but no highly ordered salt structures (spheres or circles) were observed. It is important to clarify that, even if model studies did yield salt structures, the result would neither confirm nor disprove the existence of salt spheres in the real-world crude oil emulsions. Definitive proof seems possible only by detecting salt spheres in the native emulsion. The dark crude oils coupled with two mobile phases make for a difficult to resolve moving target. Oil-water interfaces coated with organic polar entities further complicate an in situ analysis. To further investigate the conditions necessary for salt-sphere formation, four control studies containing no asphaltenes or resins were also conducted. The emulsions were formed by adding either the GOM or West Coast process water to mineral oil (1:4 water/oil by volume) that contained either 0.1 or 1.0% dodecylbenzenesulfonic acid, a common surfactant. Similar to the previously described model studies, the control mixtures were sheared and aged for 3 days. Filtration followed by SEM analysis revealed no organized salt structures. The intent of the control studies was to indirectly probe the importance of asphaltenes and resins with regard to salt-sphere existence. If salt spheres were isolated even once in the control studies, it would clearly eliminate the premise that asphaltenes and resins might help in the formation of salt spheres. The reverse, however, is not true. The absence of such structures does not mean that polar organic species, such as asphaltenes and resins, are necessarily involved in salt-sphere formation.
Energy & Fuels, Vol. 21, No. 3, 2007 1357
Conclusions Salt spheres and related structures were isolated and characterized from three different crude oils. These structures appear to have once outlined water-in-oil droplets. Crude oil and water properties from the three oils do not seem to indicate that a given property is responsible for the formation of salt spheres. The presence of demulsifiers and degree of water salinity are not responsible for the formation of the structured salt scaffolds. The occurrence of salt spheres seems more dependent upon the interaction of two salts, sodium chloride and calcium sulfate. Their interaction appears to lead to the formation of highly stable inorganic frames. Still, the work presented here does not rule out the possibility that the isolation method causes or enhances the formation of the inorganic structures. To help resolve this point and the overall picture of emulsion stability, additional work is needed to find conditions, provided that they exist, that will leave the more polar organic entities intact as a coating yet not unduly cause precipitation of asphaltenes. The existence of salt scaffolds suggests that inorganic species may also play a role in both emulsion stability and salt removal. With regard to emulsion stability, salt spheres may form a second interfacial film, one that complements the well-known asphaltenic films. From a real-world perspective, crude oils prone to inefficient desalting are known to cause downstream processing problems (corrosion and catalyst poisoning). The structures isolated in this work may provide evidence of what hidden entities might exist in difficult to desalt crude oils. Acknowledgment. We are grateful to Nalco Energy Services for permission to publish this work. EF060431O
