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Solid Content Dominates Emulsion Stability Predictions† Michael K. Poindexter,* Shaokun Chuai,‡ Robert A. Marble, and Samuel C. Marsh Nalco Energy Services, 7705 Highway 90-A, Sugar Land, Texas 77478 Received August 12, 2004. Revised Manuscript Received January 14, 2005
A project was devised to determine what constituents in water-in-crude oil emulsions control emulsion stability. The work entailed gathering two groups of data. The first group required extensive characterization of a number of different emulsions. The emulsions were composed of crude oil having a wide range of chemical properties (e.g., API gravities ranging from 10 to 31° and asphaltene content from 0 to 17 wt %). The second group of data centered on using an extensive group of demulsifiers. By using a host of demulsifiers in a standardized bottle test, the stability of the emulsions was probed. Issues addressed in this study include which crude oil components or properties (specifically asphaltenes, resins, naphthenic acids, solids, aromaticity, metal content, viscosity, and API gravity) inhibit water drop, create off-spec oil, and generate poor oil-water interfaces. When comparing numerous crude oil components and properties simultaneously, solid content showed an overwhelming ability to describe the stability of waterin-crude oil emulsions. These studies suggest that without the inclusion of solids, emulsion stability as observed in the field cannot be adequately described. Furthermore, based on filtration through 0.45 µm pore size filter paper, all crude oils studied to date contain solids. Extrapolation of this finding indicates that there are no solid-free crude oils.
Introduction Water-in-crude oil emulsions are comprised of numerous constituents. Recent mass spectrometric studies have begun to quantify the chemical complexity of the hydrocarbon portion of such fluids.1,2 When petroleum is coupled with the water phase, which has its own unique properties, the factors and forces governing emulsion stability would seem to be staggering. In addition to accounting for the chemistry at play, process conditions such as temperature, shear forces across chokes, and pipeline dynamics likewise play a role in determining emulsion stability. As complex as such fluids and their process conditions are, a tremendous amount of understanding has been achieved regarding the quantification of factors that govern emulsion stability. As a starting point in many crude oil characterizations, samples are often divided into four main fractionsssaturates, aromatics, resins, and asphaltenes (SARA). Two of the more recent advances in SARA characterization involve high-performance liquid chromatography (HPLC)3 and infrared and near-infrared spectroscopy.4 Clearly, asphaltene content and asphaltene solubility play a central role in † Presented at the 5th International Conference on Petroleum Phase Behavior and Fouling. * Author to whom correspondence should be addressed. Telephone: 281-263-7505. Fax: 281-263-7221. E-mail:
[email protected]. ‡ Present address: Memorial Sloan-Kettering Cancer Center, New York, NY 10021. (1) Marshall, A. G.; Rodgers, R. P. Petroleomics: The Next Grand Challenge for Chemical Analysis. Acc. Chem. Res. 2004, 37, 53-59. (2) Porter, D. J.; Mayer, P. M.; Fingas, M. Analysis of Petroleum Resins Using Electrospray Ionization Tandem Mass Spectrometry. Energy Fuels 2004, 18, 987-994. (3) Fan, T.; Buckley, J. S. Rapid and Accurate SARA Analysis of Medium Gravity Crude Oils. Energy Fuels 2002, 16, 1571-1575.
