Energy Fuels 2010, 24, 2376–2382 Published on Web 01/21/2010
: DOI:10.1021/ef901063e
Further Investigations into the Nature of Salt Spheres and Inorganic Structures at the Crude Oil-Water Interface† Richard W. Cloud,‡ Samuel C. Marsh,§ Sandra Linares-Samaniego,§ and Michael K. Poindexter*,§ ‡
Nalco Company, 1601 West Diehl Road, Naperville, Illinois 60563-1198 and §Nalco Company, 7705 Highway 90-A, Sugar Land, Texas 77478 Received September 20, 2009. Revised Manuscript Received December 6, 2009
A number of factors are known to contribute to and enhance water-in-crude oil emulsion stability. Organic-based and naturally occurring materials (e.g., asphaltenes, resins, naphthenic acids, waxes, etc.) have received a great deal of attention regarding their role in stabilizing and, at times, destabilizing petroleum-based emulsions. While these materials are known to reside at the oil-water interface, inorganic constituents are likewise known to contribute to emulsion stability and have been shown to also reside at the oil-water interface. To study the inorganic components in unresolved oilfield emulsions, numerous field samples were subjected to the American Society for Testing and Materials D4807-88 procedure that involves a hot toluene filtration. This method effectively removes the organic phase and isolates the inorganic components that may have also played a role in emulsion stabilization. The residual inorganic residues were initially characterized by a combination of scanning electron microscopy (SEM) and energy-dispersive spectrometry (EDS). Following up on the initial report where several samples contained highly organized inorganic structures, called salt spheres or salt scaffolds, this study takes a closer look into their compositional makeup using enhanced EDS capability with the addition of digital compositional mapping (DCM). Salts with low solubility-product constants appear to outline once existent water-in-crude oil droplets and, thus, may have played a key role in emulsion stabilization. Sodium chloride crystals often dominate the interior of these structures, and it is this entity that upon further examination was found to be unstable with regard to prolonged exposure to humidity. In comparison to dry or treated sales oils, inorganic solid levels from the oil-water interface of two oilfield separators were found to be considerably higher, with one of the samples containing an abundance of well-defined salt spheres. By use of the DCM technique, the separator sample was shown to contain salt spheres with an outer coating of strontium sulfate.
oil and water chemistry, coupled with their degree of mixing4 and gradually changing ratio,5 is further compounded by varying separation schemes and conditions designed to meet the production needs for the life of the field.6 When production facilities produce from the same reservoir, the problem-solving process can sometimes be shortened by best practice comparisons. With regard to the contributions of crude oil chemistry in stabilizing water-in-crude oil emulsions, asphaltenes,7 the asphaltene/resin ratio,8,9 naphthenic acids,10,11 waxes,12 and
Introduction A great many factors are known to contribute to waterin-crude oil emulsion stability.1-3 Some oilfield production facilities require little effort to produce on-specification crude oil, while others may require a concentrated effort to optimize process conditions and a chemical treatment program to achieve the same results. Pinpointing and solving the cause or causes of emulsion stability can be a lengthy yet useful and rewarding endeavor. The payoff is a better understanding of the system and naturally the production of both on-specification oil and water. The challenge of oil-water separation partly results from the uniqueness of each production facility. The complexity of crude
(5) Borges, B.; Rond on, M.; Sereno, O.; Asuaje, J. Breaking of waterin-crude-oil emulsions. 3. Influence of salinity and water-oil ratio on demulsifier action. Energy Fuels 2009, 23, 1568–1574. (6) Manning, F. S.; Thompson, R. E. Field processing of crude oil. In Oilfield Processing; PennWell: Tulsa, OK, 1995; Vol. 2: Crude Oil, Chapter 5, pp 61-78. (7) Kilpatrick, P. K.; Spiecker, P. M. Asphaltene emulsions. In Encyclopedic Handbook of Emulsion Technology; Sj€oblom, J., Ed.; Marcel Dekker: New York, 2001; Chapter 30, pp 707-730. (8) 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. (9) Al-Sahhaf, T.; Elsharkawy, A.; Fahim, M. Stability of water-incrude oil emulsions: Effect of oil aromaticity, resins to asphaltene ratio, and pH of water. Pet. Sci. Technol. 2008, 26, 2009–2022. (10) Goldszal, A.; Bourrel, M.; Hurtevent, C.; Volle, J.-L. Stability of water in acidic crude oil emulsions. In Spring AIChE Meeting, New Orleans, LA, March 11-14, 2002; pp 386-400. (11) Arla, D.; Sinquin, A.; Palermo, T.; Hurtevent, C.; Graciaa, A.; Dicharry, C. Influence of pH and water content on the type and stability of acidic crude oil emulsions. Energy Fuels 2007, 21, 1337–1342.
