Demulsifier Effectiveness in Treating Heavy Oil Emulsion in the

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Energy & Fuels 2007, 21, 912-919

Demulsifier Effectiveness in Treating Heavy Oil Emulsion in the Presence of Fine Sands in the Production Fluids† Chandra W. Angle,* Tadeusz Dabros, and Hassan A. Hamza Natural Resources Canada, CANMET Energy Technology Centre-DeVon, #1 Oil Patch DriVe, Suite 202, DeVon, Alberta, Canada T9G 1A8 ReceiVed May 26, 2006. ReVised Manuscript ReceiVed August 28, 2006

Surface-active chemicals (e.g., demulsifiers) are frequently used to destabilize crude oil emulsion. It was observed that, in some instances, when mineral solids were present, heavy oil emulsions were difficult to treat. Using three-phase contact angle measurements and videomicroscopy, the reasons behind the ineffectiveness of some demulsifiers were determined. It was found that adsorption of the surfactant onto solids changes the wettability of the solids, and promotes adhesion of the oil droplets to the solids thus reducing the effective density difference between the oil and the water, and hindering oil-water separation.

Introduction Effluent treatment in crude oil production is essential for meeting environmental standards for discharged water. Water must also be removed from the extracted crude oil before refining and pipelining. During production, many types of emulsions are created in the same produced fluids. These emulsions may be oil-in-water (O/W), water-in-oil (W/O), or complex emulsions such as oil-in-water-in-oil (O/W/O) or water-in-oilin-water (W/O/W), depending on the surfactants in the water, the oil, energy in the flow, and oil-to-water ratios.1-3 In practice, treatment protocols are often ad hoc and not designed on the basis of characterization of the actual production fluids. In many cases when a protocol is established for treating the produced fluids, it is used for all production wells until a problem arises. In heavy oil production, the efficiency of extracting clean dry oil from the produced fluids depends on the process conditions as well as the choice of chemical aids used to destabilize the emulsions. The effectiveness of the measures used to destabilize these emulsions depends on the properties of the surfactants such as the hydrophile-lyophile balance (HLB) as well on properties of the oil and water phase. Also, the presence of solids in the produced fluids often complicates treatment of the fluids.4 A significant amount of published work on demulsification of crude oil emulsions was recently reviewed,5,6 and specific † This work was presented at the 55th Canadian Chemical Engineering Conference in Toronto Oct 16-19th, 2005. * Corresponding author. E-mail: [email protected]. Fax: 1-780-9878676. Phone: 1-780-987-8621. (1) Angle, C. W.; Hamza, H. A. AIChE J. 2006, 52, 2639-2650. (2) Angle, C. W.; Hamza, H. A.; Dabros, T. AIChE J. 2006, 52, 12571266. (3) Angle, C. Stability of heavy oil emulsions in turbulent flow and different chemical environments. Ph.D. Dissertation, University of Manchester Institute of Science and Technology, 2004. (4) Angle, C. W. Can. J. Chem. Eng. 2004, 82, 722-734. (5) Angle, C. W. Chemical demulsification of stable crude oil and bitumen emulsions in petroleum recoverysa review. In Encylopedic Handbook of Emulsion Technology, 1 ed.; Sjoblom, J., Ed.; Marcel Dekker: New York, 2001; pp 541-594. (6) Sjo¨blom, J.; Johnsen, E. E.; Westvik, A.; Ese, M.; Djuve, J.; Auflem, I. H.; Kallevik, H. Demulsifiers in the oil industry. In Encyclopedic Handbook of Emulsion Technology, 1 ed.; Sjoblom, J., Ed.; Marcel Dekker: New York, 2001; pp 595-619.

