Article Type: Research Article Article Citation: Emmanuel J. Ekott. (2020). CORRELATION OF
ASPHALTENE SOLVATION WITH STABILITY OF CRUDE OIL EMULSION USING SCALING
EQUATIONS. International Journal of Engineering Science Technologies, 4(3), 19-29.
https://doi.org/10.29121/IJOEST.v4.i3.2020.87 Received Date: 10 May 2020 Accepted Date: 29 May 2020 Keywords: Crude Oil Emulsion Asphaltene Solvation Bancroft’s rule Scaling Equations ABSTRACT Due to the simplicity of scaling equations and its applicability to colloid chemistry, the scaling theory is widely used in studying emulsion properties such as force profiles. Scaling equations were developed for the studied samples for correlation of asphaltene solvation with stability of crude oil emulsions. Correlations were made for viscosity and percentage water resolved by varying the volume concentration of toluene in heptol mixture that was used as solvent for the asphaltene re-dissolution. The study shows that tuning the composition of heptol allows fine control of colloidal forces between asphaltene surfaces in an organic solvent and therefore determines the stability state of the emulsion. Statistically derived correlation equations provide for a range in the aromaticity of the crude medium for which an optimum stability is observed and therefore gives good understanding on the control of emulsion stability. The study further shows that emulsion inversion can be achieved by adjusting the concentration of surfactant.
1. INTRODUCTIONCrude oil is a complex fluid containing asphaltenes, resins
and napthenic acid in addition to saturates and aromatic hydrocarbons. Asphaltenes is the heaviest and most polar
fraction in the crude oil and stabilized the water in oil emulsion that
occurred during crude oil production. Problems
associated with oil well production, pipeline transfer, land and sea-based
transportation and ultimately, oil refining have been heavily linked to the
presence of asphaltenic colloids in the crude oil. This can increase pumping
and transportation expenses, corrosion of pipes, pumps, production equipment
and distillation columns, and the poisoning of downstream refinery
catalysts. During visbreaking and
catalytic hydrocracking large amounts of sludge and sediment can form
ostensibly due to the flocculation of asphaltenes during processing. Coke
generation and asphaltene adsorption within catalytic cracking beds can reduce
the effective catalyst surface area as well as the efficiency of coal
hydropyrolysis (Specker and Kilpatrick, 2004). Asphaltene deposition within
reservoir rocks has been blamed for pronounced reductions in well productivity
(Cimino et al, 1995). According to Siffert, Bourgeois and Papirer (1984) asphaltenes
have been found to facilitate the formation of extremely stable water-in-crude
oil emulsions. Understanding asphaltene chemistry and the fundamental
mechanisms of colloid formation has been the driving force behind much
petroleum research in recent years. The study of asphaltene colloidal
properties has been motivated by their propensity to aggregate, flocculate,
precipitate, and to adsorb onto interfaces (Espinat et al, 1993). To
help improve the conversion of crude oil into useful products by reducing
losses to sludge and emulsions, it is necessary to better understand the
factors that affect their formation. Paramount to this understanding is an
in-depth knowledge of the structures and interactions of the asphaltenic
components responsible. Ekott and
Akpabio (2013) investigated asphaltene solvation nexus and stability analyses
of heavy crude oil emulsions and reported that tuning the composition of heptol allows fine
control of colloidal forces between asphaltene surfaces in an organic solvent
and therefore determines the stability state of the emulsion. Their study
revealed that the crude aromaticity is definitely a primary factor in
determining the stability of asphaltene-stabilized emulsions while the
asphaltene type plays at least a secondary role in determining the resultant
emulsion stability. Their recommendation of extending the study range to
toluene volume fraction of 0.9 necessitated this study. This study correlates asphaltene
solvation with stability of water in crude oil emulsion using scaling
equations. Third order polynomial curve fitting equations have been reported by Hong and Watkinson (2004) to best fit the solubility of asphaltene. They however reported that the solubility of asphaltenes from different crude source conform to different scaling equation. Hu et al (2004) elaborated on scaling equations and stated that polynomial curve fitting equations of third order fit the modeling of asphaltene precipitation. This has been collaborated by Wang (2011) where third order polynomial curve fitting equations were used as scaling equations for measurement of asphaltene colloidal force. Wang (2011) stated that due to the simplicity of scaling equations and its applicability to colloid chemistry, the scaling theory is widely used in studying emulsion properties such as force profiles. 2. MATERIALS AND METHODSUsing asphaltene solvation test results as reported by Ekott
and Akpabio (2013), scaling equations were developed for the studied samples
for correlation of asphaltene solvation with stability of crude oil emulsions
for solvation range outside the laboratory studied range. The researcher used five crude oil emulsion samples from
