Effects of Native and Non-Native Resins on ... - ACS Publications

Page 1 of 26

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

The effects of native and non-native resins on asphaltene deposition and the change of surface topography at different pressures; an experimental investigation † † ,‡ Farhad Soorghali, Ali Zolghadr, Shahab Ayatollahi* † Enhanced Oil Recovery (EOR) Research Centre, School of Chemical and Petroleum Engineering, Shiraz University, P.O. Box 7134851154, Shiraz, Iran

‡ Department of Chemical and Petroleum Engineering, Sharif University of Technology, Tehran, Iran Received: February 18, 2015- Revised: April 28, 2015- Revised: July 15, 2015

Abstract: Asphaltene deposition during oil production and transportation causes extensive damage to reservoirs and wellhead equipment. In this study, the effects of native and non-native resins as well as their mixtures on the asphaltene deposition process are investigated. A novel pressure, volume, and temperature (PVT) visual cell is used to check the effect of resin on asphaltene deposition at different pressures and reservoir temperatures. Two Iranian crude oil samples with different potential of asphaltene deposition (low and high) were used in these tests. During depressurizing in the presence of native and non-native resins, the amount of asphaltene deposited was measured. To monitor any changes in surface topography, the atomic force microscopy (AFM) technique was used in this study. The results show that the amount of asphaltene deposited decreases as the amount of resin increases; however, less asphaltene is deposited when the resin mixture is used than when the native resin is used. At high ratios of resin to asphaltene, the stability of asphaltene is higher, but as the pressure increases, the stability of the asphaltene decreases more than expected. The surface property changes indicate that, in the presence of the resin mixture, the surfaces are less affected. Keywords: Asphaltene deposition; Native and non-native resins; Pressure volume temperature (PVT); Atomic force microscopy (AFM); High-pressure high-temperature (HPHT); Enhanced Oil Recovery *Corresponding author. Tel./fax: +98 21 66166411. E-mail addresses: [email protected], [email protected], [email protected]

1

ACS Paragon Plus Environment

Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 2 of 26

1. Introduction A popular method for division of crude oil compounds is the fractionation of saturates, aromatics, resins, and asphaltenes (SARA). These crude oil components are graded in terms of their polarity: saturates contain nonpolar compounds, while the amount of polar compounds increases with the aromatics, the resins, and finally with the aphaltenes.1-3 Each of the SARA fractions consists of a large amount of molecules with different structures. Asphaltene, which consists of poly aromatic nuclei with aliphatic side chains and rings, does not dissolve in the paraffin group and has the highest molecular weight.4-6 It has been shown that some different acidic and functional groups are also present in asphaltene structure.7 Adding nonpolar materials to the crude oil, such as n-alkanes, can cause the asphaltenes to precipitate; thus, they can be extracted, and this extraction method has famed them as insoluble in n-pentane or n-heptane.8-10 During the past decade, researchers have shown that the addition of n-alkane to crude oil disturbs the equilibrium between the asphaltene aggregates and the crude oil, so these resins have an important role in the stability of this system.11-13 With the exception of polarity and molecular weight, there are few differences between asphaltene and resin. Asphaltenes consist of different acidic and functional groups, such sulphur-oxygen functions, carbonyl functions, ester functions, pyrrole (and indole) N-H functions, and hydrogen-bonded hydroxyl groups.5, 14-17 Although there is no principle chemical difference between asphaltenes and resins, their roles and behavior place them in two different categories. Of course, asphaltenes and resins are related to each other, and the interaction between these two important components has been extensively investigated by researchers.18-23 Association of resins with asphaltenes to form micelles is generally recognized as the main reason for the stabilization of crude oil.20,

24

In a micelle, the core is formed from the self-associating of

asphaltene into an aggregate, and resins are adsorbed onto the core to form a steric shell.25 In this stable system, the ratio of resins/asphaltenes is known to be an important indicator of asphaltene stability.26 This proposed mechanism is based on the theory that considers asphaltenes and resins as a colloidal system in petroleum fluids.27-30 On the other side, the solubility theory of asphaltenes has also gained attention.31,

32

The

formation damage in the reservoirs and plugging of transportation pipes which cause significant 2


Page 3 of 26

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

drops in pressure are the main concern for both petroleum and chemical engineers working in the oil industry.33,