cases were discussed.7-11 The majority of the studies focused on simple model systems, and fewer focused on complex field emulsions, which are often more difficult to obtain. This paper presents the diagnosis and solution of a difficult but typical emulsion treatment problem faced in heavy oil production fluids. The problem arises when new SAGD (steamassisted gravity drainage) production wells come on stream. The demulsifier combinations often used for emulsion treatments become ineffective as more complex emulsions are produced. Our approach was to first understand the oils and emulsions under normal operating conditions when the demulsifiers perform successfully and then compare the demulsifier performance under conditions when treatments fail. The performance of the demulsifiers with three produced fluids was studied. In order to confirm the findings, we reproduced the fluids that were unresponsive to the demulsifiers and tested our hypothesis with combinations of fluids and two different demulsifiers. We also examine the interfacial behaviors such as three-phase contact angles to determine the causes behind the poor performance of the demulsifiers with the difficult-to-treat emulsions. Experimental Section Materials and Methods. Heavy oil emulsions were obtained from a SAGD production operation in northern Alberta. Fresh production fluids at 80 °C were collected into several 20-L containers from the producer pipes. The samples from several wells were identified as heavy oil product (hop) 1 to 4 (hop-1 to hop-4). Here, hop-1 was used as a second normal test sample for verifying the data. Samples of hop-2 and hop-3 were similar in composition and were then pooled (hop-2-3) for use as the reference emulsions. Sample hop-4 was the difficult-to-treat emulsion. The freshly produced fluids were cooled to room temperature and the oil- and water-continuous emulsions were allowed to segregate for 1 d before decantation. The mass ratios of each phase (7) Bailes, P. J.; Kuipa, P. K. Chem. Eng. Sci. 2001, 56, 6279-6284. (8) Xia, L.; Lu, S.; Cao, G. J. Colloid Interface Sci. 2004, 271, 504506. (9) Pen˜a, A. A.; Hirasaki, G. J.; Miller, C. A. Ind. Eng. Chem. Res. 2005, 44, 1139-1149. (10) Stark, J. L.; Asomaning, S. Energy Fuels 2005, 19, 1342-1345. (11) Zhang, Z.; Xu, G.; Wang, F.; Dong, S.; Chen, Y. J. Colloid Interface Sci. 2005, 282, 1-4.

10.1021/ef060240l CCC: $37.00 Published 2007 by the American Chemical Society Published on Web 01/30/2007

Demulsifier EffectiVeness with HeaVy Oil Emulsion

Energy & Fuels, Vol. 21, No. 2, 2007 913

Figure 1. Schematic for separation and analysis of produced fluids.

were then determined. The separation and treatment of a typical heavy oil emulsion sample is indicated schematically in the flow chart of Figure 1. The oil, water, and solids compositions of the two separated phases were determined. The pH and specific conductivity (SC) of the water-continuous phase were measured. The mineral content of the solids was analyzed by X-ray diffraction. The viscosity of the extracted oil as temperature varied was determined using a Cambridge Viscolab 3000 falling ball viscometer. The densities of the oils at increased temperature were determined with a cytometer as well as by using a PAAR DMA4500 (Germany) densitometer. The asphaltene contents of the oils were measured by ASTM D2000 methods.12 Microscope images of the emulsions sealed in 200-µm deep Helma cells were observed and photographed using a Nikon E600 microscope and a Nikon AE850 digital camera. The sand and oil interactions were observed using a video camera attached to an infinity microscope and were recorded with a Sony video recorder. Sand, oil, and water were placed in a 5-cm square quartz jar and mixed by a Lightnin mixer motor driving a 2.54-cm diameter 4-blade axial impeller at 300 rpm. A quartz plate was the model solid surface used for measuring the three-phase contact angle. The separated water- and oil-continuous emulsions were treated using a water-soluble demulsifier (WSD), oil-soluble demulsifier (OSD), or combinations of both. These demulsifiers were polyalkoxylated phenolic resins made up of combinations of polymeric chains of ethylene oxide (EO) and propylene oxide (PO) attached to phenolic resin. The numbers of EO or PO units were unknown. However, it is known that such water-soluble demulsifiers have more EO than PO units in the molecule while oil-soluble fractions have more PO than EO units. The molecular weights were unknown. As the detailed structures of the demulsifiers were unknown (proprietry), the present work focuses on the observable phenomena involved in their effectiveness. The inorganic salts NaHCO3, CaCl2, K2CO3, and KCl were 99.99% purity sigma-grade obtained from Aldrich Chemicals. The acids (2 mol/L HCl and 2 mol/L H2SO4) and the base (2 mol/L NaOH) were Fisher ACS-grade. The pH buffers (4.0, 7.0, 10.0) (12) Fractionation of crudes by SARA Analysis; ASTM-2007D, ASTM: West Conshohoken, PA, 2000.