Niger Delta region of Nigeria for their study. Samples were collected from both
onshore and offshore oil well sources for balanced investigation. The onshore
samples were SPDC Yokri, SPDC Otumara, and Seplat Oben emulsions. Chevron VRMT
and Mobil QIT emulsions were from offshore locations. The samples were
collected into labelled plastic containers from flow stations by opening of the
respective flow valves. 100ml of crude oil emulsion sample was measured and
weighed. 25ml of n-heptane was added, and shaken to dissolve for 10 minutes. It
was then vacuum filtered. The precipitate was rinsed with excess n-heptane
until the effluent runs were clear. The precipitate was then dried in an oven
at 25oC for an hour. 3g portion each was measured into 5 different flasks and
1ml each of 5 different heptol mixtures was added. The heptol mixtures were
prepared by mixing heptane and toluene in the following proportion by volume
respectively: 90:10, 80:20, 70:30, 60:40, and 50:50. To each flask, a fresh crude
oil emulsion sample was added to make a volume 300ml (this was the viscometer
required volume for measurement of viscosity). It was stirred and allowed to
stand for 1 hour. The viscosity of each of the mixtures was then measured with
viscometer and recorded after thorough stirring. 10ml of each of the mixtures
was thereafter taken into 5 test tubes and 1ml of QIT 007 demulsifier was added
to each test tube and allowed to stand for 10 minutes. The percentage water
separated was recorded as an index for stability of emulsion based on the
contribution of soluble asphaltene. The entire process was repeated for the
other four crude oil emulsion samples. 3.
RESULTS AND
DISCUSSION
Experimental
results obtain for the work were published by Ekott and Akpabio (2013) and
presented here on table 1. Table 1: Viscosities (CST) and Percentage Water Separation for
Asphaltene Solvation Tests
Using observed data for each
of the studied samples (table 1), scaling equations were developed. The general
form of a polynomial of order j curve
fitting equation is presented in equation 1 The expression for any error
using the least squares approach is given by equation 2 The
intention is to minimize this error. Substituting equation 1 into equation 2, equation
3 is obtained thus: Where
n = number of observed data points, i = the current data point being summed and
j = the polynomial order. Equation 3 can be re-written as: To
minimize equation 4, find the coefficients by first taking derivative with respect to
each coefficient where k = 1, …, and j =0. Equation
5 Rewriting
equation 5 and putting into matrix, give equation 6
Equation 6 Rewriting
equation 6 for a third order polynomial, gives
Equation
7 Solving
equation 7 for , provides solution to the third order curve
fitting polynomial equation 8 Five
third order polynomial equations obtained for viscosity of SPDC Yokri, SPDC
Otumara, Chevron VRMT, Seplat-Oben and Mobil QIT emulsions respectively are
presented below: Similar
equations for percentage water resolved were also obtained and presented below
for SPDC Yokri, SPDC Otumara, Chevron VRMT, Seplat-Oben and Mobil QIT emulsions
respectively. Equations 9 through 13 were used to predict the
viscosity of the respective samples at different stages of solvation including
extrapolated toluene concentrations of 0.6 to 0.9 volume fractions. Results for
the predicted values are presented on table 2 below. Equations 14 through 18
were used to predict the percentage water resolved of the respective samples at
different stages of solvation including extrapolated toluene concentrations of
0.6 to 0.9 volume fractions. Absolute values were considered as negative signs
only indicated reversal of the plot lines. This was important since viscosity
and amount of water resolved cannot be negative. Results for the predicted
values are also presented on table 2 below. Table 2: Predicted Percentage Water
Separation and viscosities (cst) of Asphaltene Solvation in heptol using
scaling equations
The effect of solvent solvency on viscosity and stability of
precipitated asphaltene for each of the samples using scaling equations are
presented on figures 1 – 5. Figure
1: Effect of solvent solvency on
viscosity and stability of Precipitated Asphaltene SPDC Yokri Crude Emulsion
using scaling equations Figure
2: Effect of solvent solvency on
viscosity and stability of Precipitated Asphaltene SPDC Otumara Crude Emulsion
using scaling equations Figure
3: Effect of solvent solvency on viscosity and stability of Precipitated
Asphaltene Chevron VRMT Crude Emulsion using scaling equations Figure
4: Effect of solvent solvency on
viscosity and stability of Precipitated Asphaltene Seplat-Oben Crude Emulsion
using scaling equations Figure
5: Effect of solvent solvency on
viscosity and stability of Precipitated Asphaltene Mobil QIT Crude Emulsion
using scaling equations These
results can be understood in the light of the solubility state of the
asphaltenes. McLean and Kilpatrick
(1997) established that asphaltenes from Arabian and Venezuelan crude
oils were in true solution when the toluene concentration in heptol was greater
than 50% (v/v) using photon correlation spectroscopy (PCS). When the toluene
concentration was reduced from 50% to 10%, the asphaltenes were colloidally
dispersed and were ultimately precipitated out of solution. Therefore,
at crude aromaticities lower than 20% toluene, some of the asphaltenes are
certainly precipitated out of solution in the form of aggregates which are too