34

It has been postulated that asphaltene deposition is due to changes in the

pressure, temperature, or composition of crude oil that may take place in the reservoir, surface production facilities, or transportation systems. Therefore, in some cases production blockage also occurs. In addition, during petroleum refining processes, asphaltenes are non-distillable and cause problems.35, 36 The impacts of the economic and technical problems caused by asphaltene precipitation and deposition on petroleum production operations are increasing, and many studies have been conducted in this area; however, there are still many issues to be resolved. The number of investigations of the effects of resins on asphaltene precipitation has increased gradually in the past decade. The fact that resins in crude oil act as stabilizing agents for asphaltenes is generally acknowledged.13, 37-40 Using gravimetric sedimentation analysis, Murzakov et al.41 showed that adding resins to an asphaltene−benzene solution reduces the amount of asphaltene precipitated by n-heptane. Lian et al.42 also reported the stabilizing effect of resins on asphaltenes in an asphaltene−toluene solution and mentioned n-pentane as an asphaltene-insoluble solvent. Hammami et al.43 measured the onset point of asphaltene precipitation at ambient temperature and high pressure (690kPa) and found that adding resins with high content of basic functions to the petroleum fluid resulted in a significant increase of the onset point using n-C5. Carnahan et al.26 reported that resins from Boscan petroleum fluid could increase considerably the onset point of asphaltene precipitation from Hamaca petroleum fluid and showed the incompetence of the assumption that resins from a specified crude oil are incompatible, in terms of asphaltene stabilization, with other crude oils. Other studies have elucidated the role of resins on the stabilizing of asphaltenes compared to amphiphiles. Al-Sahhaf et al.44 investigated the effect of resins and various amphiphiles on the onset point of asphaltene precipitation. They confirmed the observations of Chang and Fogler45, who reported the effectiveness of dodecyl resorcinol (DB) and DBSA amphiphiles. The same authors also reported that the stabilizing potential of low amphiphile (DBSA and DR) concentration is the same as that of a large amount of resins. Goual and Firoozabadi46 took a new approach to the effects of resins and DBSA on asphaltene precipitation. They found that the effect of various resins on asphaltene precipitation depends on the resin dipole moment (a 3


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 4 of 26

measure of polarity) and concluded that resins with high dipole moments are more effective than resins with low dipole moments. Questions still remain about the effects of native and non-native resins on asphaltene stability as well as the effects of pressure at constant temperature, mimicking the conditions of oil production at the asphaltenic oil reservoir. This study investigates the effects of mixed resins derived from various crude oils as stabilizing agents to inhibit the aggregation of asphaltenes in crude oil systems. To perform the tests at reservoir conditions, a special apparatus with a high pressure cell equipped with a highresolution microscope is used to visually monitor the deposition of asphaltene on glass substrates (as sandstone surfaces) in the presence of different resins at different pressures. To monitor any changes in the surface properties by the materials that adhere to the surface, microscopic views and AFM images of the contaminated surfaces were analyzed.

2. Experimental 2.1. Materials Different asphaltene and resin extraction methods have been proposed in the literature (e.g., ASTM D893-69, D2007-80, Modified D2007-80)47; however, all of them are based on the removal of asphaltenes by precipitation using a paraffinic solvent (n-heptane, IP 143/90)48 prior to chromatographic separation of the remaining crude oil on attapulgite clay and/or silica gel. In the current study, asphaltenes were extracted from two different Iranian crude oil samples (Crude oil K and Crude oil B) for which the structures and composition were reported elsewhere.5,

14

Excess n-heptane and with a ratio of 20:1 was used to asphaltene

extraction, and the Soxhlet method was applied to purify the asphaltene further. Resins

were

extracted

from

the

deasphalted

oil

by

means

of

column

chromatography.18, 47 The malten (deasphalted oil + n-heptane) 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 > 0.990) and toluene (Merck, mole fraction purity > 0.990). Finally, a mixture of acetone (Merck, mole fraction purity > 0.990), dichloromethane (Merck, mole fraction purity > 0.990), and 4


Page 5 of 26

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

toluene with the ratio of 40:30:30 was used to extract the resins from the column. The synthetic oil used in this study was made by mixing n-heptane and toluene (heptol). To mimic the sandstone rock in the reservoir, glass slides were utilized as the solid surface. The results of the SARA analysis and the composition of the crude oil samples are presented in Tables 1 and 2.49 Table 1. Table 2.

2.2. Experimental apparatus HPHT Visual Asphaltene Deposition Apparatus In this study, a new apparatus designed in Shiraz University’s EOR Research Centre was utilized to visually monitor and determine asphaltene deposition at different resin-toasphaltene ratios and different pressures at reservoir temperature. The schematic view of this apparatus is shown in Figure 1. This apparatus consists of a high-pressure cell that is filled by the oil sample. A rotating metal disk is placed horizontally inside the cell, which contains eight spots for fitting glass slides on it. Figure. 1 The images of precipitated asphaltenes that deposited on the glass slides were captured by a charge couple device (CCD) camera (IDS, UI-1485LE-C5 HQ, 5.7 megapixels) installed on the top of a microscope (Krüss, MBL2000) with an optical resolution up to 480x. A magnetic device from the outside of the cell rotated a 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. In this study, the captured images were analyzed with Sigma Scan Pro 5 software. To adjust the cell temperature, a heater was installed outside of the cell. To maintain the cell at the desired pressure, a high-pressure liquid chromatography (HPLC) pump (Agilent Technologies 1200 series) was used. The tests were carried out at a constant temperature of 363.15 K 5