and conductivity standards (KCl) were pre-prepared Fisher Scientific products. A food-grade 35-wt% H2O2 obtained from HCI Canada was used for pretreating the Ottawa sand from Illinois. Spectroscopic or HPLC purity (Optima) organic solvents CHCl3, CH2Cl2, n-heptane (for asphaltenes analysis), toluene, and acetone (for cleanup) were from Fisher Scientific. Ottawa sand was the model solid used to test the role of the sand in the difficult-to-treat emulsions. The Ottawa sand was first washed by a sequence of treatments to remove excess fines and impurities: First, the sand was reacted with H2O2 to oxidize and remove organics; second, it was washed with H2SO4 (2:1 ratio by volume) to remove inorganic bases such as carbonates; and third, it was neutralized to pH 7.0 followed by copious washing with deionized water and wet sieving by minus 50- to minus 70-mesh (297-210 µm) standard ASTM sieves (Tyler brand, USA). The sand was oven dried at 105 °C for 48 h and tested for surface impurities using X-ray diffraction analysis and photoacoustic Fourier transform infrared spectroscopy (FTIR-PAS). X-ray diffraction analysis showed mainly quartz and no contaminants. At first, the clays on the sand samples were not detected by FTIR-PAS. Then, several batches of 30 wt % of the dried sand were mixed at 800 rpm for 2.5 h in deionized water, the supernatant was removed after mixing, and the suspension was allowed to settle over a few days. The supernatants were decanted, and the sedimented fine solids were removed, pooled together, and dried. Photoacoustic FTIR spectroscopy showed traces of kaolinite clay residue in these pooled fine samples. Size analysis of the sand by light scattering gave a wide size distribution, d10 ) 221 µm, d50 ) 303 µm, d90 ) 413 µm, d32 ) 294 µm. The zeta potential was -45 mV in model process water (mpH2O) at pH 8.5. Three-phase contact angle measurements were conducted in the model process water (mpH2O) that was made by dissolving 0.7892 g NaHCO3 (0.01 mol/L), 0.0002 g CaCl2 (1.8 × 10-6 mol/L), and 0.0189 g K2CO3 (1.37 × 10-4 mol/L) in 1 L of deionized water (dH2O). The pH of the water was 8.5, and the specific conductivity (SC) was 870 µS/cm at 25 °C. Contact angle measurements were performed at a room temperature of 22 °C using a Rame-Hart goniometer assembly (USA). Using a metered microliter syringe attached to a curved needle, the sessile drops of oil were delivered

914 Energy & Fuels, Vol. 21, No. 2, 2007

Angle et al.

Figure 2. Micrograph of a typical water-in-oil (W/O) emulsion in produced fluids. The scale at left indicates that 1 division ) 10 µm.

Figure 3. Micrograph of a typical oil-in-water (O/W) emulsion in produced fluids. The scale at left indicates that 1 division ) 10 µm.

onto the underside of a quartz plate immersed in the model process water contained in a larger glass cuvette. A stop watch was used for monitoring time. As required by the procedure, the water-soluble demulsifier was dissolved in the immersion water and the oil-soluble demulsifier was dissolved in the oil phase. Demulsification at atmospheric pressure (101.3 kPa) was conducted using 125-mL glass graduated jars (Korpak) immersed in the water bath heated by a Lauda recirculator controlled at 80 °C. Demulsification was also performed using hop-2-3 and hop-4 W/O emulsions at a diluent/oil ratio of 1.68 at 160 psi (1102 kPa) of pressure and 135 °C using a 1-L stainless steel reactor fitted with a thermocouple, a Lightnin motor, and an axial impeller for mixing at 300 rpm. The percentage of oil in water was analyzed at time intervals of 15 min of settling for water-continuous emulsions, and the percentage of water was analyzed in oil for oil-continuous emulsions by Karl Fischer techniques. The data plotted were water content versus time for separation in the reactor.

Results and Discussion Microscopic Images. Figure 2 shows a microscope image of a water-in-oil (W/O) emulsion while Figure 3 shows the oilin-water (O/W) emulsion with average oil drop sizes of the O/W being considerably larger than water droplets of the W/O (Figure

Figure 4. Micrographs of problem emulsions in produced fluids from a startup well hop-4: (upper) O/W and (lower) W/O. Scale 50 × 10-6 m.

2) for the typical heavy oil well production fluid hop-2-3. Figure 4 shows microscope images of the oil- and water-continuous emulsions for the hop-4 fluids that were difficult to treat. Density and Viscosity vs Temperature. Figure 5 shows that for the extracted dry heavy oil, the viscosity decreases as the temperature increases. The data are plotted as an Arrhenius form against 1/T in kelvin. The line indicates the fit to this model and is a typical response for heavy oils. Figure 6 shows the densities of the oil and water as a function of temperature. The separation of oil from water by gravity relies on the density difference, and as Figure 6 shows, at 160 °C, the densities of the water and the heavy oil are the same (0.91 g/mL).



