Effect of Resins on Asphaltene Deposition and the Changes of

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Effect of Resins on Asphaltene Deposition and the Changes of Surface Properties at Different Pressures: A Microstructure Study Farhad Soorghali, Ali Zolghadr, and Shahab Ayatollahi*,† Enhanced Oil Recovery (EOR) Research Center, School of Chemical and Petroleum Engineering, Shiraz University, Post Office Box 7134851154, Shiraz, Iran S Supporting Information *

ABSTRACT: Asphaltene deposition has hindered oil production from asphaltenic oil reservoirs through deposition in reservoir rock and surface facilities. This paper investigates the effect of resin on asphaltene deposition at different pressures. To investigate the asphaltene deposition in the presence of resins at reservoir temperature and different pressures, a pressure, volume, and temperature (PVT) visual cell was designed. A high-resolution microscope and image processing software were used to detect and determine the amount of deposited asphaltene as well as its size distribution at different conditions. Two types of Iranian crude oils with different potential of deposition (low and high) were used in this work. In the first stage, the amount of asphaltene deposition and the changes of surface properties were recognized through the depressurizing process with and without the presence of resins in the fluid. The wettability changes as a sign of surface properties were studied by contact angle measurement, and also for further investigation, the atomic force microscopy (AFM) technique was used. The results verify that the amount of asphaltene deposition increases when the pressure increases and the quantity of asphaltene deposition decreases as the resin/asphaltene ratio in these samples increases. At high ratios of resin/asphaltene, the asphaltene was found to be more stable. However, the results showed that, as the pressure increases, the stability of asphaltene decreases more than expected. The surface property changes indicate that, in the presence of resins, the surfaces become more water-wet and their roughness decreases.

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INTRODUCTION A petroleum fluid is generally divided into three parts: (1) oils (that is, saturates and aromatics), (2) resins, and (3) asphaltenes.1−3 This partitioning is very broad; each part of the petroleum fluid also consists of a wide range of molecules with varying structures and properties.4 If the components of crude oil are investigated in terms of polarities, asphaltenes and resins are polar molecules, while the oils are either non- or mildly polar.5,6 For most of the crude oils, they contain more saturates and aromatics; however, even small concentrations of asphaltenes would affect the quality of the crude oil because they can easily aggregate and deposit on the surfaces as well as affect their rheological properties.7−9 Asphaltene is defined as part of crude oil, which is insoluble in normal alkanes, such as n-heptane, but soluble in aromatic solvents. 8−10 Also, asphaltenes are formed from polyaromatic nuclei with aliphatic side chains and rings. These compounds in the presence of aromatic hydrocarbons (or other polar solvents) associate and form micellar aggregates (nanoscale).11−14 It is realized that asphaltenes contain aromatic compounds and also different acidic and basic functional groups.15 Asphaltene problems considerably affect the economics and technical feasibility of petroleum production, either through in situ deposition in the reservoir, in the wellbore, or at the surface production facilities, including the transportation systems.16−18 Asphaltene deposition has also been reported in deep water offshore production facilities.19−21 Asphaltene aggregates (macroscale) when some of the fluid properties, such as composition, temperature, and pressure, are changed during the production and transportation.22,23 The most important parameters that promote © 2014 American Chemical Society