† Presented at the 10th International Conference on Petroleum Phase Behavior and Fouling. *To whom correspondence should be addressed: The Dow Chemical Company, 2301 N. Brazosport Blvd., B-1222, Freeport, TX 77541. Telephone: 979-238-1436. Fax: 979-238-0414. E-mail: mkpoindexter@ dow.com. (1) Emulsions—Fundamentals and Applications in the Petroleum Industry; Schramm, L. L., Ed.; American Chemical Society: Washington, D.C., 1992. (2) Encyclopedic Handbook of Emulsion Technology; Sj€oblom, J., Ed.; Marcel Dekker: New York, 2001. (3) Kokal, S. Crude oil emulsions: A state-of-the-art review. SPE Prod. Facil. 2005, 20, 5–13. (4) Kokal, S.; Al-Juraid, J. Quantification of factors affecting emulsion stability. J. Pet. Technol. 2000, 52, 41–42.
r 2010 American Chemical Society
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interfacial material having liquid crystalline structures have all been shown to play a role. Some studies have examined each component in isolation of the others via model studies, while other reports have examined crude oils that have an abundance of one or several components compared to other oils. Besides the organic-based materials listed, inorganic constituents are likewise known to contribute to emulsion stability,14-19 and similarly, they also have been found at the oil-water interface. Inorganic solids can originate from several sources: the reservoir,20 scale formation,21 and corrosion byproducts. Inorganic particle size, their profusion, chemical composition, and wettability have all been examined and shown to influence emulsion stability. While many different chemical entities, organic- as well as inorganic-based, can produce an emulsion, it is important to delineate that emulsions can be further classified with respect to their strength or ability to resist dehydration. This critical distinction was shown in model studies where various combinations of asphaltenes, resins, and inorganic solids were used to generate emulsions. While asphaltenes alone can produce stable emulsions, it was the combination of native solids and asphaltenes that produced the most stable emulsions.22 Results of this nature encourage further exploration into the role that inorganic solids play in emulsion stabilization. During crude oil production at some sites, there are occasional instances when very stable emulsions form. They can defy resolution, necessitating their isolation from production, when they are sometimes sent to a holding or slop (sludge) oil tank for special treatment or disposal.23 Slop oil studies are not frequently reported in the literature because they are not a common occurrence at most sites. Their appearance is often difficult to predict, and they are often resolved in the field before a formal study of their properties is initiated. They represent a special case of emulsion stability that can be the result of unique field excursions (e.g., production from well
workovers, chemical overtreatment, or sloughing off of solids from the wellbore). Interface pads or rag layers from oil-water separators can also sometimes contain a slop-like consistency. As long as the pad does not build-up over time but resides at a steady state, then production will remain uninterrupted. As will be described shortly, two oilfield separator interface pads were sampled and sent for laboratory analyses. Common features of both were their extremely high inorganic solid and water content. One of the interface pads contained structures similar to the previously reported salt spheres,24 allowing further examination, via digital compositional mapping (DCM),25 into the detailed ordering of different salts and other inorganic species around the spheres. Experimental Section Materials, Crude Oil, and Interface Material. Toluene used for dilution of the crude oils was HPLC-grade and used as received from J.T. Baker. Nylon membrane filters (0.45 μm pore size, 47 mm diameter) were from Whatman. Dry crude oils (i.e., sales oils) were obtained in the field just after the lease automatic custody transfer (LACT) unit.26 