Figure 5. Viscosity decrease with increasing temperature at 101.3 kPa for extracted heavy oil. A typical Arrhenius plot (log η vs 1/T) is shown in the fitted line to the data.

Figure 6. Density decrease with increasing temperature at 101.3 kPa for extracted heavy oil and water. Table 1. Analyzed Physical Properties and Compositions of Test Fluid Emulsions and Oils sample wt % oil wt % solids wt % water asphaltenes wt % in oil oil density g/mL at 22 °C pH SC mS/cm

hop-1 O/W

hop2-3 O/W

hop-4 O/W

hop2-3 W/O

hop-4 W/O

4.60 0.14 95.3 17.2

40.1 0.09 59.8 17.2

6.50 0.13 93.4 na

66 ( 7 0.45 ( 0.33 33.5 17.5 ( 0.9

75.0 3.2 21.8 17.8 ( 0.8

0.9923

0.9905

0.9965

0.9907

0.9965

8.6 ( 0.3 8.6 ( 0.3 8.8 ( 0.6 2.1 ( 0.4 2.1 ( 0.8 6 ( 3

Gravitational separation does not occur under these conditions. Table 1 shows the properties of the oils and water analyzed according to the schematic in Figure 1. Dewatering Emulsions at High Temperature and Pressure. Figure 7 compares the dewatering of hop-2-3 and hop-4 oil-continuous emulsions at 135 °C and 1102 kPa over time using the demulsifier combination of 500 ppm OSD and 90 ppm WSD. These dosages were found to be effective for dewatering the normal produced fluid under field conditions. Figure 8 compares photographs of hop-2-3 and hop-4 fluids that resulted after demulsification of the oil-in-water emulsion at 135 °C and 1102 kPa and cooling for 1 h. The photograph on the left clearly shows the ineffectiveness of the demulsifier combination used for hop-4 oil-in-water emulsion.

Figure 7. Water content measured in cream for treated hop-2-3 and hop-4 W/O emulsions with and without demulsifiers as a fuction of time in a reactor at 135 °C and 1102 kPa. Samples were diluted at diluent/oil ) 0.168.

Demulsification at 80 °C and Atmospheric Pressure. Figure 9 shows demulsifier effectiveness at varied WSD dosages and a fixed OSD dosage (500 ppm) as verified in bottle tests at 80 °C using hop-1 whole fluidssa combined oil-in-water and water-in-oil emulsion as received after 24 h. The clean separation of oil (dark top) and water (clear bottom) is shown for 90-500 ppm WSD and 500 ppm OSD. Figure 10 shows that while using a combined hop-2-3 water-continuous emulsion and hop-1 emulsion (top photograph), as well as hop-2-3 oilcontinuous emulsions and hop-1 emulsions (bottom photograph) so as to increase the oil content, successful demulsifications were obtained with 200 ppm WSD and 500 ppm OSD in bottle tests at 80 °C. The separation tests at 80 °C were repeated for combined O/W and W/O emulsions of hop-4 as the oil content was varied for each bottle while the demulsifier combinations remained the same. The results after 24 h of cooling are shown in Figure 11. Significant portions of the oil phase drop into the water phase starting at 20.2 wt % oil; the analysis for ash content in the oil was 0.35 g in 100 g of fluid, given a combined mass ratio of 10:40 oil phase to water phase. As the oil content in the samples was increased, the oil began settling by streaming down in a narrow band like a funnel into the water phase. However, Figure 12 shows that the hop-4 O/W and W/O emulsions fixed at 40 wt % oil and treated with combinations of fixed dosages of OSD (500 ppm) and varied dosage of WSD were also poorly demulsified. After 0.5 h at 80 °C, the separations were visible for the 200 ppm WSD sample, but the water phase contained a large amount of oil. After cooling for 24 h, the sample bottle darkened with a film of oil adhering to the glass. Thus, we concluded that hop-4 was clearly a problem fluid representing a treatment challenge that needed to be understood and that oil content was not the cause of the behavior. In the hop-4 oils, 3.2 wt % solids was present in the oil phase in contrast to 0.09 wt % solids in the hop-2-3 oil phase. Considerably lesser amounts of solids were found in the watercontinuous emulsions (see Table 1). By using toluene washes, centrifugation, filtration, and drying, dry solids (3.2 g) were extracted from the hop-4 oil phase. These solids were subsequently added to the hop-2-3 emulsions in order to mimic hop-4 emulsions (combined hop-2-3 O/W and W/O emulsions had a total of 40.3 g of oil in 100 g of the mixture). Figure 13 shows that by using 200 ppm WSD and 500 ppm OSD in bottle tests


Angle et al.

