Subscriber access provided by UNIVERSITY OF ADELAIDE LIBRARIES
Fossil Fuels
Effect of Asphaltenes Characteristics on its Solubility and Overall Stability Andreas Prakoso, Abhishek Punase, Estrella Rogel, Cesar Ovalles, and Berna - Hascakir Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.8b00324 • Publication Date (Web): 10 May 2018 Downloaded from http://pubs.acs.org on May 15, 2018
Just Accepted “Just Accepted” manuscripts have been peer-reviewed and accepted for publication. They are posted online prior to technical editing, formatting for publication and author proofing. The American Chemical Society provides “Just Accepted” as a service to the research community to expedite the dissemination of scientific material as soon as possible after acceptance. “Just Accepted” manuscripts appear in full in PDF format accompanied by an HTML abstract. “Just Accepted” manuscripts have been fully peer reviewed, but should not be considered the official version of record. They are citable by the Digital Object Identifier (DOI®). “Just Accepted” is an optional service offered to authors. Therefore, the “Just Accepted” Web site may not include all articles that will be published in the journal. After a manuscript is technically edited and formatted, it will be removed from the “Just Accepted” Web site and published as an ASAP article. Note that technical editing may introduce minor changes to the manuscript text and/or graphics which could affect content, and all legal disclaimers and ethical guidelines that apply to the journal pertain. ACS cannot be held responsible for errors or consequences arising from the use of information contained in these “Just Accepted” manuscripts.
is published by the American Chemical Society. 1155 Sixteenth Street N.W., Washington, DC 20036 Published by American Chemical Society. Copyright © American Chemical Society. However, no copyright claim is made to original U.S. Government works, or works produced by employees of any Commonwealth realm Crown government in the course of their duties.
Page 1 of 13 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
Effect of Asphaltenes Characteristics on its Solubility and Overall Stability Andreas Prakoso*, Abhishek Punase*, Estrella Rogel†, Cesar Ovalles†, Berna Hascakir*, *Texas A&M University †
Chevron Energy and Technology Center
1. Abstract Complex molecular structure, high impurity content, and self-association tendency of asphaltenes makes the determination of its phase behavior very difficult. Since, asphaltenes phase behavior is indicative of asphaltenes stability within the bulk oil, it is very important to understand its stability. Various production and flow assurance challenges related to precipitation of unstable asphaltenes can be prevented by proper comprehension of asphaltenes stability. This study provides a data set on 11 different asphaltenes which helps us to understand the complicated nature of the components of asphaltenes and crude oils which play an important role in maintaining the stability of asphaltenes. In addition to the physical and chemical characterization, elemental analysis and ΔPS parameter which is the indication of the solubility of asphaltenes in different solvents of the bulk oil samples were measured and evaluated. The results of this study show that the presence of paraffinic wax and water within the crude oil samples along with impurities in the form of reservoir fines can greatly affect the stability of asphaltenes. The organometallic content of crude oil destabilizes asphaltenes, whereas high fines content increases the stability of asphaltenes. 2. Introduction Asphaltenes are complex hydrocarbon molecules with high heteroatom content [1]. The change in pressure and temperature conditions of the reservoir may result in asphaltenes precipitation which might plug the reservoir pores and/or production and transportation pipelines [1]. The changes in oil composition due to the interaction with the injected Enhanced Oil Recovery (EOR) fluids may also trigger the asphaltenes flocculation. Precipitation of asphaltenes may also be induced by the presence of clays in the reservoir rock [2, 3]. Additionally, reservoir salinity may also have an influence on asphaltenes stability, as asphaltenes aggregation tendencies may depend on the type of ions in the reservoir brine and asphaltenes [4]. The contribution of all reservoir components on asphaltenes stability is complicated and can be determined through dielectric constant measurements [5], dipole moment estimations [6], zeta potential measurements [7], onset asphaltene precipitation tests [8], refractive index 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 13