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

and four different pressures: P1 = 435.11psia, P2 = 870.23psia, P3 = 1450.38psia, and P4 = 2030.53psia. The detailed description of the experimental apparatus is reported elsewhere.50, 51 The test conditions were intended to be close to those of the real reservoir; however, some of the parameters, such as the effects of shear in the porous rock and pressure changes because of the natural depletion of the reservoir fluid, have not been modeled using this apparatus. 2.3. Experimental procedure Synthetic oil (heptol) was used in this study to mimic crude oil containing all the SARA components. In the first stage, 0.40 g of asphaltene was dissolved in 275 mL of toluene, followed by stirring gently for 20 minutes, using a magnetic stirrer. Then, the desired amount of a resin was added to the solution and stirred for another 40 minutes. After one hour, 225 mL of n-heptane was added to the mixture, and the final solution was mixed again for one hour. The procedure used for preparing the synthetic oil was used for all the resin−asphaltene ratios. Each solution was injected into the cell and allowed to reach the desired temperature (363.15 K) using the heater around the main cell. The pressure of the cell was then increased to 2030.53 psia using the HPLC pump. The solution in the cell was held under these conditions for a certain period of time to allow for possible asphaltene deposition on the glass slides. During this process, high-resolution images were captured sequentially. Prior to final image analysis, the glass slides were removed gently and rinsed carefully with heptane to distinguish between settled and real deposition of asphaltene.50, 51 The pressure was then reduced to the second stage (1450.38 psia) at constant temperature (363.15 K). The solution was stirred to remove all the asphaltene particles deposited on the glass slides from the previous step. Then, the image capturing was continued, and the same procedure was repeated for the new pressures. The asphaltene-deposited area and particle size distribution were measured using Sigma Scan Pro 5 software. After each test, the glass slides were removed from the disk for AFM analysis. 3. Results and discussion 3.1. Mixed and simple native resins associated with asphaltenes. 6


Page 6 of 26

Page 7 of 26

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

To reduce the possible errors during the removal of the glass slides from the HPHT cell, the amount of deposited asphaltene, which is the most desired parameter for any asphaltene-related study, had to be measured in situ, inside the visual HPHT cell. To investigate the effects of different resins on asphaltene stability, in the first stage the asphaltene deposition tests were carried out without the presence of the resins. Then the tests were repeated for two different synthetic oils containing asphaltene from two separate oil reservoirs, with specific amounts of resins. Figure 2 shows the surface fraction occupied by the deposited asphaltene with and without the presence of their native resins at three resin/asphaltene ratios (R/A = 0.3, 1.5, and 3) and different pressures.49 The surface fraction was defined as a fraction of the surface that was occupied by deposited asphaltene. Each asphaltene deposition area was calculated after 45 minutes as the reference time period for all the tests. (See Figures S1, S2, and Tables S1, S2, and S3 in the Supporting Information.)

Figure. 2

Figure 2 shows that as the ratio of resin to asphaltene increased, the asphaltene deposition decreased for all the tests. It is obvious from comparing Figure 2a and Figure 2b that the asphaltene of crude oil K (AK) had more deposition potential than did the asphaltene of crude oil B (AB). The potential of deposition was defined as a fraction of the surface that was occupied by deposited asphaltene/ratio of n-heptane to toluene. The average asphaltene deposition area of crude oil K (the heavier crude oil sample) was 1416218 µm2, which was four times greater than the same for crude oil B. (The blank investigated surface area was 1,800,000 µm2.) Additionally, the average diameter of aggregates, as presented in Table 3, shows that the AK aggregated more than did the AB; therefore, the larger deposited particles were formed on the surface. Table 3. After the asphaltene deposition tests with no resin were performed, resins and asphaltenes were added to the synthetic oil at ratios of 0.3, 1.5, and 3 (R/A). In this part, 7


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

the resins and asphaltenes in the synthetic oil samples were from the same crude oil samples.49 Figure 2 indicates that the resins prohibited the asphaltene deposition process and stabilized asphaltene particles in the solutions; however, the effectiveness of their stabilizing performance was not the same for both resin samples. The effect of crude oil K’s resin (RK) on stabilizing crude oil K’s asphaltene (AK) was apparent in all ratios, as the higher ratio of resin to asphaltene led to more asphaltene stability and less deposition. On the other hand, the resins of crude oil B (RB) did not show the same effect of decreasing the asphaltene precipitation of crude oil B. As is shown, at RB/AB = 0.3, the extent of asphaltene precipitation was similar to that of the case in which no resins were used. However, the results indicated that an RB/AB ratio of 3.0 hindered asphaltene deposition for crude oil B at different pressures. To perform more analysis on the effects of resins on the stability of asphaltenes, a mixture of two resins was made and tested. The process was the same as that used for the previous tests; however, a mixture of equal amounts of two different resin samples was used. Figure 3 shows the surface fraction of deposited asphaltene in the presence of mixed resins with the different mixed-resins/asphaltene (MR/A) ratios of 0.3, 1.5, and 3. (Quantitative results are presented in Tables S4 and S5 of the Supporting Information.) As the results show, the mixed resins significantly stabilized the asphaltenes in the solution. For the AB solution, the presence of mixed resins resulted in the reduction of asphaltene deposition for all three ratios compared to the sample RB/AB in the ratios of 0.3 and 1.5. Also, in the AK solution, mixed resins prohibited asphaltene deposition; as the ratios increased, the deposition decreased. The average area of deposition for the 0.3, 1.5, and 3 ratios of mixed resins with AK was 7, 6, and 5 times less than that of the RK case, respectively. The deposition reduction for the mixed resins and AB sample compared to the RB/AB case was about 3 times in all ratios. This clearly shows that the mixed resins had more potential for stabilizing the asphaltenes compared to the individual resins from crude oil B and crude oil K.