asphaltene aggregation are the amount of paraffin, temperature, and pressure changes.24,25 Resin is another parameter that could affect asphaltene aggregation. Resin is known as a fraction of the deasphalted crude oils that is adsorbed in silica gel and is extracted with polar solvents.26 There are two views to study the condition of asphaltenes in the crude petroleum systems. The first opinion considers asphaltenes in terms of solubility that are dissolved in the surrounding medium, and asphaltenes precipitate after the oil solubility falls below a certain condition.27−29 The second opinion looks at resin as specific stabilizer agents of asphaltene molecules. Recently, the study of resins with the recognition of their effect on the stability of asphaltenes in petroleum fluids has been developed.30,31 The stabilization of crude oil is recognized because of the association of resins with asphaltenes to form micelles.32 In a micelle, the core is formed from self-associating asphaltenes into an aggregate and resins are adsorbed onto the core to form a steric shell.33 The asphaltene stabilization depends upon the resin/asphaltene ratio in the crude oil inside the reservoir.34 The molecular structure of resins is not unique in different parts of crude oil reservoirs. However, they exist as a group of molecules specified by solubility and adsorption behavior.35,36 There are many studies on the effect of resins during the asphaltene precipitation process.37−40 The main point of these studies describes the effect of resins on the onset of asphaltene precipitation. Received: January 4, 2014 Revised: March 10, 2014 Published: March 10, 2014 2415

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Until now, the effect of resin on asphaltene deposition and surface property changes have not been studied at different pressures. In this work, the stabilizing role of resins on asphaltene precipitation at the reservoir temperature and different pressures is studied. During this experimental study, synthetic oil (heptol) with different ratios of resin/asphaltene was used as the oil model to analyze the conditions for asphaltene precipitation and deposition. A high-pressure and high-temperature (HPHT) pressure, volume, and temperature (PVT) cell, which was already manufactured45,46 for the asphaltene precipitation and deposition study, was used to investigate the mentioned parameters at reservoir conditions. Slide glasses were used to mimic sandstone surfaces as they are placed in the PVT cell, while their surfaces were monitored carefully using a digital camera, and the captured pictures were analyzed by a computer. Atomic force microscopy (AFM) has recently been used to characterize the surface properties at the nano structure level. For instance, in this study, the root-mean-square (RMS) and mean roughness were obtained from AFM analysis, and the topography of the surfaces treated at different fluids was monitored carefully. Quantitative measurement of surface roughness is considered to be a valuable characteristic of the AFM technique. Therefore, this method was used here to find out the surface property alteration. For further investigation of the effect of resin on asphaltene deposition and changes of surface properties, the AFM technique and wettability measurement tests were also used.

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Figure 1. Schematic diagram of the experimental apparatus, including (1) peristaltic pump, (2) distilled water reservoir, (3) computer, (4) CCD camera, (5) microscope, (6) slide glass, (7) piston cylinder, (8) cold light source, (9) heater, (10) magnetic mixer, (11) high-pressure cell, (12) rotator, (13) metal disk, (14) fan, and (15) magnetic device. The precipitated asphaltenes, which deposit on the slide glasses, are captured by a charge-coupled device (CCD) camera (IDS, UI1485LE-C5 HQ, 5.7 megapixels), which is installed on the top of a microscope (Krüss, MBL2000), with an optical resolution of up to 480×. A magnetic device from the outside of the cell could rotate the rotating disk to keep each slide glass in front of the microscope. A source of cold light installed inside the cell was supplied to lighten the dark solution without generating excess heat. According to the operator needs, the images or videos can be captured with different resolutions. In this study, the captured images were analyzed with Sigma Scan Pro 5 software. To adjust the cell temperature and pressure, a heater, which was installed outside of the cell, and a highpressure liquid chromatography (HPLC) pump (Agilent Technologies 1200 series) were used, respectively. The tests were carried out at a constant temperature of 363.15 K and four different pressures: P1, 435.11 psia; P2, 870.23 psia; P3, 1450.38 psia; and P4, 2030.53 psia. A detailed description of the experimental apparatus is reported elsewhere.45,46 Experimental Procedure. A total of 0.40 g of asphaltene was dissolved in 275 mL of toluene, followed by stirring gently for 20 min, using a magnetic stirrer. Then, the desired amount of resins, in specific ratios to the asphaltenes, was added to the solution and stirred for another 40 min. After 1 h, 225 mL of n-heptane was added to the mixture, and the final solution was mixed again for another 1 h. The prepared synthetic oil was injected into the cell, and then it was allowed to reach the desired temperature (363.15 K). The pressure of the cell was then increased to 2030.53 psia using the HPLC pump. The solution in the cell was allowed for possible asphaltene deposition on the slide glasses for a certain period of time. During this process, high-resolution images were captured sequentially. The pressure was then reduced to the second stage (1450.38 psia) at a constant temperature (363.15 K). The solution was stirred to remove all of the asphaltene particles deposited on the slide glasses from the previous step. Then, the image capturing was continued, and the same procedure was repeated for this pressure. The asphaltene-deposited area and particle size distribution were measured with the image processing software. After each test, the slide glasses were removed from the disk for the wettability test (contact angle measurement by DSA100, Krüss) and AFM analysis. The fluid inside the cell was exited slowly (during exiting of the fluid, the position of asphaltene is checked by a camera to stay fixed), and slide glasses stay inside the cell for 48 h to become completely dry and are then taken out carefully to be ready for next test. Static contact angle measurements with the sessile drop method were recorded and analyzed at room temperature by DSA100 (Krüss). In this method, a liquid drop rests on a horizontal flat solid surface (Figure 5). The contact angle is defined as the angle formed by the intersection of the liquid−solid interface and the liquid−vapor interface (geometrically acquired by applying a tangent line from the contact point along the liquid−vapor interface in the droplet profile). While the drop reaches a stationary position in about 1 s, the measurement takes place in a few minutes after the drop is