large to adsorb and remain at the interface in order to affect the optimum
degree of stabilization. In the middle range of crude aromaticity (30–60%
toluene, depending on sample), the asphaltenes are most likely near or right at
the point of precipitating in the form of a fine dispersion ( i.e., very small
particulates). This dispersion of fine asphaltene particulates is capable of
adsorbing and stabilizing the water-oil interface to the optimum extent by
forming a barrier which is mechanically resistant to the coalescence of the
droplet phase. At the upper end of the aromaticity spectrum, the asphaltenes
are colloidally, if not molecularly, dissolved in the oil phase and are more
content to remain there in place of becoming interfacially active. Emulsions
produced from highly aromatic crude mediums are less stable to the coalescence
and phase separation of the dispersed water droplets. It
appears that as the system approaches 0.5 toluene volume fraction, the system
begins to change from a colloidal system to a solution. The system begins to
lose its stabilization properties as the surface active agents become weak. The
amphoteric properties of the surface active agents gradually diminish and as
such the oil and water moieties collapse causing the system to be converted to
solution. As the system gradually changes to a solution from this point, its
water retention capabilities gradually reduce because the system gradually
becomes a homogeneous mixture brought about by the increased aromaticity of the
solvent. The
result can also be interpreted in terms of asphaltene force profile. Since
asphaltenes (amphiphilic) and heptane (apolar) are significantly different in
molecular structure (highly aromatic of hetero-atoms vs aliphatic), the
asphaltene molecules tend to self-associate, aggregate and precipitate in
n-heptane. The dominant forces between asphaltenes in heptane arose from van der
Waals forces. For toluene volume fraction <0.2, heptol is a poor solvent and
there seem to be stronger adhesion between asphaltenes. While in a good solvent
of pure toluene, the adhesion force will be almost zero. For heptol with
toluene fraction 0.2 to 0.7, the solvency of heptol gradually increased
exhibiting relatively constant adhesion force. It appears that in poor
solvents, asphaltenes-asphaltenes interactions are stronger than
asphaltenes-heptol interactions, leading to stronger adhesion between asphaltene
surfaces and hence increase in viscosity. Wang (2011) measured the adhesion
force profile and reported that the force did not show highly significant
change at toluene volume fraction of 0.4 to 0.6 in heptol as shown in figure
4.28. At this region, we observed high viscosity and less water separation for
all the studied samples. This indicated the region of high emulsion stability
due to the freed surface-active agent caused by the solvation with heptol. Wang
(2011) also showed that the interactions between asphaltene surfaces upon
approach can be attractive or repulsive, depending on the quality of the
solvent. The repulsive forces between asphaltenes in heptol of toluene volume
fraction >0.2 are of steric nature and the electrical double layer force is
negligible. The attractive force measured in heptane can be well fitted with
only van der Waals forces. These observations indicate that heptol of toluene
volume fraction >0.2 is a good solvent, whereas heptol of toluene volume
fraction <0.2 is a poor solvent for asphaltenes. In good solvents, the
immobilized asphaltenes repel each other due to steric repulsion caused by the
swelling side-chains. In poor solvents, on the other hand, the immobilized
asphaltenes attract to each other by van der Waals forces, leading to
asphaltene aggregation and precipitation. In this study, the attraction between
asphaltene surfaces was observed at toluene volume fraction above 0.2, which
does not mean that only at toluene volume fraction <0.2 can asphaltenes
precipitate in heptol. At toluene volume fraction <0.5, the generally
accepted heptol composition at which onset of asphaltenes was observed, it is
possible that some asphaltene molecules in the asphaltene films are still in a
“precipitated” or compact state, but there are still some asphaltene molecules
in the asphaltene films soluble in heptol. The different studied samples show
variations of asphaltenes solvation at this point. The later part of
asphaltenes generates a repulsive force until at toluene volume fraction
<0.2 the overall interactions between asphaltenes are attractive. Since
attractive van der Waals forces are omnipresent in asphaltene/heptol system, it
was interesting to investigate the variation of van der Waals forces with the
solvent composition. This study indirectly investigated this force, as
variation in viscosity of the emulsion since the solvation state of asphaltene
was responsible for the varied viscosity of the emulsion. This study
demonstrates a decrease in van der Waals attraction with increasing toluene
volume fraction. The reduction of van der Waals forces with increasing toluene
volume fraction contributes to reduced adhesion and hence less
aggregation/flocculation of asphaltenes in toluene-rich heptol. However, the
contribution of van der Waals forces to the total force when toluene volume
fraction >0.2 is negligible. The dominant force between the asphaltene
surfaces in heptol with toluene volume fraction >0.2 is steric repulsion.