governing emulsion stability.5 Asphaltene solubility is linked to resin content5-8 as well as the overall aromaticity5,7,8 of the maltenes. Other cited crude oil components having an influence on emulsion stability include naphthenic acids,9 solids,8,10-15 and waxes.13,16 (4) Aske, N.; Kallevik, H.; Sjo¨blom, J. Determination of Saturate, Aromatic, Resin, and Asphaltenic (SARA) Components in Crude Oils by Means of Infrared and Near-Infrared Spectroscopy. Energy Fuels 2001, 15, 1304-1312. (5) 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. (6) 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. (7) Aske, N.; Orr, R.; Sjo¨blom, J. Dilatational Elasticity Moduli of Water-Crude Oil Interfaces Using the Oscillating Pendant Drop. J. Dispersion Sci. Technol. 2002, 23, 809-825. (8) Gafonova, O. V.; Yarranton, H. W. The Stabilization of Waterin-Hydrocarbon Emulsions by Asphaltenes and Resins. J. Colloid Interface Sci. 2001, 241, 469-478. (9) Goldszal, A.; Bourrel, M.; Hurtevent, C.; Volle, J.-L. Stability of Water in Acidic Crude Oil Emulsions. In Spring AIChE Meeting, New Orleans, March 11-14, 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 109; Marcel Dekker: New York, 2003; Chapter 3, pp 61-90. (11) Mikula, R. Emulsion Characterization. In Emulsionss Fundamentals and Applications in the Petroleum Industry; Schramm, L. L. Ed.; American Chemical Society: Washington, DC, 1992; Chapter 3, pp 79-129. (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. Colloids Surf. 1985, 15, 175-189. (14) 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. (15) Yan, N.; Gray, M. R.; Masliyah, J. H. On Water-in-Oil Emulsions Stabilized by Find Solids. Colloids Surf., A 2001, 193, 97-107.
10.1021/ef049797w CCC: $30.25 © 2005 American Chemical Society Published on Web 04/02/2005
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Energy & Fuels, Vol. 19, No. 4, 2005 1347 Table 1. Summary of Crude Oil Properties
crude oil
designation
API gravity
viscosity, cP
% resins
% asphaltenes
naphthenic acidsa
solidsb
Fe, ppm
Ni, ppm
V, ppm
aromatic H/Cc
Alberta Alberta Alberta California (offshore) Gulf of Mexico (shelf) Gulf of Mexico (deepwater) California Midway-Sunset California Midway-Sunset Eastern Montana Eastern Montana Western Venezuela Western Wyoming
AB-1 AB-2 AB-3 COf GM-1 GM-2 MS-1 MS-2 MT-1 MT-2 WV WY
10.0 13.5 12.3 19.7 28.7 18.3 10.5 11.1 30.6 27.8 11.2 19.5
53 3000 6 200 7 200 258 17 220 166 500 65 400 17 76 59 000 165
14.6 13.7 13.6 16.7 2.6 11.7 24.1 25.0 4.3 4.2 17.1 9.9
14.3 13.1 12.3 11.4 0 3.4 7.9 8.3 8.1 11.6 16.8 7.6
0.4 1.0 0.6 0.5 0.3 1.2 1.8 2.6 0.2 0.1 0.5 0.2
401 661 985 257 176 205 156 634 664 1,090 297 157
6.8 3.6 14 120 13 50 32 19 5.0 13 11.5 2.7
64 66 62 69 0.9 17 67 53 2.9 4.6 95 34
160 150 150 175 0.7 51 75 62 2.7 1.0 1,067 130
1.54 1.52 1.52 1.71 1.54 1.52 1.51 1.56 1.46 1.46 1.56 1.54
a
Reported as mg of KOH/g of crude. b Reported as pounds/1000 barrels of crude (PTB). c Atomic ratio for aromatic fraction.