EXPERIMENTAL SECTION

Materials. There are several methods for asphaltene and resin extraction mentioned in the literature (e.g., ASTM D893-69, D200780, and modified D2007-80);41 however, the used methods in this work are based on the removal of asphaltenes by precipitation using paraffinic solvent (n-heptane, IP 143/90)42 prior to chromatographic separation of the remaining crude oil on attapulgite clay and/or silica gel.41 Asphaltenes were extracted from two different Iranian crude oil samples (Kuh-e-Mond and Bangestan, with their structures and composition mentioned in other papers),43,44 by dissolving in excess nheptane with the ratio of 20:1, and then the Soxhlet method was used for more purification. Resins were extracted from the deasphalted oil with the column chromatography method.41,48 The maltene (deasphalted oil + nheptane) was adsorbed to a column of silica gel (Merck, 35−70 mesh ASTM); then the saturates and aromatics were washed by a solution of 70:30 n-heptane (Merck, mole fraction purity of >0.990) and toluene (Merck, mole fraction purity of >0.990); and finally, a mixture of acetone (Merck, mole fraction purity of >0.990), dichloromethane (Merck, mole fraction purity of >0.990), and toluene with the ratio of 40:30:30 was used to extract the resins from the column. Synthetic oil used in this study was made by mixing n-heptane and toluene (heptol). Slide glasses were used as the solid surface to mimic the sandstone rock in the reservoir. The saturates, aromatics, resins, and asphaltenes (SARA) analysis and composition of crude oil samples are presented in the reported tables (see Tables S1 and S2 of the Supporting Information). Experimental Apparatus. HPHT Visual Asphaltene Deposition Apparatus. In this study, an apparatus, designed at the Shiraz University Enhanced Oil Recovery (EOR) Research Center, was used to visually observe and determine asphaltene deposition at different ratios of resin/asphaltene at different pressures and temperatures. The schematic of this apparatus is shown in Figure 1. This apparatus consists of a high-pressure cell, which is filled by the oil sample. A rotating metal disk is placed horizontally inside the cell with eight places for fitting slide glasses on it (item number 13 in Figure 1). 2416

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placed there. Young’s equation is used in the apparatus software for measuring the contact angle.47

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RESULTS AND DISCUSSION Resin Effects on Asphaltene Deposition. The amount of deposited asphaltene is the most desired parameter for any asphaltene-related study.46 Because of errors associated with the slide glass removal from the HPHT cell, this parameter must be measured in situ, inside the visual cell. In this study, the visual HPHT cell was equipped with the tools needed to find the amount of deposited asphaltene, which has been explained elsewhere.45,46 Initially, the asphaltene deposition tests were carried out, without the presence of the resins. Two different synthetic oils containing asphaltene from two separate oil reservoirs were used for this experimental study. Table 1 shows the amount of