Moving towards poor solvent with decreasing toluene volume fraction in heptol,
the solvent becomes less favorable for the stretching of asphaltene molecules.
Parts of asphaltenes have aggregated with the polar segments shielded inside
the aggregates. As a result, part of the asphaltene layer could be rigid and
the others flexible. The rigid asphaltenes tend to condense to form a more
compact layer. This might have been responsible for the reversal of the
emulsion stability at toluene volume fraction of about 0.8. Using the scheme for dominant contributors to asphaltene solubility, state of aggregation, and the resulting impact on interfacial activity presented by McLean and Kilpatrick (1997) additional explanations can be offered to the results of this study. McLean and Kilpatrick scheme showed that as the volume fraction of the aromatic solvent increases, the bulky asphaltene precipitates that were very weakly solvated and hence provided very weak surface-active properties gradually become moderately solvated with better surface-active properties. The state of solvation increases as the aromaticity of the solvent increases until it becomes strongly solvated and the surface-active agent becomes weak again. Results of this work conformed to this scheme. Figures 1 – 5 show that as toluene volume fraction increases, the stability of the emulsion increases with peak at about 0.4 - 0.5 toluene volume fractions where the asphaltenes are moderately solvated. Above this region, the asphaltenes were strongly solvated and the surface-active agents become less active resulting in weak emulsion stability. High emulsion stability was however observed for Seplat-Oben emulsion at 0.7 toluene volume fraction as shown in figure 4. This was due to the very high-water content of the emulsion. The shapes of the viscosity and percentage water resolved plots for the studied samples were also very informative. Figures 2, 3 and 4 for SPDC Otumara, Chevron VRMT and Seplat-Oben emulsions respectively informed a narrow range of stability compared to figures 1 and 5 for SPDC Yokri and Mobil QIT emulsions respectively. This implies that in controlling the solubility of asphaltenes in SPDC Otumara, Chevron VRMT and Seplat-Oben emulsions, we expect to have best demulsification outside a small range as shown in the figures. The other samples will be expected to be more problematic as the range of emulsion stability is wide. However, the respective figures provide the most precise point of solvent solvency for highest and least emulsion stability. Moreover, the scaling equations proved to be useful models for determination of emulsion stability as can be harvested from figures 1 – 5. The
shape of figure 4 can be explained further in light of Bancroft’s rule and
Hydrophile-Lipophile Balance (HLB). Bancroft’s rule states that the phase in
which the surfactant is most soluble is the continuous phase of an emulsion and
added that the solubility should be determined by the total surfactant
concentration in a phase. In this study, asphaltene surfactant become more soluble
as the aromaticity of the solvent increased implying that the surfactant
concentration increased in the aqueous phase. An interesting case emerged for
Seplat Oben sample. For this sample, the percentage water content was over 62%
and the emulsion was within a phase inversion region. As the aromaticity of the
solvent increased above 0.2 toluene fraction the asphaltene becomes more
soluble and therefore increased the surfactant concentration. Anisa, Nour and
Nour (2010) had mentioned that such increased in surfactant concentration can
led to phase inversion. This is more likely in a system where other conditions
like water cut level was also at point of phase inversion. Figure 4 therefore
shows that at about 0.2 toluene fraction the Seplat Oben sample inverted from
oil-in-water emulsion to water-in-oil emulsion. Hydrophile-Lipophile
Balance (HLB) is described by a number that gives an indication of the relative
affinity of a surfactant molecule for the oil and aqueous phases of an
emulsion. A molecule with a high HLB number has a high ratio of hydrophilic
groups to lipophilic groups. According to Anisa, Nour and Nour (2010) changing