Much of the progress and understanding of emulsion stabilization has resulted from laboratory studies. In such controlled environments, specific amounts of a given crude oil constituent are often added to a solvent mixture. The most common cosolvent system is heptane-toluene and generally abbreviated as heptol.5,7,8,14,17 This solvent pair permits fine adjustment of the aromatic-aliphatic balance, which collectively serves to represent the lighter fractions of crude oil, specifically the saturate and aromatic cuts. Creating emulsions using this methodology permits exacting control over the design of emulsion composition. A second way to study crude oil emulsions is to use fluids from the field. Transporting field emulsions to the laboratory for study, however, has limitations. A major issue concerns aging. Extensive work in our laboratories confirmed prior art that showed aged emulsions are generally not representative of field emulsions.18,19 Effects due to aging are expected as emulsion stability has a time-dependent nature. For example, in the oilfield, process conditions create a new oil-water interface. Once formed, the migration of surface-active species to the interface ensues to reduce the surface tension. This dynamic process has a so-called starting point and can apparently continue for long periods of time.19-21 Thus, studying aged emulsions may not provide results representative of field conditions. Laboratory conditions are generally not able to recreate the once through conditions encountered in most oilfields. Such is not the case in refinery desalters where the emulsion is created intentionally using crude oil, wash water, and mix valves. In such instances, emulsions generated in the laboratory can often simulate desalter emulsions. The fluids reported in this work (16) Zaki, N.; Schorling, P.-C.; Rahimian, I. Effect of Asphaltene and Resins on the Stability of Water-in Waxy Oil Emulsions. Pet. Sci. Technol. 2000, 18, 945-963. (17) Kim, Y. H.; Wasan, D. T. Effect of Demulsifier Partitioning on the Destabilization of Water-in-Oil Emulsions. Ind. Eng. Chem. Res. 1996, 35, 1141-1149. (18) 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, 2000; Chapter 2, pp 51-77. (19) 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. (20) Jeribi, M.; Almir-Assad, B.; Langevin, D.; He´naut, I.; Argillier, J. F. Adsorption Kinetics of Asphaltenes at Liquid Interfaces. J. Colloid Interface Sci. 2002, 256, 268-272. (21) 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.
focused solely on oilfield emulsions, not refinery emulsions, and thus necessitated that field laboratories be utilized using fresh emulsions taken at or near the wellhead. The strategy for examining which crude oil constituents govern emulsion stability entailed several steps. The first step involved treating a variety of different water-in-crude oil emulsions with a select group of chemical demulsifiers in the bottle test.22 Bottle test results that capture various aspects of oil-water resolution would serve as the dependent variables for gauging emulsion stability. The second step required shipping the field emulsions to a central laboratory where the emulsion was once again broken with the same group of demulsifiers. Resolved crude oil was removed and analyzed using fairly traditional methods, namely, separation into the SARA components. Additional properties were gathered to provide a broad description of the crude oil properties. These values would in turn serve as the independent variables for determining emulsion stability. Analysis of the data involved determining which input or independent crude oil variables had the strongest influence on the output or dependent emulsion stability variables. By using partition trees, a statistical technique useful for collectively examining the influence of multiple inputs against a given output parameter, additional insight was gained. Experimental Section Materials. All chemical demulsifiers were from Nalco Energy Services. Five percent dilutions by weight of chemical were made using heavy aromatic naphtha as the solvent. Demulsifier dosages for all tests were held at 50 ppm (by vol). Stoddard solvent or Varsol (CAS Registry No. 8052-41-3), sometimes referred to as mineral spirits, is hydrocarbon-based and was used as the diluent in determining the water content in the oil samples. This nonvolatile, odorless diluent in effect reduces the viscosity of the emulsion and greatly facilitates the quantification of unresolved emulsion and water. Crude Oil Emulsions. Crude oil emulsions obtained in the field were free of demulsifier. Twelve emulsions were used in the study, and Table 1 provides a basic chemical description of each oil along with their abbreviations. To conform with production conditions, the two Canadian emulsions (AB-2 and AB-3) were diluted with field condensate (15% by vol) after collection from the wellhead. The addition of condensate was done to ensure that the bottle test fluids were as close as (22) Poindexter, M. K.; Lindemuth, P. M. Applied Statistics: Crude Oil Emulsions and Demulsifiers. J. Dispersion Sci. Technol. 2004, 25, 311-320.