Figure 3. Deposited asphaltene of (a) Kuh-e-Mond and (b) Bangestan, at 363.15 K and different pressures.

clearly indicates that the potential of Kuh-e-Mond for asphaltene deposition is significantly higher than that of the Bangestan sample. Besides (see Table S3 of the Supporting Information), the average diameter of aggregates indicates that the AK sample aggregates more than the AB sample; therefore, the larger deposited particle area was formed. In the next stage, the effect of resin on asphaltene deposition of the two crude oil samples with two different potentials of deposition was investigated. It was already shown, in the previous sections, that one of these samples has higher potential for asphaltene deposition (Kuh-e-Mond) compared to the other sample (Bangestan). In the second part of the experiment, resin was added to the synthetic oil at the specific ratios to the asphaltene (resin/ asphaltene). Resin/asphaltene ratios were set at the values of 0.3, 1.5, and 3. The resin and asphaltene in the synthetic oil samples were extracted from the same crude oil samples. The results, which are presented in Tables S4 and S5 of the Supporting Information, show the area of asphaltene deposition for Kuh-e-Mond and Bangestan samples with three resin/ asphaltene ratios (0.3, 1.5, and 3.0). Also, Figure 4 shows the surface fraction of deposited asphaltene with the same ratios. The results indicate that the resin in the solution inhibits the asphaltene deposition; however, this behavior is not the same for both oil samples. The effect of the resin of Kuh-e-Mond

Table 1. Area of AK & AB Deposition at 363.15 K and Different Pressures without the Presence of Resin pressure (psia)

435.11

870.23

1450.38

2030.53

AK deposition area (μm2) AB deposition area (μm2)

1297134

1337256

1463291

1567192

241597

273824

304833

530270

asphaltene deposition area at a constant temperature as the pressure increases for the two different samples. Each asphaltene deposition area was calculated after 45 min. Table 1 shows that the amount of asphaltene deposition increases as the pressure increases. The surface fraction is defined as a fraction of the surface that is occupied by deposited asphaltene.48 As shown in Figure 2,

Figure 2. Comparison between Kuh-e-Mond surface fraction occupied by deposited asphaltene and that of Bangestan versus pressure at 363.15 K.

the asphaltene of the Kuh-e-Mond (AK) sample has more potential to be deposited than the asphaltene of the Bangestan (AB) sample. As Figure 2 shows, at most pressures, the surface fraction of AK is almost 5 times that of AB. Figure 3 shows the sample photographs that were taken from the slide glasses inside the visible HPHT cell, after 45 min. The dark particles are aggregated and deposited asphaltenes. These pictures indicate that the surface area of asphaltene deposition is increased as the pressure increases; also, the surface area of Kuh-e-Mond asphaltene deposition is more than that of the Bangestan sample. The average asphaltene deposition area of Kuh-e-Mond (heavier crude oil sample) was 1 416 218 μm2, which is 4 times greater than that of the Bangestan sample. It

Figure 4. Comparison between the Kuh-e-Mond surface fraction occupied by deposited asphaltene and that of Bangestan (with and without the presence of resin) versus pressure at 363.15 K. 2417

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model contains both asphaltene and resin, then the treated surfaces in this type of oil tend to be more water-wet. As Figure 5 shows, the droplet of water on the asphaltene surface has a wider angle in contact with immiscible fluid (air) than the asphaltene in the presence of the resin surface. These results then confirm the previous findings of inhibiting effects of the resins for asphaltene deposition. Therefore, in comparison to the aged slide glasses in the asphaltene, less asphaltene was deposited on the surfaces in the presence of resins, keeping the surfaces more water-wet. AFM Tests. The surfaces of the treated and fresh slide glasses were scanned using AFM, and the nanoscale topography images were studied carefully to find any surface property changes.45 Several different parameters, such as height distribution and roughness parameters, could be measured from the AFM images, on the basis of a specific area. To evaluate and compare the quality of the surfaces, several parameters have to be collected from the AFM images, such as Sz, Sa, Sq, Sds, and Sdr, according to eqs 1, 2, 3, 4, and 5, respectively. The summits and alleys are defined as the points that are higher than all eight neighboring points.52 Note that the points on the edge of the area are not considered.