the HLB of an emulsion, which depend on the nature and concentrations of the
emulsifying agents can led to phase inversion. Michaels (2006) formulated the
expression HLB = 7 + ∑(hydrophilic group numbers) – ∑(lipophilic group numbers) Equation 19. Michael
also added that the HLB range for water-in-oil and oil-in-water emulsions are 3
– 10 and 11 – 18 respectively. In this work, increasing the solvent aromaticity
caused change in the HLB number. From Bancroft’s rule, when more of the
surfactant is soluble in the lipophilic phase, the number of lipophilic group
increases and this result in reduction of HLB number according to Michaels’
expression. For toluene volume fraction less than 0.2 for Seplat Oben sample,
the number of lipophilic group might have increased as the aromaticity of the
solvent increased and caused a phase inversion at about toluene volume fraction
of 0.2. As the emulsion becomes water-in-oil emulsion, the continuous phase of
the emulsion becomes the hydrophilic phase and further increased in aromaticity
caused increased in number of hydrophilic group. The result of this on
Michaels’ HLB expression is increase in HLB number. Figures 1 – 5 show
progressive impact of this increment as the toluene volume fraction increases. 4. CONCLUSIONSThe study
shows that tuning the composition of heptol allows fine control of colloidal
forces between asphaltene surfaces in an organic solvent and therefore
determines the stability state of the emulsion. Statistically derived
correlation equations provide for a range in the aromaticity of the crude
medium for which an optimum stability is observed and therefore gives good
understanding on the control of emulsion stability. The study further shows that
emulsion inversion can be achieved by adjusting the concentration of
surfactant. As the asphaltene surfactant become more soluble as the aromaticity
of the solvent increased, the emulsion system of one of the samples was
inverted because the surfactant concentration increased in the aqueous phase
and these findings conformed to both HLB number theory and Bancroft’s rule of
emulsion. SOURCES OF FUNDINGNone. CONFLICT OF INTERESTNone. ACKNOWLEDGMENTNone. REFERENCES[1] Anisa, A. N. I; Nour, A. H.; Nour, Ashary H (2010): Castastrophic and Transitional Phase Inversion of water-in-oil Emulsion for Heavy and Light Crude Oil. Journal of Applied Sci., 10(23) 3076 – 3083. [2] Cimino, R., et al. (1995): Solubility and Phase Behavior of Asphaltenes in Hydrocarbon Media, in Asphaltenes: Fundamentals and Applications, E.Y. Sheu and O.C. Mullins, Editors. 1995, Plenum Press: New York, 97-130. [3] Ekott and Akpabio (2013): Understanding Asphaltene Solvation Nexus and Stability Analyses of Heavy Crude Oil Emulsions. Int. Journal of Engineering, Science and Technology. Vol.3, No. 1 [4] Espinat, D.; Ravey, J. C.; Guille, V.; Lambard, J.; Zemb, T. and Cotton, J. P. (1993): Colloidal macrostructure of crude oil studied by neutron and X-ray small angle scattering techniques. Journal de Physique IV, (Colloque C8, supplément au Journal de Physique I), 181-184. [5] Hong, E. and Watkinson, P. (2004): A study of asphaltene: Solubility and Precipitation. Fuel, 83, 1881 – 1887. [6] Hu, Yu-Feng; Li, S; Liu, N; Chu, Y; Park, S. J.; Mansoori, G. A and Guo, T. (2004): Measurement and corresponding states modelling of asphaltene precipitation in Jilin reservoir oils. Journal of Petroleum Science and Engineering. 41(1-3), 199-221 – 242. [7] McLean, J. D. and Kilpatrick, P. K. (1997): Effects of asphaltene aggregation in model heptane-toluene mixtures on stability of water-in-oil emulsions. Journal of Colloid and Interface Science, 196 (1), 23-34. [8] Siffert, B.; Bourgeois, C. and Papirer, E. (1984): Structure and Water-Oil Emulsifying Properties of Asphaltenes. Fuel, 63 (6): p. 834-837. [9] Spiecker, P. M. and Kilpatrick, P. K (2004): Interfacial Rheology of Petroleum Asphaltenes at the oil-water interface. Langmuir. 20. 4022-4032. [10] Wang, S. (2011): Understanding Stability of Water-in-diluted Bitumen Emulsion by Colloidal Force Measurements. Ph.D. Thesis, University of Alberta, Edmonton.
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