Figure. 3

8


Page 8 of 26

Page 9 of 26

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

A notable effect of the resins on the asphaltenes was the minimization of the asphaltene aggregates compared to the cases without resins.39 With vapor pressure osmometry52 and small-angle X-ray scattering53 measurements, it was concluded that the presence of resins significantly decreased the size of asphaltene aggregates. These results show the anti-flocculent effect of resins.31, 38, 54 We found that mixed resins of RB and RK decreased the diameter of asphaltenes more than did the native resins. Tables 4 and 5 show that decreasing the aggregation process was more effective for the AK case, the sample with more deposition potential, than it was for the AB case. In this study, an asphaltenic crude oil sample (crude oil K) was selected. The observations showed that particle sizes increased as the pressure increased, as reported in the literature for at least two out of three types of crude oil samples57, showing that asphaltene particle size increases as pressure increases. This can be attributed to the type of fluid used in this study, synthetic dead oil, which did not involve the light hydrocarbon dissolution during the pressurizing process.

Table 4.

Table 5.

3.2. AFM (Atomic Force Microscopy) Tests To investigate the changes in surface properties, the glass slides were taken out of the cell after each AFM test. To compare the surfaces, four aged glass slides in AK, AB, RK, and RB were chosen for this investigation. The soaking period was 30 days. The surfaces of the treated and fresh glass slides were scanned using AFM, and the nano-scale topography images were studied carefully to find any surface property changes. Several different parameters, such as height distribution and roughness, 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 were collected, such as Sz, Sa, Sq, Sds, and Sdr, according to eqs 1, 2, 3, 4, and 5, respectively. The 9


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

summits and alleys were defined as the points that are higher than all eight neighboring points.55 Note that the points on the edge of the area were not considered. 1) Sz =

2) Sa =

3) Sq =

4) Sds =

5) Sdr =

The AFM topography images with height images (on the basis of the path drawn) and the aforementioned parameters are presented in Figure 4 and Table 6, respectively. The results show significant changes in the topography of the monitored surfaces after the glass slides were subjected to the asphaltene deposition process. A fresh glass slide had a smooth surface with a mean roughness (Sa) of 1.36 nm. Also, the parameter Sdr, which is the developed interfacial area ratio, was close to zero (Sdr = 0.01 %), indicating a very smooth, fresh surface.

Figure. 4

Table 6.

From the AFM 3D images, it is apparent that both the AK and AB asphaltene samples formed deep valleys and high summits. The path drawn in each 2D image shows the 10


Page 10 of 26

Page 11 of 26

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

differences between the topography of asphaltenes and resins. For example, the change of altitude in AB was from 100 to about 800 nm, but for its native resin, RB, it was about 3−8 nm. The parameters Sa and Sdr for AB were 119 nm and 20.5%, respectively. The same parameters for RB were 2.12 nm and 0.05 %. With these quantitative results, it could be concluded that the resins formed a smooth layer on the surfaces. Furthermore, based on a comparison of the AFM images for asphaltene and resin, asphaltene particle deposition was evident, while resin deposition was not. This might be due to the tendency of asphaltenes to aggregate and form asphaltene particles, as reported in the literature.40, 46, 56

Moreover, the high deposition potential of asphaltenes and their tendency to adhere

to the surfaces compared to resins must be considered to evaluate this phenomenon. (See also Figure S2 of the Supporting Information for more AFM images.) As in the simple mode, the two asphaltene and resin samples behaved the same, and the effects of adding mixed resins to asphaltenes were similar to each other. In both cases, adding mixed resins in the ratio of 1.5 caused the surface to be smoother than the cases in which only asphaltenes deposited on the surfaces. For instance, from the topography parameters presented in Table 6, the parameters Sa and Sdr for the solution of mixed RB and RK in the ratio of 1.5 to AB were 5.28 nm and 1.56%, respectively, which show much smoother surfaces than in the case of AB deposition on glass slides. Also, it is evident that in the mixed resin cases, a smoother surface than the simple native resin cases was created. In the simple mode, the glass slides from the RB/AB solution were rougher than those from the RK/AK solution; however, in the mixed mode, this difference could not be seen. These quantitative results and examination of the images clearly indicate the effect of resins on asphaltene deposition and hence surface topography. 4. Conclusion In the present study, the deposition behaviour of asphaltenes in association with mixtures of non-native and native resins with different ratios at reservoir temperature and various pressures was analyzed by the use of a novel HPHT PVT cell. AFM was used to recognize the change of surface properties due to asphaltene−resin deposition of different types and ratios.