Samples were also taken from the interface of two oil-water separators (i.e., heater treaters).27 Characterization of Crude Oil and Solids. American Petroleum Institute (API) gravities were obtained using an Anton Paar density meter DMA 48 set to 15.56 °C. Residual water was determined by Karl Fischer titration according to American Society for Testing and Materials (ASTM) D4377. Solid content was 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. Following 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).26 Solids isolated from the crude oils were then characterized using scanning electron microscopy (SEM) and energy-dispersive spectrometry (EDS). SEM/EDS is a routine analytical method used to provide physical characterization (SEM) and elemental analysis (EDS) of a bulk solid material. SEM backscatter imaging (BEI), which is used for the current analyses, uses electrons that originate from the electron beam of the instrument after they have been “backscattered” out of the sample. The level of backscatter (or brightness) in the BEI image is directly related to the electron density of the sample. Because higher atomic number elements have progressively higher electron density, this imaging method allows for direct element differentiation down to less than one atomic number unit. As a result of electron beam excitation of the sample, X-rays are also produced that are specific to both the individual atoms present and the electron energy levels within the electron orbitals. These resulting X-rays from each atom will occur at defined energy differences based on electron exchange within each atom. The X-rays are then collected and separated along an energy scale (x axis) of the spectral profile for elemental identification. Initial studies were performed using a Cambridge 360 SEM equipped with a Thermo Electron Corporation Vantage II EDS
(12) Thompson, D. G.; Taylor, A. S.; Graham, D. E. Emulsification and demulsification related to crude oil production. Colloids Surf. 1985, 15, 175–189. (13) Czarnecki, J. Stabilization of water in crude oil emulsions. Part 2. Energy Fuels 2009, 23, 1253–1257. (14) Menon, V. B.; Wasan, D. T. A review of the factors affecting the stability of solids-stabilized emulsions. Sep. Sci. Technol. 1988, 23, 2131– 2142. (15) 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. (16) Yan, N.; Gray, M. R.; Masliyah, J. H. On water-in-oil emulsions stabilized by fine solids. Colloids Surf., A 2001, 193, 97–107. (17) 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. (18) Sztukowski, D. M.; Yarranton, H. W. Oilfield solids and waterin-oil emulsion stability. J. Colloid Interface Sci. 2005, 285, 821–833. (19) Poindexter, M. K.; Marsh, S. C. Inorganic solid content governs water-in-crude oil emulsion stability predictions. Energy Fuels 2009, 23, 1258–1268. (20) Fjar, E.; Holt, R. M.; Horsrud, P.; Raaen, A. M.; Risnes, R. Solids production. In Petroleum Related Rock Mechanics, 2nd ed.; Elsevier: Amsterdam, The Netherlands, 2008; Chapter 10, pp 341-368. (21) Jordan, M. M.; Johnston, C. J.; Robb, M. Evaluation methods for suspended solids and produced water as an aid in determining effectiveness of scale control both downhole and topside. SPE Prod. Oper. 2006, 21, 7–18. (22) Gafonova, O. V.; Yarranton, H. W. The stabilization of waterin-hydrocarbon emulsions by asphaltenes and resins. J. Colloid Interface Sci. 2001, 241, 469–478. (23) Lissant, K. J. Additional methods and areas in demulsification. In Demulsification Industrial Applications; Marcel Dekker: New York, 1983; Chapter 6, p 143.
(24) Cloud, R. W.; Marsh, S. C.; Ramsey, B. L.; Pultz, R. A.; Poindexter, M. K. Salt spheres—Inorganic structures isolated from petroleum-based emulsions. Energy Fuels 2007, 21, 1350–1357. (25) 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. (26) Hyne, N. J. Dictionary of Petroleum Exploration, Drilling and Production; PennWell: Tulsa, OK, 1991. (27) Manning, F. S.; Thompson, R. E. Dehydration of Crude Oil. In Oilfield Processing; PennWell: Tulsa, OK, 1995; Vol. 2: Crude Oil, Chapter 7, pp 113-143.