Figure 8. Comparison of settled water phase after treatment of hop-4 and hop-2-3 O/W emulsions with 90 ppm WSD and 500 ppm OSD after 30 min at 135 °C and 1102 kPa. Problem fluid hop-4 is shown at left.

Figure 9. Bottle test results at 80 °C for hop-1 O/W emulsions treated at increasing concentrations of WSD and 500 ppm OSD for 30 min. A clear separation can be seen at 90 ppm WSD.

Figure 10. Bottle test results for hop-1 mixed with hop-2-3 as the oil content increases, after treatment with 200 ppm WSD and 500 ppm OSD for 30 min of reaction at 80 °C (after 24 h of cooling). Photographs show the results of hop-1 and hop-2-3 water-continuous emulsions (O/W) (top) and oil-continuous emulsions (W/O) of hop-1 and hop-2-3 (bottom).

at 80 °C a similar funnel-like channelling of the oil phase settled into the water phase for both the mimic and problem emulsions (the solids spiked hop-2-3 and hop-4). This indicated that the

solids were responsible for the poor destabilization and separation of the oil and water phases. Table 2 shows an X-ray analysis of the solids extracted from the oil phase of hop-4. The analysis



Figure 11. Bottle test results for hop-4 as the oil content increases (increasing ratios of W/O to O/W mixed) after treatment with 200 ppm WSD and 500 ppm OSD for 30 min of reaction at 80 °C.

Figure 12. Bottle test results for hop-4 at 40 wt % oil after treatment with varied dosages of WSD and fixed dosage of OSD for 30 min of reaction at 80 °C.

shows that 98 wt % of the solids was quartz, and the rest was a combination of albite, kaolinite, chlorite, mica, rutile, and magnetite. Similar bottle tests were repeated using 3.5 wt % Ottawa sand added to the whole hop-1 emulsions at a fixed OSD dosage of 500 ppm and increasing dosages of WSD. Although separations began at 90 ppm WSD, at 175 ppm WSD the oil phase began coating the glass and oil funneled into the water once more. Deposited oil phase was seen at the base of the bottle and oil coated the surface of the bottle as well. An ash analysis of the oil phase indicated that oil deposition in the bottom of the flask began when the oil contained 0.32 wt % ash. A change to a combination of a different OSD (D309 at 70 ppm) and WSD (P70K at 300 ppm) that had been successful in other demulsification studies produced the same behavior. Once more, by using hop-4 emulsions, the same settling of the hop-4 oil phase in a funnel-like stream for a hop-4 W/O to O/W ratio of 10:40 was observed. The results confirmed that solids were causing the problems in effective demulsification. The oil-wet and fine solids stabilize the emulsions.13 The coarse solids that are mainly sand cause an increase in the average density of the solid-loaded oil. Increasing the solids content increases the effective density of the oil phase from

less than to greater than that of water. Considering the solids density to be 2700 kg/m3 and the diluted oil density to be less than that of water, then for each diluent to oil mass ratio, the density of the oil-diluent-solids mixtures will be the same as water for a range of solids concentrations and no separation by gravity will occur. In order for gravity separations to occur, the difference between the densities of water and the solids-loaded diluent oil should be sufficiently large. Thus, the diluent to oil ratio and solids content are important. However, it is also important to know how and under what conditions the oils adhere to sand in the presence of demulsifiers. Spreading and Wetting of Oil on Sand in Water. Figure 14 shows the schematics of oil spreading on sand immersed in water as the contact angles through the oil decrease. The experimental results in Figures 15-17 depict the effects of spreading and wetting phenomena of heavy oil on sand. Clean sand is shown as large white particles and heavy oil as black spots. Figure 15 shows a photomicrograph of the clean sand (white grains) followed by the addition of only diluted oil after mixing. The dark oil drops remained spherical. Figure 16 shows (13) Gelot, A.; Friesen, W.; Hamza, H. A. Colloids Surf. 1984, 12, 271303.


Angle et al.