11


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 12 of 26

In conclusion, we have shown that the stability of asphaltenes is closely related to the amount and the type of resins. As the ratio of mixed resins to asphaltene (MR/A) increased, more stable asphaltene conditions were achieved. It was also found that the stabilizing role of the mixture of resins was more effective than that of native resins. Results showed that the effect of RB on decreasing asphaltene deposition in the small ratios (0.3 and 1.5) was negligible, while the small amounts of RB in mixtures with RK in the mentioned ratios caused a considerable reduction of asphaltene deposition. This phenomenon can be attributed to molecular interactions between the two types of resins between the resins and the asphaltenes. Analyzing these molecular interactions with clarification of the chemical nature of resins and asphaltenes will provide beneficial clues to resin/asphaltene behavior. In a synthetic oil sample that contained asphaltene with high potential of deposition (AK), the mixed resins played a significant role in decreasing the amount of asphaltene deposition. The results also indicated the positive effect of pressure on the growth of asphaltene deposition both with and without the presence of resins. Since different effects were noticed for various types of resins on asphaltene deposition in different samples, it was found that the effects of different resins on decreasing the size of asphaltene aggregates were not the same. Finally, the decrease in the roughness of surfaces was greater in the presence of resins than it was in the cases without resins. Acknowledgements Help from Dr. Dehghani and Dr. Esmaeil-Poor for their guidance on resins extraction is greatly acknowledged. We are also grateful to Ali Tohidi for his efforts to build the HPHT Visual Asphaltene Deposition Apparatus. ABBREVIATIONS PVT, pressure volume temperature; AFM, atomic force microscopy; HPHT, highpressure high-temperature; RB, resin of Crude oil B; RK, resin of Crude oil K; MR, Mixed of resin of Crude oil B and Crude oil K, AB, asphaltene of Crude oil B; AK, asphaltene of Crude oil K.

12


Page 13 of 26

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

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. Sadeghi, K. M.; Sadeghi, M.-A.; Wu, W. H.; Yen, T. F., Fractionation of various heavy oils and bitumen for characterization based on polarity. Fuel 1989, 68, (6), 782-787. 3. Rodgers, R. P.; McKenna, A. M., Petroleum analysis. Analytical chemistry 2011, 83, (12), 46654687. 4. Hashmi, S. M.; Zhong, K. X.; Firoozabadi, A., Acid–base chemistry enables reversible colloid-tosolution transition of asphaltenes in non-polar systems. Soft Matter 2012, 8, (33), 8778-8785. 5. Amin, J. S.; Nikooee, E.; Ghatee, M.; Ayatollahi, S.; Alamdari, A.; Sedghamiz, T., Investigating the effect of different asphaltene structures on surface topography and wettability alteration. Applied Surface Science 2011, 257, (20), 8341-8349. 6. Merino-Garcia, D.; Andersen, S. I., Thermodynamic characterization of asphaltene-resin interaction by microcalorimetry. Langmuir 2004, 20, (11), 4559-4565. 7. Speight, J. G., The chemical and physical structure of petroleum: effects on recovery operations. Journal of Petroleum Science and Engineering 1999, 22, (1), 3-15. 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. 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 pressure. Energy & Fuels 2013. 10. Long, R. B., The concept of asphaltenes. Chemistry of Asphaltenes 1981, 195, 17-27. 11. Khadim, M. A.; Sarbar, M. A., Role of asphaltene and resin in oil field emulsions. Journal of Petroleum Science and Engineering 1999, 23, (3), 213-221. 12. Schorling, P.-C.; Kessel, D.; Rahimian, I., Influence of the crude oil resin/asphaltene ratio on the stability of oil/water emulsions. Colloids and Surfaces A: Physicochemical and Engineering Aspects 1999, 152, (1), 95-102. 13. Ali, M.; Alqam, M., The role of asphaltenes, resins and other solids in the stabilization of water in oil emulsions and its effects on oil production in Saudi oil fields. Fuel 2000, 79, (11), 1309-1316. 14. Ghatee, M. H.; Hemmateenejad, B.; Sedghamiz, T.; Khosousi, T.; Ayatollahi, S.; Seiedi, O.; Sayyad Amin, J., Multivariate curve resolution alternating least-squares as a tool for analyzing crude oil extracted asphaltene samples. Energy & Fuels 2012, 26, (9), 5663-5671. 15. Fergoug, T.; Bouhadda, Y., Determination of Hassi Messaoud asphaltene aromatic structure from 1H & 13C NMR analysis. Fuel 2014, 115, 521-526. 16. Strausz, O. P.; Mojelsky, T. W.; Lown, E. M., The molecular structure of asphaltene: an unfolding story. Fuel 1992, 71, (12), 1355-1363. 17. Mullins, O. C.; Sabbah, H.; Eyssautier, J. l.; Pomerantz, A. E.; Barré, L.; Andrews, A. B.; RuizMorales, Y.; Mostowfi, F.; McFarlane, R.; Goual, L., Advances in asphaltene science and the Yen– Mullins model. Energy & Fuels 2012, 26, (7), 3986-4003. 18. McLean, J. D.; Kilpatrick, P. K., Effects of asphaltene aggregation in model heptane–toluene mixtures on stability of water-in-oil emulsions. Journal of Colloid and Interface Science 1997, 196, (1), 23-34. 19. Pelet, R.; Behar, F.; Monin, J., Resins and asphaltenes in the generation and migration of petroleum. Organic Geochemistry 1986, 10, (1), 481-498.