(RK) on stabilizing AK is evident in all ratios, because the higher ratio of resin/asphaltene leads to more asphaltene stability and, hence, less deposition. The results show that, as the amount of resin increases from 0.3 to 1.5 and then to 3.0, the surface fraction was decreased significantly. On the other hand, resins of Bangestan (RB) do not show the same effect to decrease the asphaltene precipitation. As shown, at the resin/ asphaltene ratio (RB/AB = 0.3), asphaltene precipitation does occur the same as no resins being present. However the results indicate that the RB/AB ratio of 3.0 inhibits asphaltene deposition for the Bangestan sample at different pressures. Figure 4 shows that, for the resin/asphaltene ratios with more stabilized asphaltene conditions at low pressure (for example, RK/AK = 1.5 and 3.0), as the pressure increases, the stability of asphaltene decreases, and this is related to the theory of forming asphaltene and resin in a micelle form.5,26 Asphaltenes are disposed to self-associate and form micelles, and resins are known as peptizing agents that adsorb to these micelles, make a steric shell, and play the role of surfactants to stabilize the asphaltenes.35 The results show that the pressure changes have the same effect on both samples. For example, the highest deposition has occurred at 2030.53 psia. A notable effect of resins on the asphaltenes is to minimize the asphaltene aggregates compared to the cases without resins. The results obtained from the image processing software showed that the increase in the amount of resins leads to the smaller aggregates of asphaltenes, which is in agreement with the previous studies in this regard.39 Vapor pressure osmometry (VPO)48 and small-angle X-ray scattering36 measurements have been used in the past, where it was concluded that the presence of resins significantly decreased the size of asphaltene aggregates. These results have shown the anti-flocculant action of resins.49−51 Also, it must be noted that the effect of different resins from different sources (RB and RK) on the aggregate size reduction for asphaltenes are not the same. The results shown in Table S6 of the Supporting Information compared to Table S3 of the Supporting Information indicate that RK is more effective than RB to minimize the size of asphaltene aggregates. Surface Analysis. To investigate the changes in surface properties, the slide glasses were taken out of the cell after each test for wettability tests using contact angle measurement and performing AFM tests. To compare the surfaces, four aged slide glasses in AK, AB, RK, and RB were chosen for this investigation. The soaking period was 30 days, and the results of contact angle measurements are presented in Table 2. The results well indicate the effects of asphaltenes and resins in the oil on the wettability of the solid surfaces. Asphatenes could alter the surface to be more oil-wet, as already reported in many occasions. If the resins are the only heavy oil component, then the surfaces become even more oil-wet. However, if the oil

5

Sz = Sa =

Sq =

contact angle (deg) 83.6 93.7 70 70 73

contact angle (deg) aged AK aged RK RK/AK = 0.3 RK/AK = 1.5 RK/AK = 3

5

(1)

∫ ∫a |Z(x , y) dx dy|

(2)

∫ ∫a (Z(x , y)2 ) dx dy

(3)

Sds =

number of peaks area

(4)

Sdr =

(texture surface area) − (cross‐sectional area) cross‐sectional area

(5)