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Stability of Salt Spheres. The existence and stability of salt structures illustrate that they are able to survive two emulsion destabilizing environments as posed by the ASTM D4807-88 procedure, namely, a high concentration of aromatic solvent (toluene) and a reasonably high temperature (90 °C). Several groups have shown via model studies that water-in-oil emulsions made with a high toluene concentration are unstable.22,28,29 Higher temperatures are also known to aid emulsion destabilization, and with the exception of very heavy crude oils, the ASTM test temperature is well above or at the operating conditions of many oilfield separators.27 A third factor should also be mentioned regarding the stability exhibited by salt spheres and that concerns impact
resistance. Isolation by filtration involves forces that do not crush at least a portion of the tiny scaffolds. The fate of some scaffolds might not survive the filtration procedure; e.g., see the background in several of the backscatter electron images (BEIs) in the previous study.24 However, as also seen in those BEIs, some of the structures do indeed endure the isolation procedure. The apparent sturdiness of salt spheres may provide an indication of the stability that must be overcome to resolve some emulsions. With the addition of the more informative DCM technique, one of the most complete examples of a salt sphere, that from a West Coast emulsion, was revisited for further characterization.24 The previously identified sample and structure of interest is shown in Figure 1. In the BEI showing three discrete spheres (Figure 1a), the eye is initially drawn to the larger, more prominent cubes (e.g., point A highlighted in Figure 1b). The energy-dispersive spectrum of the large cubes was found to be sodium chloride (Figure 2a). Further examination of the overall sphere reveals an outer gossamerlike film covering, if not bridging, many of the sodium chloride cubes. In the previous study, analysis by EDS could not totally single out or resolve just the bridging material (e.g., point B highlighted in Figure 1b) from the sodium chloride crystals. Nonetheless, the spectrum of the bridging material, shown in Figure 2b, reveals a higher concentration of both calcium and sulfur than seen in Figure 2a, indicating that species containing these two elements partly comprise the outer film. Silicon also appears in this spectrum, an element that will be discussed in the next section. When the sample filter paper containing the previously analyzed West Coast salt spheres was re-examined using DCM, it was discovered that all of the salt spheres had metamorphosed into featureless structures as represented in Figure 3. From the BEI in Figure 3a, a faint outline around the salt cube is visible. With the aid of nine DCMs in Figure 3b, the elemental composition of the once existent bridging film was examined and defined. The gossamery film appears to consist of sulfur (rose), calcium (orange), barium (magenta), oxygen (yellow), and possibly silicon (pale green), where more intense coloring indicates higher concentrations of the respective elements. Visually comparing these maps further suggests that barium, sulfur, and oxygen display a direct association and indicate the presence of barite salt, a common oilfield scale.30,31 Calcium is more concentrated just above the sodium chloride cube but is within the faint outline for the most part. Because of both the graphite methodology used in sample preparation and the composition of the filter media, carbon content cannot be readily quantified. With this in mind, the calcium could be in the form of calcium carbonate. Barium was not labeled in the EDS spectral profile of Figure 2b, although it was likely present at a trace level (ca. 4.5 keV). However, with the DCM technique shown in Figure 3b, improved data refinement is provided and a clearer picture of elemental associations is displayed. This is certainly true for the current state of this sample after hydration and redeposition of the solids. From this process, it appears that most of the lower Ksp solids have coalesced
(28) 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. (29) Kumar, K.; Nikolov, A. D.; Wasan, D. T. Mechanisms of stabilization of water-in-crude oil emulsions. Ind. Eng. Chem. Res. 2001, 40, 3009–3014.
(30) Patton, C. C.; Foster, A. Water formed scale. In Applied Water Technology, 3rd ed.; Foster, A., Ed.; John M. Campbell and Company: Tulsa, OK, 2007; Chapter 3, pp 57-69. (31) Cowan, J. C.; Weintritt, D. J. An overview of the scale deposition problem. In Water-Formed Scale Deposits; Gulf Publishing: Houston, TX, 1976; Chapter 1, pp 19-27.