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possible to what the field separators process. Any free water (i.e., water that separates rapidly after sample collection in the field) was drained and discarded before starting each test. Water Content Determination. Before conducting a bottle test, a procedure commonly called a “grindout” was performed to determine the water content in the emulsion. To a graduated API centrifuge tube (12.5 mL) was added one part by volume Varsol as diluent and then one part by volume emulsion. The contents were shaken by hand to ensure that the emulsion was well-dispersed. The contents were centrifuged for 5 min, and then the percent water and remaining emulsion (referred to as basic sediment, BS23) was recorded. It is standard procedure to double all centrifuge tube readings to account for the Varsol dilution. The term basic sediment is used to describe either solid accumulation at the bottom of the tube or the emulsion (“rag”) layer residing between the oil and the water layers. Finally, a heavy dose of a chemical known to resolve the remaining emulsion was added to the centrifuge tube. Such “slugging chemicals” are typically sulfonate-based. The tube was once again shaken and then centrifuged. As mentioned, the slugging chemical breaks the previously unresolved emulsion, and the final, total water content was recorded. This value, called the slug grindout number, is critical to determine as it provides a performance benchmark for the chemical demulsifiers. Bottle Testing and Water Drop Readings. Bottle tests were conducted in 6 oz prescription bottles. Fresh emulsion was poured to the 100 mL mark. Bottles were then heated in a water bath to a temperature that represented the field separator temperature as close as possible. Following demulsifier addition, samples were agitated and then allowed to sit. Water drop readings recorded in milliliters were taken over longer time frames for heavier crude oils and conversely over shorter times for lighter crudes. Final water drop readings will serve as one of five bottle test parameters to gauge emulsion stability. Final water drop is reported as a percentage where the last water drop recorded during a test is divided by the total water content of the starting emulsion (i.e., the slug grindout number). For a general description of field bottle testing, see Leopold24 as well as Manning and Thompson.25 Oil Dryness (Thief, t) Readings. Once the water drop readings were completed, the resolved or partially resolved oil from each bottle was analyzed for dryness. Using a pipet, a small portion of the oil (commonly called a “thief”, ca. 6 mL) was siphoned off. For withdrawing purposes, the tip of the pipet was set to 15-20 mL above the theoretical oil-water interface as determined by the slug grindout value. The thief of oil was added to a graduated API centrifuge tube containing an equal volume of Varsol, and the contents were shaken thoroughly. Following centrifugation, the percent emulsion, BS(t), was recorded. Next, slugging chemical was added to each tube to resolve any remaining emulsion. After centrifuging the contents, the final water level was recorded as the thief slug value, slug(t). Both the BS(t) and slug(t) values express the volume percentage of emulsion and water remaining in the siphoned oil sample, respectively. These two parameters describe different aspects of oil dehydration. Interface Quality (Composite, c) Readings. The last stage of bottle testing involved examining the oil-water interface for dryness and is often referred to as a composite. From each bottle, the resolved water layer was removed by siphon. The remaining contents were then well shaken. As in (23) BS stands for basic sediment, bottom sediment, or base sediment, see Hyne, J. M. Dictionary of Petroleum Exploration, Drilling, and Production: PennWell: Tulsa, 1991. (24) 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, DC, 1992; Chapter 10, pp 341-383. (25) Manning, F. S.; Thompson, R. E. Dehydration of Crude Oil. In Oilfield Processing Volume 2: Crude Oil; PennWell: Tulsa, 1995; Chapter 7, pp 113-143.