The AFM topography images with height images (on the basis of the path drawn) and the aforementioned parameters are presented in Figure 6, Table 3, and Figure S1 of the Supporting Information, respectively. The results show significant change in the topography of the surfaces after the slide glasses were aged in different oil models. The fresh slide glass has a smooth surface with a mean roughness (Sa) of 1.36 nm. Also, the parameter Sdr, which is called the developed interfacial area ratio, is close to zero (Sdr = 0.01), which indicates the smoothness of the fresh surfaces. As the results show, surface topography was changed after the slide glasses were treated with the oil; however, the changes are significant for the asphaltene deposition when no resin is present. From the AFM three-dimensional (3D) images, it is depicted that both asphaltene samples, AK and AB, have formed deep valleys and high summits. The path drawn in each 2D image shows the differences between topography of asphaltenes and resins. For example, the change of altitude in AB is from 100 to about 800 nm, while for the case of its native resin, RB, it is about 3−8 nm. The parameters Sa and Sdr for AB-treated surfaces are 119 nm and 20.5%, respectively. The same parameters in the case of RB are 2.12 nm and 0.05%. These quantitative results show that a smooth layer has been formed by the resins on the treated surfaces. Furthermore, comparing the AFM images for asphaltene and resin, it is seen that the asphaltene-deposited particles are clearly shown there,

Table 2. Contact Angle Data of the Aged Slide Glasses in Resin, Asphaltene, and Different Resin/Asphaltene Ratios

aged AB aged RB RB/AB = 0.3 RB/AB = 1.5 RB/AB = 3

5

∑1 |peak heights| + ∑1 |valley depths|

88 92 69 71 70 2418

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Figure 5. Comparison between wettability of surfaces of (a) asphaltene and (b) asphaltene in the presence of resin.

Figure 6. Three- and two-dimensional AFM images of asphaltene deposition on slide glasses: (a) fresh slide glass, (b) RB/AB = 1.5, and (c) RK/AK = 1.5.

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presence of resin in three ratios (Table S5), average diameter of asphaltene particles (Table S6), and 3D and 2D AFM images of asphaltene deposition on slide glasses (Figure S1). This material is available free of charge via the Internet at http:// pubs.acs.org.

Table 3. Calculated AFM Parameters for Different Samples substrates

Sz (nm)

Sa (nm)

Sdr (%)

Sq (nm)

Sds (μm−2)

fresh slide glass aged AB aged AK aged RB aged RK aged RB/AB = 1.5 aged RK/AK = 1.5

13.8 946 379 40.4 51.1 862 603

1.36 119 41.8 2.12 2.79 98.6 74.8

0.01 20.5 12.1 0.05 0.09 13.7 8.2

1.82 168 56.6 4.11 4.36 149 105

11 5.38 6.31 12 11.2 2.53 1.88

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AUTHOR INFORMATION

Corresponding Author

*Telephone/Fax: +98-21-66166411. E-mail: [email protected]. Present Address †

while the resin deposition is not evident. This is attributed to the tendency of asphaltenes to aggregate and form megascale asphaltene particles, as reported in the literature.5,6,10 Also, the high deposition potential of asphaltenes and their tendency to adhere to the surfaces compared to resins must be considered to evaluate this phenomenon. The asphaltenes and resins of the two different samples behave exclusively the same. The effects of added resins to their native asphaltenes were almost similar to each other. In both cases, the topography parameters presented in Table 3 show that the roughness of the surface is decreased when resins were added with resin/asphaltene of 1.5 compared to the aged slide glasses in the oil sample without the resins. For instance, the parameters Sa and Sdr for the solution of RB and AB with RB/ AB of 1.5 are 98.6 nm and 13.70%, which show more smooth surfaces than the case aged with AB. These quantitative results and examination of the images clearly indicate the effect of resins on the asphaltene deposition and, hence, the surface topography.

Now with Sharif University of Technology, Tehran, Iran.

Notes

The authors declare no competing financial interest.