system. Later analyses used a Hitachi S-3400N SEM while still using the Vantage system. Current EDS system upgrades, including DCM, use a Thermo Scientific Sigma Six 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 optimize both elemental statistics and DCM data collection. DCM uses the basic method of EDS and enhances it by providing a defined lateral distribution of the elemental content within the sample. With DCM, both elemental and image data are collected and digitally stored from each pixel location. Thus, a direct method to laterally define specific compositional and morphological information on a pixelby-pixel basis can be generated. Sample geometry is critical to obtain the best analytical results. X-rays were collected only from locations for a sample where direct “line-of-sight” to the X-ray detector could be maintained. Because the detector was offset within the system at a nominal 30° angle and at a specific working distance height to the sample plane, certain sample geometries resulted in either reduced and/or lost information. Because of the rounded, spherical, and uneven shapes characteristic of these samples, sites for all EDS analyses were carefully selected to minimize the negative effects from poor sample/detector geometry. For consistency between samples, a single selected DCM set of nine elements, displayed as a 3 3 matrix, was chosen. Many more elements were examined than reported in the figures. Within this output restriction, the nine elements of highest interest were selected. For all samples, six to eight elements provided the key lateral distribution data. Thus, nothing critical was excluded, but some elements that were detected at some level were not included in the output. The combined technique of SEM/EDS with DCM25 allows for a simple and direct way of providing both physical characterization and direct compositional measurement of discrete sample features. Key multi-element and morphology relationships and associations are easily determined. As an added feature, spectral data can be easily generated and quantified by selecting single to multiple pixel selections. As a result, this technique can best define the formation of these unique features that were isolated from crude oil emulsions.
Results and Discussion
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Figure 2. (a) EDS of crystal A shown in Figure 1b. The residual carbon and oxygen peaks are likely from the background filter paper. (b) EDS of bridging fines from area B in Figure 1b. Figure 1. (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 A is sodium chloride, while film B contains calcium and sulfur.24
Salt Spheres from the Interface of an Oil-Water Separator. Since the first report on salt spheres, more oilfield samples have been examined using the ASTM D4807-88 procedure. Many of the oil samples, commonly known as dry oils or sales oils, were taken from the LACT unit in the oilfield.26 The amount of inorganic solid content and residual water content as determined by Karl Fischer titration for a number of samples is provided in Table 1. Also included in Table 1 are two samples taken from the interface pad of a primary oil-water separator. In both instances, the producer only sent unresolved emulsion from the interface for analysis and not the associated water samples. The solids level for both samples originating from a separator is noticeably greater than that observed for any of the LACT samples. These results illustrate that the oil-water interface in oilfield separators can contain an extremely high level of inorganic solids. The results further suggest that sales oils taken from production units are not representative and should not be representative of the interfacial composition of the separator. Using sales oil samples, which are often chemically treated, for emulsion studies can present a very different picture of factors contributing to emulsion stability because the most interfacially active constituents (organic and inorganic) have partly been removed and concentrated
together, which would further enhance a signal response for each. It seems as if the sodium chloride portion of the salt sphere had gradually agglomerated into a single bulk mass, whereas the outer film, almost falling in place, maintained its integrity to some degree. While the original specimen was altered after prolonged exposure to moisture from long-term shelf storage (over 3 years), these results suggest that specific inorganic salts (i.e., scales) may form a tenacious film such that the resulting network gives rise to extremely stable water-in-crude oil emulsions. As discussed, the stability of such structures is able to withstand filtrations involving hot toluene. The other salt sphere specimens identified in the first report shared the same outcome after prolonged exposure to moisture. Following the filtration step, samples are now always stored in a desiccator and shipped between laboratories in the presence of a desiccant. Since this precautionary procedure was adopted, no metamorphosized structures have been detected. 2379
Energy Fuels 2010, 24, 2376–2382
: DOI:10.1021/ef901063e
Cloud et al. Table 1. Inorganic Solid Content from Various Oilfields source
sample point
API gravity
solids (PTB)a
water content (%)b
Alberta Alberta Alberta Alberta Alberta Alberta Alberta North Dakota North Sea Oman Texas Texas Texas Gulf of Mexico North Africa
LACT LACT LACT LACT LACT LACT LACT LACT LACT LACT LACT LACT LACT separator separator
17.8 12.1 20.7 13.0 18.0 15.1 8.3 31.1 19.8 22.5 30.0 30.6 36.8 33.0 26.0
102 191 270 117 187 278 130 54 355 49 404 865 88 7990 10100
0.30 0.87 0.20 0.50 0.63 0.26 0.11 0.06 0.36 0.75 0.78 0.27 0.26 29.90 46.10
a PTB = pounds per thousand barrels. b Determined by Karl Fischer titration.