Poindexter et al. the thief procedure, a portion of the shaken composite was added to a centrifuge tube containing Varsol. Basic sediment and slug values for the composites were determined in the manner described in the oil dryness thief section and labeled as BS(c) and slug(c), respectively. Composite values complement thief measurements. For example, the closer composite and thief values are to each other, the more evenly distributed is the emulsion and water throughout the oil phase. However, if the composite values are noticeably larger than their thief counterparts, then a gradient exists where an abundance of water resides closer to the oil-water interface. Crude Oil Separation and Characterization. To collect crude oil for the SARA analyses, the top portion of resolved crude oil (i.e., ca. 15% of the total oil phase) from each bottle was removed and combined. A literature procedure was used to fractionate the crude oils into their SARA components.26 Crude oil viscosities at room temperature were obtained using a Brookfield Viscometer model LVT. Naphthenic acid determinations were accomplished by solid-phase extraction of the maltenes (defined as the n-heptane-soluble fraction) and then titrated in an isopropyl alcohol/toluene solution using potassium hydroxide. Naphthenic acid content is reported in mg of KOH/g of crude. Solid content was determined according to ASTM D4807-88, which involves a hot toluene wash (90 °C) through a nylon membrane filter with 0.45 µm pore size.27 Solid values reported are in pounds per thousand barrels (PTB).23 Metal content was determined using a Jarrell-Ash 61E inductively coupled argon plasma emission spectrometer. Elemental analyses were performed by Galbraith Laboratories in Knoxville, TN. API gravities were obtained using a Paar Density Meter DMA 48. Statistical Analysis. Linear regression analyses were performed to measure the association of each crude oil characteristic with each bottle test performance parameter. Multivariate models were generated using the partition tree technique. All statistical analyses were conducted using JMP Statistical Discovery Software Version 5.0.1 from the SAS Institute, Inc., Cary, NC.
Results and Discussion Bottle Test Protocol. Determining which crude oil constituents or properties influence emulsion stability remains a challenging endeavor. As discussed earlier, model studies afford a systematic way to add constituents such that one or more parameters (e.g., asphaltenes and/or resins) can be investigated. The approach described here does not have the opportunity to adjust the constituents in a controlled fashion. Each crude oil emulsion brings its own unique set of characteristics to the data set. For each emulsion under investigation, all crude oil elements are present simultaneously. Asphaltenes act in tandem with all the other constituents. While such a scheme may seem to obscure the role each component plays in emulsion stabilization, it does leave the crude oils intact and remarkably similar to that encountered in field systems. For example, in the field, asphaltenes always exist in the presence of resins, never alone. In essence, this approach is a different yet complementary approach to model studies. This methodology still permits the same basic questions to be addressed regarding emulsion stability. With all the constituents present and simultaneously engaged, if a given parameter (or group of parameters) (26) 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. (27) ASTM D4807-88: Standard Test Method for Sediment in Crude Oil by Membrane Filtration. 1999.
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Energy & Fuels, Vol. 19, No. 4, 2005 1349
Table 2. Chemical Demulsifier Families no. of demulsifiers 8 5 8 5 4 6
Table 3. Mean Bottle Test Parameters
chemical family resins with nonyl substituent resins with butyl substituent propylene glycol backbone triol backbone hexol backbone crosslinked resins
aptly describes emulsion stability across a variety of crude oil emulsions, then this parameter is likely very relevant. Such a parameter is acting in the presence of all other parameters not in isolation. By itself, emulsion stabilization is a somewhat loaded term. Most descriptions of emulsion stabilization are defined by parameters incorporating water drop and/ or oil dryness (i.e., thief values) at a certain oil depth. Interface resolution (sometimes referred to as composite values) is another parameter that deserves to be included in emulsion stabilization descriptions. Fortunately, all three general parameters are an aspect of bottle testing and are recorded. At a minimum, these descriptions need to be accounted for when describing emulsion stability and eventual resolution. Accounting for only one of these parameters does not necessarily lend supporting conclusions to the other parameters. For