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CONCLUSION In the present study, a HPHT PVT cell was used to investigate the asphaltene deposition behavior at the presence of resins with different ratios at reservoir temperature and relatively high pressures. To recognize the change of surface properties, the wettability measurement by contact angle and AFM techniques were used. The results show that, as the ratio of resin/ asphaltene increases, more stable asphaltene conditions are achieved. However, as the pressure increases, the asphaltene deposition increases significantly. It was found that the effect of resin on the stability of asphaltene is more evident in the oil sample with high potential of asphaltene deposition compared to the oil sample with low potential of deposition at the same resin/asphaltene ratios. The effect of resin on the stability of asphaltene decreases as the pressure increases, and this is more obvious at higher ratios of resin/asphaltene. Because different results were found for asphaltene inhibition in different oil samples when the resin is present, it is concluded that this phenomenon depends upon the asphaltene structures as well. Finally, the previous findings were confirmed by comparing the results to contact angle measurement and AFM analysis, which also suggested the significant effects of resins on asphaltene deposition and, hence, the surface property changes.

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ACKNOWLEDGMENTS

The authors express their special thanks of gratitude to Dr. Dehghani and Dr. Esmaeil Poor for their guidance on resin extraction. The authors are also grateful to Ali Tohidi for his efforts to build the HPHT visual asphaltene deposition apparatus.

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NOMENCLATURE PVT = pressure, volume, and temperature AFM = atomic force microscopy HPHT = high-pressure and high-temperature RB = resin of Bangestan RK = resin of Kuh-e-Mond AB = asphaltene of Bangestan AK = asphaltene of Kuh-e-Mond REFERENCES

(1) Aske, N.; Kallevik, H.; Sjöblom, 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 (5), 1304−1312. (2) Pelet, R.; Behar, F.; Monin, J. Resins and asphaltenes in the generation and migration of petroleum. Org. Geochem. 1986, 10 (1), 481−498. (3) Hua, Y.; Angle, C. W. Brewster angle microscopy of Langmuir films of Athabasca bitumens, n-C5 asphaltenes, and SAGD bitumen during pressure−area hysteresis. Langmuir 2012, 29 (1), 244−263. (4) McCain, W. The Properties of Petroleum Fluids; PennWell Books: Tulsa, OK, 1990. (5) Goual, L.; Firoozabadi, A. Effect of resins and DBSA on asphaltene precipitation from petroleum fluids. AIChE J. 2004, 50 (2), 470−479. (6) Merino-Garcia, D.; Andersen, S. I. Thermodynamic characterization of asphaltene−resin interaction by microcalorimetry. Langmuir 2004, 20 (11), 4559−4565. (7) Rogel, E. Asphaltene aggregation: A molecular thermodynamic approach. Langmuir 2002, 18 (5), 1928−1937. (8) Buenrostro-Gonzalez, E.; Groenzin, H.; Lira-Galeana, C.; Mullins, O. C. The overriding chemical principles that define asphaltenes. Energy Fuels 2001, 15 (4), 972−978. (9) Stachowiak, C.; Viguié, J.-R.; Grolier, J.-P. E.; Rogalski, M. Effect of n-alkanes on asphaltene structuring in petroleum oils. Langmuir 2005, 21 (11), 4824−4829. (10) Long, R. B. The concept of asphaltenes. Chem. Asphaltenes 1981, 195, 17−27. (11) Liu, D.; Li, Z.; Fu, Y.; Zhang, Y.; Gao, P.; Dai, C.; Zheng, K. Investigation on asphaltene structures during Venezuelan heavy oil hydrocracking under various hydrogen pressures. Energy Fuels 2013, 27 (7), 3692−3698.

ASSOCIATED CONTENT

S Supporting Information *

SARA tests (wt %) and API gravity (deg) of oils used in this work (Table S1), compositions (mol %) of the crude oils (Table S2), average diameter of AB and AK (Table S3), area of AB deposition at 363.15 K and different pressures with the presence of resin in three ratios (Table S4), area of AK deposition at 363.15 K and different pressures with the 2420

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dx.doi.org/10.1021/ef500020n | Energy Fuels 2014, 28, 2415−2421