chloride scaffold in Figure 4a is noticeably thick and the structure seemingly robust, there is a gapping hole in the sphere. This opening, much like the less prominent gaps for the two smaller spheres in Figure 1a, indicate that the forces incurred during the filtration process may well have caused this irregularity. In the first salt sphere report,24 the less soluble inorganic salts were speculated as acting as the nexus for the larger, more prominent sodium chloride entities. While this may be the case, it is probably more important to recognize that less soluble salts, such as barium sulfate and possibly calcium carbonate (as discussed in Figures 1 and 3b), have very low solubility-product constants (Ksp) and appeared on the outer surface of the salt scaffolds as a type of coating.32 It is also worth noting that, even though it was not possible to confirm the presence of calcium carbonate via compositional mapping, a review of the brine chemistry indicated the presence of bicarbonate (the alkalinity of the water sample was 2800 mg/L). In addition, the calcium observed in the DCM of Figure 3b has a distinctive highly concentrated pattern that does not match sulfur, further suggesting that perhaps calcium carbonate was present on the outer surface of the salt scaffolds. For the close-up salt sphere shown in Figure 4b, high levels of strontium (blue), sulfur (rose), and oxygen (yellow) are evident from the DCMs in Figure 4c. Similar to the barium sulfate and possibly calcium carbonate coating discussed in the prior example, strontium sulfate coats much of the salt sphere from the separator. This coating and the association of the three elements (strontium, sulfur, and oxygen) are better defined in panels a-c of Figure 5. An overlay image of the three elements is also depicted in Figure 5d, where the white and lightly colored regions indicate a compositional association for the elements. As seen, a good portion of the sphere seems to be coated by strontium sulfate. Even though the compositional images are quite conclusive, it seems odd to observe only SrSO4 and no BaSO4, because these types of scales are usually found together, with BaSO4 being the dominant species as a result of the extremely low solubility of the barite salt. In fact, the barium map shown in Figure 4c does not appear to display any direct association with sulfur. Unfortunately, a lack of brine
Figure 3. (a) BEI of a re-examined West Coast salt sphere modified by exposure to moisture. Several arrows highlight the outer rim of the film. (b) DCM for nine elements. The bulk mass is composed of sodium (pink) and chloride (bright green), while the once existent bridging film, defined by a now faint outline around the salt cube, is composed of sulfur (rose), calcium (orange, with a noticeable concentration just above and to the left of the salt cube), barium (magenta), oxygen (yellow), and possibly silicon (pale green).
at the oil-water interface in the separator. At the same time, samples taken at the interface of a field separator likely represent an upper limit in inorganic solid level encountered during the processing of oil-water mixtures. While working with incoming emulsions from the wellhead is often the starting point for solving many oil-water separation issues, the interface from oil-water separators can provide additional insight regarding what entities might be contributing to emulsion stability. The sample from the interface of a North African separator was found to contain numerous salt spheres following the ASTM procedure. Figure 4 represents one of the spheres. DCMs of the salt sphere from the separator interface contained large and well-defined sodium chloride crystals, as shown by the intensely colored pink (sodium) and bright green (chloride) maps in Figure 4c. While the sodium
(32) For the solubility-product constants of common salts, see Faure, G. Salts and their ions. In Principles and Applications of Geochemistry, 2nd ed.; Prentice Hall: Upper Saddle River, NJ, 1998; Table 10.1.
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Figure 4. (a) BEI of the salt sphere isolated from the interface of an oil-water separator (magnification of 500). (b) Close-up view of the same salt sphere (1200). (c) DCM set for nine elements. Color codes follow the previous example in Figure 3b.
chemistry details does not allow for a further understanding of this phenomenon. There have been reports, however, where strontium sulfate was found to be the main scale, and that may be the case here.33,34 In comparison to the highly insoluble salts, sodium chloride on the other hand has an extremely high solubility-product
Figure 5. Better defined DCMs from Figure 4 are provided for (a) strontium, (b) sulfur, and (c) oxygen. Notice the areas common to all three elements, indicating the likely existence of strontium sulfate. Image d is a multi-element overlay, where lighter color appearances indicate a compositional association for all three elements: strontium, sulfur, and oxygen. Magnification for all four maps is the same as Figure 4b (1200).