example, it was shown that water drop and oil dryness are not strongly correlated.28 An emulsion may yield very dry top oil and still show poor water drop due to ineffective coalescence. As used in the field, the bottle test generally enlists a host of chemical demulsifiers. By using a select group of demulsifiers (and the same group at the same dosage level) on each crude oil emulsion, emulsion strength can be probed, quantified, and ultimately compared. Each demulsifier acts on the emulsion in a unique manner. The bottle test results thus embody the properties and interactions of the chemical demulsifier, the emulsion under investigation, and the test conditions. Individually, demulsifiers may yield fast water drop, dry oil, and a clean oil-water interface; have each of these desired results; or have little or no impact. By examining various emulsions under the same set and concentration of demulsifier probes, emulsion classification can be organized using bottle test results (i.e., the outputs or dependent variables of the study). An emulsion exhibiting a tendency for more complete water drop yet maintaining wet, off-spec oil is probably stabilized by different constituents than an emulsion resisting complete water drop but readily yielding a top layer of very dry oil. Table 1 parameters will be used to determine which properties are most influential in governing emulsion stability. Thirty-six different demulsifiers spanning six different oxyalkylated families were used at the same dosage level (50 ppm by vol), see Table 2. Seven of the demulsifiers were run in duplicate, bringing the lines of each bottle test set to 43. The mean value of five critical bottle test parameters was used to determine emulsion strength for a given emulsion (see Table 3). The five parameters included final water drop [WD], (28) Poindexter, M. K.; Chuai, S.; Marble, R. A.; Marsh, S. C. Classifying Crude Oil Emulsions Using Chemical Demulsifiers and Statistical Analyses. Presented at the Annual Technical Conference and Exhibition, Denver, October 5-8, 2003; SPE Paper 84610.
crude oil
water drop (final)
oil dryness BS(t)
oil dryness slug(t)
composite BS(c)
composite slug(c)
AB-1 AB-2 AB-3 COf GM-1 GM-2 MS-1 MS-2 MT-1 MT-2 WV WY
59 37 23 55 68 54 53 50 54 44 68 85
8 18 28 11 2 0.3 3 10 30 40 1 1
9 22 36 11 5 6 4 11 28 32 7 4
7 30 31 12 2 1 3 12 28 36 1 2
14 37 45 18 8 10 15 27 28 31 7 7
Table 4. R2 Values for Select Crude Oil Properties versus Bottle Test Parameters bottle test parameter water drop (final) BS (thief) slug (thief) BS (composite) slug (composite)
asphaltenes, %
solids, PTB
R/A
0.07 0.09 0.12 0.11 0.11
0.55 0.85 0.88 0.85 0.78
0 0.38 0.36 0.34 0.10
basic sediment in the thief [BS(t)], thief slug [slug(t)], basic sediment in the composite (i.e., interface) [BS(c)], and composite slug [slug(c)]. Water drop values were calculated to account for the maximum amount of water present. In essence, percent water drop based on the slug grindout value was used. Consequently, the overall ability of the demulsifier ensemble to resolve a given emulsion was defined by the five output mean parameters. The choice of demulsifiers used is somewhat arbitrary. Almost any suite of chemicals known to have interfacial activity could serve the purpose described in this methodology. Influential Crude Oil Components. The most basic method to determine whether a direct relationship exists between two variables is linear regression. For this study, Table 1 crude oil parameters served as the input variables while Table 3 bottle test results served as the output variables. Table 4 lists the R2 values of the linear regression models on the two input variables (asphaltenes and solids) most able to predict bottle test performance, which in turn serves as the gauge for describing emulsion stability. Also included in Table 4 is the often cited resin-to-asphaltene ratio (R/A). Compared to asphaltene content, this hybrid parameter scored better in three of the four dryness parameters but worse in water drop. The Gulf of Mexico emulsion GM-1 was excluded from the R/A calculations as it was void of asphaltenes. Solid content far surpassed all parameters in predicting emulsion stability. Figure 1 illustrates these trends for one of the oil dryness parameters, slug(t). It might be tempting to describe the asphaltene influence on oil dryness with a nonlinear (such as polynomial or exponential) regression model (see Figure 1A). At the lower asphaltene concentrations, the oil dryness values are low and fairly flat. Around 10% asphaltenes, some of the oil dryness data rises steeply. However, the emulsion from Western Venezuela (WV) would seem to have ample asphaltenes to stabilize an emulsion (16.8% by wt, the most of any crude in Table 1). Similar reasoning holds for the Canadian emulsion AB-1 that has 14.3% asphaltenes, a substantial amount.