13


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

20. Hoepfner, M. P.; Vilas Bôas Fávero, C.; Haji-Akbari, N.; Fogler, H. S., The Fractal Aggregation of Asphaltenes. Langmuir 2013. 21. Acevedo, S.; Ranaudo, M. A.; Escobar, G.; Gutiérrez, L.; Ortega, P., Adsorption of asphaltenes and resins on organic and inorganic substrates and their correlation with precipitation problems in production well tubing. Fuel 1995, 74, (4), 595-598. 22. Midttun, Ø.; Kvalheim, O., Interactions in chromatographic separation of resins from deasphaltened crude oils studied by means of infrared spectroscopy and principal component analysis. Fuel 2001, 80, (5), 717-730. 23. Sedghi, M.; Goual, L., Role of Resins on Asphaltene Stability†. Energy & Fuels 2009, 24, (4), 2275-2280. 24. Pereira, J. C.; López, I.; Salas, R.; Silva, F.; Fernández, C.; Urbina, C.; López, J. C., Resins: The molecules responsible for the stability/instability phenomena of asphaltenes. Energy & fuels 2007, 21, (3), 1317-1321. 25. Firoozabadi, A., Thermodynamics of Hydrocarbon Reservoirs, 1999. In McGraw-Hill, New York. 26. Carnahan, N. F.; Salager, J.-L.; Antón, R.; Dávila, A., Properties of resins extracted from Boscan crude oil and their effect on the stability of asphaltenes in Boscan and Hamaca crude oils. Energy & Fuels 1999, 13, (2), 309-314. 27. Yen, T. F.; Erdman, J. G.; Pollack, S. S., Investigation of the structure of petroleum asphaltenes by X-ray diffraction. Analytical Chemistry 1961, 33, (11), 1587-1594. 28. Ignasiak, T.; Kemp-Jones, A.; Strausz, O., The molecular structure of Athabasca asphaltene. Cleavage of the carbon-sulfur bonds by radical ion electron transfer reactions. The Journal of Organic Chemistry 1977, 42, (2), 312-320. 29. Speight, J. G.; Moschopedis, S. E., Some observations on the molecular nature of petroleum asphaltenes. Am. Chem. Soc., Div. Pet. Chem., Prepr.;(United States) 1979, 24, (CONF-790917-(Vol. 24)(No. 4)). 30. Hammami, A.; Phelps, C. H.; Monger-McClure, T.; Little, T., Asphaltene precipitation from live oils: An experimental investigation of onset conditions and reversibility. Energy & Fuels 2000, 14, (1), 14-18. 31. Espinat, D.; Ravey, J. In Colloidal structure of asphaltene solutions and heavy-oil fractions studied by small-angle neutron and X-ray scattering, SPE International Symposium on Oilfield Chemistry, 1993; Society of Petroleum Engineers: 1993. 32. Yen, T.; Burger, J., Advances in Chemistry, Series 195. Chemistry of Asphaltenes, Am. Chem. Soc, Washington 1979, 39-52. 33. Mansoori, G. A., Asphaltene deposition: An economic challenge in heavy petroleum crude utilization and processing. opeC Review 1988, 12, (1), 103-113. 34. Escobedo, J.; Mansoori, G. A. In Asphaltene and other heavy-organic particle deposition during transfer and production operations, SPE Annual Technical Conference and Exhibition, 1995; Society of Petroleum Engineers: 1995. 35. Fahim, M. A.; Al-Sahhaf, T. A.; Elkilani, A., Fundamentals of petroleum refining. Elsevier: 2009. 36. Becker, J., Crude oil waxes, emulsions, and asphaltenes. Pennwell Books: 1997. 37. Xia, L.; Lu, S.; Cao, G., Stability and demulsification of emulsions stabilized by asphaltenes or resins. Journal of colloid and interface science 2004, 271, (2), 504-506. 38. Spiecker, P. M.; Gawrys, K. L.; Trail, C. B.; Kilpatrick, P. K., Effects of petroleum resins on asphaltene aggregation and water-in-oil emulsion formation. Colloids and surfaces A: Physicochemical and engineering aspects 2003, 220, (1), 9-27. 39. León, O.; Contreras, E.; Rogel, E.; Dambakli, G.; Acevedo, S.; Carbognani, L.; Espidel, J., Adsorption of native resins on asphaltene particles: a correlation between adsorption and activity. Langmuir 2002, 18, (13), 5106-5112.