(33) Essel, A. J.; Carlberg, B. L. Strontium sulfate scale control by inhibitor squeeze treatment in the Fateh field. J. Pet. Technol. 1982, 34, 1302–1306. (34) Jacques, D. F.; Bourland, B. I. A Study of solubility of strontium sulfate. SPE J. 1983, 23, 292–300.
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constant (Ksp of 36) and occupies the inner part of the spheres. This ordering or layering effect of low Ksp salts on the outside with an inner sodium chloride layer was seen repeatedly for the other spheres isolated from the North African separator. Thus, the boundary defined by the less soluble inorganic species may well outline the once extant oil-water interface, while the inner sodium chloride crystals lie well within the once existent water droplets. It is conceivable that materials with low Ksp values existed as solids during oilfield production and emulsion formation, while timing for the formation of sodium chloride crystals is much less certain. Returning to the DCMs of Figure 4c, barium, calcium, and silicon all appear as a fine dust throughout much of the sphere and adjacent to it. All three elements periodically exhibit areas of higher concentration. These elements in selected states (e.g., barium carbonate, calcium carbonate, and silicates) may round out much of the outer coating on the salt spheres from the separator. Iron (see the lower left corner of Figure 4c) presents another interesting observation because it appears to be in higher concentration in the backdrop of the image and much less concentrated on the sphere itself. This observation raises the question whether iron species may have once occupied an extreme outer layer (i.e., been more associated in the oil phase with polar organic species) and were washed off the sphere during the filtration procedure and subsequent toluene rinsing. Iron, especially ferric iron, is reported to interact with asphaltenes and influence their polarity and solubility properties.35 It is thus postulated that iron species might have once occupied or resided near the oil-water interface, where interfacially active asphaltenes and possibly resins likely once resided but were subsequently washed off the spheres during the toluene rinsing step of the ASTM D4807-88 procedure. The use of DCM revealed numerous inorganic species participating in the makeup of salt spheres. In the initial report, salt spheres seemed simpler in their chemical composition because the exact location, concentration, and compositional association of elements was more limited using solely SEM and EDS. DCM has helped further define the complex yet ordered nature of salt spheres.
Conclusions Minimizing the buildup of unresolved emulsion at the oilwater interface is a critical aspect of demulsification. Identifying constituents that accumulate at the oil-water interface is one way to better define and understand the problem. This study expands on a method of filtration and SEM/EDS analysis used to isolate and identify the inorganic constituents that may well contribute to emulsion stabilization. The results presented in this study do not imply that salt spheres are the sole species responsible for emulsion stability. Many stable emulsions have been found to contain no salt spheres. The spheres might have once existed but did not survive the filtration process, or they simply were not present. Most likely, because of the complex nature of crude oil emulsions, stabilization as a result of salt spheres is but one example of a host of possible emulsion stability mechanisms. Identification of salt spheres provides another view of what constituents and their organization may exist at the oil-water interface and contribute to emulsion stabilization. While salt spheres are at least somewhat stable to highly aromatic solvent, high solution temperatures, and the filtration process of the ASTM D4807-88 procedure, they are not stable to moisture over prolonged periods of time once they are isolated from their native emulsion. When inorganic species are isolated from water-in-oil emulsions with the intent of examining their structure, care should be exercised to ensure that exposure to moisture is minimized. In comparison to sales oils, the solid content for two oil-water separators was shown to be around two orders of magnitude higher. These levels indicate that the concentration of inorganic solids at the interface may well play a significant role in stabilizing oil-water emulsions. DCM revealed that less soluble inorganic salts, such as strontium sulfate, itself a less commonly encountered oilfield scale, occupied the outer layer of the salt sphere, while sodium chloride resided on the inner face of the sphere. This observation further suggests that the thin film of less soluble inorganic salts and other highly insoluble material (e.g., silicates) may demarcate where the oil-water interface once existed in oilfield water-in-crude oil emulsions. Thus, scale and demulsification problems, while periodically addressed separately, may well be highly intertwined.
(35) Nalwaya, V.; Tangtayakom, V.; Piumsomboon, P.; Fogler, S. Studies on asphaltenes through analysis of polar fractions. Ind. Eng. Chem. Res. 1999, 38, 964–972.
Acknowledgment. We are grateful to the Nalco Company for permission to publish this work.
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