Figure 13. Bottle test results for treated whole hop-4, O/W of hop-2-3 mixed with 3.5 wt % solids extracted from hop-4, and hop-2-3 only O/W, after reaction for 30 min at 80 °C with 200 ppm WSD and 500 ppm OSD. The oil content was fixed at 40.3 wt % in all cases. Table 2. Concentrations (weight percent) of Minerals Solids in the Hop-4 Oil Phase quartz

albite

kaolin

rutile

chlorite

mica

magnetite

98

0.2

0.9

0.1

0.03

0.4

0.1

that after the addition of 100 ppm WSD to the water phase droplets did not adhere to the sand. The addition of the OSD in excess at 800 ppm caused the oil to spread on the sand grains as shown in Figure 17. On mixing, the oil not only emulsified in the water, which became quite black, but also coated the sand grains. Figure 18 illustrates the changes in contact angle over time for a heavy oil droplet containing an oil-soluble demulsifier (OSD) on a quartz slide immersed in water that contains watersoluble demulsifier (WSD). The graphs show that when no OSD is present in the oil the contact angle slowly declines after a long wait time even as the WSD increases. The graphs also illustrate the changes of three-phase contact angle (measured through the oil phase) for toluene-diluted heavy oil with quartz as the WSD concentration in the model process water increases. When 500 ppm OSD (500 mg OSD/kg solvent-diluted oil) is present in the oil, the contact angle decreases as the concentration of WSD increases. The decline is greater after 5 min of equilibration. These data support the interaction of sand with the oil causing adhesion in most cases in the presence of the

Figure 14. Schematics of spreading of an oil droplet on sand in a water-continuous medium (not drawn to scale): (1) high contact angle and no spreading; (2) low contact angle and spreading.

Figure 15. No spreading and adhesion of toluene-diluted heavy oil (1:1) onto sand (3.5 wt %) in water after mixing.

OSD. This change contributes to further emulsification or dirty water as mixing progresses. The graphs of contact angle versus concentrations of WSD in Figure 18 also show that initially no spreading or wetting was observed at a contact angle designated as 180° for no contact. The very spherical drops on sand in Figure 15 confirm this result. The top graph of Figure 18 shows there are changes in the contact angle by the addition of only the WSD in the water phase. However, at a fixed dosage of OSD in the oil phase, and increased dosages of WSD in the water phase, spreading occurs. The black oil droplets that are spread on sand appear in the photomicrograph of Figure 17. The impacts of these effects are oil recovery problems, dirty oily water, and problems of sand disposal accompanied by oil losses.



Figure 16. Spreading of toluene-diluted heavy oil (1:1) onto sand (3.5 wt %) in water after mixing in water-containing 100 ppm WSD. The scale is 1 mm.

Figure 18. Reduced three-phase contact angle for oil/quartz/water as a function of WSD concentration, and comparing no OSD with 500 ppm OSD in oil at t ) 0 and t ) 5 min.

For our purpose, we are mainly concerned with the solidliquid-liquid systems, as oil is mixed with water and is in contact with free flowing sand. 4. Conclusions

Figure 17. Spreading and adhesion of toluene-diluted heavy oil (1:1) containing 800 ppm OSD onto sand (3.5 wt %) in water after mixing in water containing 100 ppm WSD. The water phase darkens with increased mixing.

One can determine the net amount of work done in wetting of solid-oil from solid-water, if the solid crosses the O/W interface, by using the surface tensions, the interfacial tension, and the contact angle14 as s/o Ws/w adh - Wadh ) σw/a - σo/a + σo/w cos θ

(1)

(1) The problematic fluids contained much higher solids than other fluids. (2) Solids in the problematic fluid were found to be coarse sand with very minor amounts of clays. (3) The water-soluble surfactant changed sand surfaces from water-wet to oil-wet, and the oil-soluble surfactant further reduced the contact angle. (4) Both OSD and WSD enhanced entrapment of sand in the oil phase. (5) Oil-wet solids reduced the density difference between oil and water. (6) Oil-wet solids hindered separation of the oil-continuous phase from the water phase which is important for effective dewatering. Acknowledgment. This study was supported by the federal Panel on Energy Research and Development and CANMET at Advanced Separation Technologies CETC-Devon. We thank Dr. Yuming Xu for assistance in doing the contact angle measurements. EF060240L (14) Adamson, A. W. Physical Chemistry of Surfaces; John Wiley & Sons: New York, 1982.

Demulsifier Effectiveness in Treating Heavy Oil Emulsion in the

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