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Figure 2. Contour plot of asphaltenes and solids vs the oil dryness parameter, slug(t).
Figure 1. (A-C) Plots of asphaltenes, solids, and R/A vs the oil dryness parameter, slug(t), respectively. Each point represents a crude oil on the plots.
While specific asphaltene characteristics as opposed to content alone may play a critical role in the ranking of emulsion stability data, other non-asphaltenic factors may be more influential in governing emulsion stability. For example, the solid content parameter by itself provides a much better description of emulsion stability. From this study, solid content serves as the best single predictor. Contour plots can be used as a way to examine the combined effect of asphaltene and solid content on emulsion stability. Using the oil dryness parameter slug(t) again as an example, Figure 2 shows that the apex of solid content is detrimental to achieving acceptable oil dryness values. The same does not hold true for the vertex of asphaltene content where more acceptable levels of oil dehydration reside. Partition Tree Analyses. Partition tree models were generated to examine the collective influences of multiple crude oil components on emulsion strength.
This statistical technique begins with a given dependent variable. In this study, these are the bottle test parameters listed in Table 3. The first step in running a partition tree is to find an input variable (i.e., from the list of crude oil properties listed in Table 1) that optimally splits the dependent variable into two groups. Groups resulting from the first split can be split again. As before, each split is determined by finding the input variable that best divides the remaining data group under consideration for split. As such, later splits can use input variables other than the variable used to perform the first split. Each parameter from Table 3 was examined using all the properties listed in Table 1. Figure 3 is representative of the technique and shows the first three splits for water drop. In this case, solid content served as the first input split variable with the “fulcrum” set at 634 PTB. For the second level of differentiation, asphaltene and naphthenic acid content were found to split data best on the left- and right-hand portions of the figure, respectively. Figure 3 shows that lower levels of solid and naphthenic acid content are advantageous for water drop while higher solid and asphaltene levels are detrimental. Table 5 summarizes the partition tree results for all five variablesswater drop, oil dryness (BS and slug), and interface quality (BS and slug). Additional splits are entirely possible; however, the gain in information is minor as strong correlations (R2 values on the order of 0.9) were obtained at the current level of analysis. The gain in R2 needs to be judged after each split is performed. A small gain in R2 indicates that the most recent split was not informative. Such splits should not be used. The directionality of the splits listed in Table 5 agreed with expectations. Emulsion stability increased when solid, asphaltene, naphthenic acid, and iron levels were high. High iron levels have been implicated in determining asphaltene polarity and appear to promote the aggregation of asphaltenes.29 For the secondary splits used to describe the BS(c) parameter, high H/C values for the aromatic fraction and low resin content inhibited oil dehydration. Both results indicate that the lack of aromaticity is unfavorable. (29) Nalwaya, V.; Tangtayakom, V.; Piumsomboon, P.; Fogler, S. Studies on Asphaltenes through Analysis of Polar Fractions. Ind. Eng. Chem. Res. 1999, 38, 964-972.