14


Page 14 of 26

Page 15 of 26

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

40. Merino-Garcia, D.; Andersen, S. I., Thermodynamic characterization of asphaltene-resin interaction by microcalorimetry. Langmuir 2004, 20, (11), 4559-4565. 41. Murzakov, R.; Sabanenkov, S.; Syunyaev, Z., Influence of petroleum resins on colloidal stability of asphaltene-containing disperse systems. Chemistry and Technology of Fuels and Oils 1980, 16, (10), 674-677. 42. Lian, H.; Lin, J.-R.; Yen, T. F., Peptization studies of asphaltene and solubility parameter spectra. Fuel 1994, 73, (3), 423-428. 43. HAMMAMI, A.; FERWORN, K. A.; NIGHSWANDER, J. A.; OVER˚, S.; STANGE, E., Asphaltenic crude oil characterization: An experimental investigation of the effect of resins on the stability of asphaltenes. Petroleum science and technology 1998, 16, (3-4), 227-249. 44. Al-Sahhaf, T. A.; Fahim, M. A.; Elkilani, A. S.,. Fluid phase equilibria 2002, 194, 1045-1057. 45. Chang, C.-L.; Fogler, H. S., Stabilization of asphaltenes in aliphatic solvents using alkylbenzenederived amphiphiles. 1. Effect of the chemical structure of amphiphiles on asphaltene stabilization. Langmuir 1994, 10, (6), 1749-1757. 46. Goual, L.; Firoozabadi, A., Effect of resins and DBSA on asphaltene precipitation from petroleum fluids. AIChE journal 2004, 50, (2), 470-479. 47. Miller, R., Hydrocarbon class fractionation with bonded-phase liquid chromatography. Analytical Chemistry 1982, 54, (11), 1742-1746. 48. Klein, G. C.; Kim, S.; Rodgers, R. P.; Marshall, A. G.; Yen, A.; Asomaning, S., Mass spectral analysis of asphaltenes. I. Compositional differences between pressure-drop and solvent-drop asphaltenes determined by electrospray ionization Fourier transform ion cyclotron resonance mass spectrometry. Energy & fuels 2006, 20, (5), 1965-1972. 49. Soorghali, F.; Zolghadr, A.; Ayatollahi, S., Effect of Resins on Asphaltene Deposition and the Changes of Surface Properties at Different Pressures: A Microstructure Study. Energy & Fuels 2014, 28, (4), 2415-2421. 50. Sayyad Amin, J.; Alamdari, A.; Mehranbod, N.; Ayatollahi, S.; Nikooee, E., Prediction of asphaltene precipitation: Learning from data at different conditions. Energy & Fuels 2010, 24, (7), 40464053. 51. Zanganeh, P.; Ayatollahi, S.; Alamdari, A.; Zolghadr, A.; Dashti, H.; Kord, S., Asphaltene deposition during CO2 injection and pressure depletion: A visual study. Energy & Fuels 2012, 26, (2), 1412-1419. 52. Yarranton, H. W.; Alboudwarej, H.; Jakher, R., Investigation of asphaltene association with vapor pressure osmometry and interfacial tension measurements. Industrial & engineering chemistry research 2000, 39, (8), 2916-2924. 53. Bardon, C.; Barre, L.; Espinat, D.; Guille, V.; Li, M. H.; Lambard, J.; Ravey, J.; Rosenberg, E.; Zemb, T., The colloidal structure of crude oils and suspensions of asphaltenes and resins. Fuel Science and Technology International 1996, 14, (1-2), 203-242. 54. Barre, L.; Espinat, D.; Rosenberg, E.; Scarsella, M., Colloidal structure of heavy crudes and asphaltene soltutions. Oil & Gas Science and Technology 1997, 52, (2), 161-175. 55. Seiedi, O.; Rahbar, M.; Nabipour, M.; Emadi, M. A.; Ghatee, M. H.; Ayatollahi, S., Atomic force microscopy (AFM) investigation on the surfactant wettability alteration mechanism of aged mica mineral surfaces. Energy & Fuels 2010, 25, (1), 183-188. 56. Long, R.; Bunger, J.; Li, N., Chemistry of asphaltenes. Advances in Chemistry Series 1981, 195, 17-27. 57. Nielsen, B. B.; Svrcek, W. Y.; Mehrotra, A. K., Effects of temperature and pressure on asphaltene particle size distributions in crude oils diluted with n-pentane. Industrial & engineering chemistry research 1994, 33, (5), 1324-1330.

15


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 16 of 26

Figure captions:

Figure 1. [50] 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. Figure 2. Comparison between crude oil surface fractions occupied by deposited asphaltene in presence of native resins with no resin cases, versus different resin/asphaltene (R/A) ratios, at different pressures and constant temperature (T = 363.15 K): a) crude oil K sample, b) crude oil B sample. Figure 3. Comparison between crude oil surface fractions occupied by deposited asphaltene in presence of mixed resins with no resin cases versus different mixedresins/asphaltene (MR/A) ratios, at different pressures and constant temperature (T = 363.15 K): a) crude oil K sample, b) crude oil B sample. Figure 4. 3D and 2D AFM images of asphaltene deposition on slide glasses: (a) aged AB, (b) RB/AB = 1.5, (c) MR/AB = 1.5.