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Figure 3. Partition tree of water drop using the 10 input variables listed in Table 1. Table 5. Summary of Partition Tree Results bottle test parameter
R2
1st split variable
2nd split variables (left/right)
water drop (final) BS (thief) slug (thief) BS (composite) slug (composite)
0.85 0.94 0.97 0.99 0.94
solids solids solids solids solids
asphaltenes/naphthenic acids solids/solids asphaltenes/solids H/C for aromatic fraction/resins iron/asphaltenes
In each case, solid content was used to make the first and, therefore, most influential split. Asphaltene content, a commonly cited variable in governing emulsion stability, was used in three of the second level splits and appears to be most influential after solid content. However, asphaltene content did not govern both second level splits for any emulsion stability parameter. For the BS(t) parameter, solid content was used in all three splits. These field-based studies and conclusions shed light on and support the model studies by Gafonova and Yarranton8 as well as Sztukowski and Yarranton.14 Their results suggested that the combination of asphaltenes and solids caused the most stable emulsions. They further suggested that future research target the role solids play in stabilizing emulsions. Other statistical techniques were also evaluated in the search to uncover relationships between data in Tables 1 and 3. With each technique, solid content was found to be the most critical variable in describing emulsion stability. For example, when using stepwise multiple regression where the input variables were entered in a forward direction, solid content was the first parameter to enter each model. Furthermore, when using up to three input variables to build each model, solid content was the only parameter used in all five bottle test descriptions. Solid Properties. As used in this study, solid content is defined by ASTM D4807-88. The procedure involves a hot toluene wash of the collected solids using 0.45 µm pore size filter paper. This workup will certainly remove most any organic material (including resins, asphaltenes, and naphthenic acids) associated with the solids. Defining the precise interactions between solids and the rest of the crude oil components is clearly a separate
research topic. As shown by Kotlyar et al.30 for oil sand bitumen, solids are strongly associated with asphaltenes. This interaction was attributed to the similarity between the organic coating on the solids and the asphaltenes. Results from this investigation indicate that solid content alone serves as an excellent gauge for determining emulsion stability. It was not necessary to incorporate additional solid characterization data such as particle size distribution and elemental composition. While pioneering work by Pickering31 showed that solids alone can stabilize emulsions, this study does not imply that solids alone are responsible for emulsion stabilization. There is overwhelming data that shows other factors are critical. However, in searching for a variable most apt to predict emulsion stability, solid content appears to be the key. In addition to these results, we have yet to find a crude oil absent of solids when reviewing past analytical records using the ASTM D4807-88 procedure. This comment is made in light of years of analyses from crude oils spanning the world. If solids are truly always present, then solids may play the most influential role in predicting emulsion stability. Starting with Pfeiffer and Saal,32 there has been widespread discussion concerning the establishment of methods to standardize the isolation and characterization of asphaltenes. If widely accepted asphaltene procedures come to fruition, then hopefully similar measures can be established for other crude oil components (namely, the saturates, aromatics, resins, and even solids). The consistent quantification of solid content could assist in developing a better understanding of the factors controlling oilfield emulsion stability. Conclusions A wide range of water-in-oil emulsions was investigated via field bottle testing followed by crude oil (30) 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. (31) Pickering, S. U. Emulsions. J. Chem. Soc. 1907, 91, 2001-2021. (32) Pfeiffer. J. P.; Saal, R. N. J. Asphaltic Bitumen as Colloid System. J. Phys. Chem. 1940, 44, 139-149.
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fractionation and analysis. By using an ensemble of demulsifiers, emulsion strength was probed, quantified, and compared. A handful of crude oil properties was used to determine if one or more of the attributes could describe emulsion stability. Emulsion stability was quantified using five common bottle test parameters that describe various aspects of oil-water resolution. Solid content had by far the greatest ability to predict emulsion strength as shown by several different statistical techniques. In each description of emulsion stability, higher solid content had a detrimental effect. The results indicate that solids play an integral role in governing emulsion stability if not the lead role. Analysis via partition trees is a highly visual technique and permits construction of extremely informative models using more than one input variable. This
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statistical technique also permits usage of input variables over the most pertinent information domain rather than trying to force all input variables to be regressed against the full range of the output variable. Furthermore, by virtue of splits or partitions, the technique can better account for nonlinear associations that are complementary to linear regression analysis. Acknowledgment. We are grateful to Nalco Energy Services for permission to publish this work. We also thank Becky Ramsey, Bob Pultz, and Terry Street for determination of naphthenic acid as well as metal and solid contents. EF049797W