Table titles:

Table 1. SARA tests (% wt.) and API° of oils used in this work. Table 2. Compositions (mol. %) of the crude oils. Table 3. The average diameter of asphaltene particles of crude oil B (AB) and crude oil K (AK). Table 4. The average diameter of asphaltene particles in the presence of mixed resins. Table 5. The average diameter of asphaltene particles in presence of native resins. Table 6. AFM parameters at different samples. 16


Page 17 of 26

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

Figure 1. [50] 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.

17


Energy & Fuels

a)

Deposited asphaltene in presence of native resins, AK

1 0.9

p=435.11 psia

0.8

p=870.23 psia

0.7

p=1450.38 psia

0.6

p=2030.53 psia

0.5 0.4 0.3 0.2 0.1 0 0

0.3 RK/AK Ratio

1.5

3

b) 0.35

p=435.11 psia Deposited asphaltene in presence of native resins, AB

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 18 of 26

0.3

p=870.23 psia 0.25

p=1450.38 psia 0.2

p=2030.53 psia 0.15 0.1 0.05 0 0

0.3

1.5 RB/AB Ratio

3

Figure 2. Comparison between crude oil surface fractions occupied by deposited asphaltene in presence of native resins with no resin cases, versus different resin/asphaltene (R/A) ratios, at different pressures and constant temperature (T = 363.15 K): a) crude oil K sample, b) crude oil B sample.

18


Page 19 of 26

a) 1 Deposited asphaltene in presence of mixed resins, AK

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

0.9

p=435.11 psia

0.8 0.7

p=870.23 psia

0.6

p=1450.38 psia

0.5 0.4

p=2030.53 psia

0.3 0.2 0.1 0 0

0.3

1.5

3

MR/AK Ratio

b)

Figure 3. Comparison between crude oil surface fractions occupied by deposited asphaltene in presence of mixed resins with no resin cases versus different mixedresins/asphaltene (MR/A) ratios, at different pressures and constant temperature (T = 363.15 K): a) crude oil K sample, b) crude oil B sample.

19


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

a)

b)

c)

Figure 4. 3D and 2D AFM images of asphaltene deposition on slide glasses: (a) aged AB, (b) RB/AB = 1.5, (c) MR/AB = 1.5.

20


Page 20 of 26

Page 21 of 26

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

Table 1. SARA tests (% wt.) and API° of oils used in this work.

Test name Saturates (wt %) Aromatics (wt %) Resins (wt %) Asphaltene (wt %) APIº

Crude oil K

Crude oil B

12.8 21.83 53.39 14.7 12.8

30.1 42.1 13.36 13.75 20.2

21


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 22 of 26

Table 2. Compositions (mol. %) of the crude oils.

Components

Crude oil K(mol%)

H2S

Crude oil B(mol%)

0

0

N2

0.66

0

CO2

0.23

0

C1

10.35

0

C2

2.35

0.2

C3

1.95

0.3

iC4

1.62

0.2

nC4

4

0.9

iC5

3.6

0.8

nC5

2.28

1.3

C6

2.74

9.4

C7

2.15

6.7

C8

2.42

7.5

C9

2.15

5.5

C10

3.13

5.4

C11

2.52

5

C12+

57.86

56.8

Other Properties C12+ mol wt (g/mol)

333

C12 + sp gr at 288 K

0.964

22


418 0.976

Page 23 of 26

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

Table 3. The average diameter of asphaltene particles of crude oil B (AB) and crude oil K (AK). Average diameter of particles (µm)

AB

12.6

AK

20.9

23


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 24 of 26

Table 4. The average diameter of asphaltene particles in the presence of mixed resins.

Average MR/AB

Average

diameter

MR/AK

diameter

(µm)

(µm)

0.3

9.5

0.3

11.2

1.5

8.8

1.5

9.3

3.0

7.9

3.0

8.6

24


Page 25 of 26

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

Table 5. The average diameter of asphaltene particles in presence of native resins.

Average RB/AB

Average

diameter

RK/AK

(µm)

diameter (µm)

0.3

11.5

0.3

12.5

1.5

10.3

1.5

10.9

3.0

9.9

3.0

10.3

25


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 26 of 26

Table 6. AFM parameters at different samples.

Substrates

Sz (nm)

Sa (nm)

Sdr (%)

Sq (nm)

Sds (µm-2)

Fresh slide glass

13.8

1.36

0.01

1.82

11

Aged AB

946

119

20.5

168

5.38

Aged AK

379

41.8

12.1

56.6

6.31

Aged RB

40.4

2.12

0.05

4.11

12

Aged RK

51.1

2.79

0.09

4.36

11.2

862

98.6

13.7

149

2.53

603

74.8

8.2

105

1.88

77.2

5.28

1.56

7.28

17.6

135

6.49

1.64

11.2

14.8

Aged (RB/AB) =1.5 Aged (RK/AK) =1.5 Aged (MR/AB) =1.5 Aged (MR/AK) =1.5

26


Effects of Native and Non-Native Resins on ... - ACS Publications

Recommend Documents