measurements [9], and solubility profile analysis [10]. Each method follows different procedure by targeting the estimation of different behaviors of asphaltenes in bulk oil, however, tests are conducted in general by using different solvents (i.e., n-heptane) or water. While there are several debates on the asphaltenes molecular structures and their presence within crude oils, these authors believe that all factors (polarity, solvent power, and electrical charges within the crude oil) contribute to determine the asphaltenes stability. However, it is also possible that only one factor might dominate the overall stability of asphaltenes. The non-hydrocarbon components (sulfur, nitrogen, oxygen, and metals) of asphaltenes and their molecular bonding state has been determined as the dominating factor [1]. Hence, it is important to first ascertain the non-hydrocarbon components through elemental analysis of asphaltenes to develop a better understanding towards the stability of asphaltenes [11, 12]. Hydrogen and carbon content along with the Hydrogen to Carbon (H/C) ratio determines the aliphatic/aromatic nature of the crude oil molecules [13]. Still, it should be noted that even hydrogen and carbon may have both organic (hydrocarbons) and inorganic origins (i.e.; bicarbonate and carbonate). Hence, not only the elemental but also the molecular level characterization is necessary. However, due to complex nature of the crude oils and asphaltenes, the characterization of the individual molecular structures is not practical [14, 15]. Still, some fractionation methods can be implemented. Saturates, Aromatics, Resins, and Asphaltenes (SARA) fractionation is a widely used fractionation method for this purpose [16]. SARA fractionation groups the similar chemical structures within the crude oil according to their solubility in different solvents. Since asphaltenes are soluble in aromatic hydrocarbons and insoluble in normal alkanes, it is expected that while aromatics fraction of crude oil stabilizes the asphaltenes, saturates fraction of crude oils will disturb asphaltenes stability [7, 17]. However, since the solubility parameter of saturates and aromatics fractions are not known, their impact on the overall stability of asphaltenes remains unclear. This study investigates the effect of characteristics on asphaltenes solubility and stability. Simple correlations are developed to understand the impact of the elemental composition of crude oil as well as the interaction of asphaltenes with other crude oil fractions and reservoir fines on asphaltenes behavior. 3. Experimental Procedure 11 different crude oil and bitumen samples from Canada, Colombia, Indonesia, Mexico, USA, and Venezuela were first characterized with their viscosity; API gravity; the amount of Saturates, Aromatics, Resins, and Asphaltenes (SARA) fractions; and carbon, hydrogen, nitrogen (CHN), and metal contents. 2 ACS Paragon Plus Environment
Page 3 of 13 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
Brookfield DV-III Ultra rheometer was used to measuring the viscosity of the samples at ambient temperature (22.3 °C). The density values were measured at standard conditions using Anton Paar DMA 4100 Density Meter. The ASTM D2007-11 [18] method (using n-pentane) was followed to determine SARA fractions of each crude oil sample based on their adsorption affinity towards the attapulgus clay and silica gel. Standard combustion method, using a Leco CHN analyzer Carlo Erba model was used to estimate the carbon, hydrogen, and nitrogen content in the test sample. The metal content of samples was determined by Thermo Intrepid Inductively Coupled Plasma (ICP). Evaluation of the asphaltenes stability within the crude oil is challenging. One method which provides reasonable estimation of the asphaltenes stability is the solubility profile of crude oils [10]. The solubility profile of asphaltenes measures the solubility distribution of asphaltenes molecules and relates their solubility properties towards their tendencies to precipitate. The asphaltene solubility profile method consists of precipitating the asphaltenes in a Teflon containing column using n-heptane and then gradually and continuously modifying the solvent mobile phase, so that the asphaltenes eluted from the column at each time are related to the solvent power of the mobile phase (n-heptane, 90:10 methylene chloride/methanol mixture, and 100% methanol). In this way, it is possible to produce a response that can be associated with the solubility distribution of asphaltenes. Hence the name of asphaltene solubility profile. It is crucial to point out the no chromatographic separation is taking place. The method is just on-column precipitation and redissolution of the asphaltenes [10]. Detection and quantification of the eluent are conducted by using Alltech Evaporative Light Scattering Detector (ELSD) 2000 detector and HP series 1100 High-Performance Liquid Chromatography (HPLC) chromatograph. The solubility profiles were analyzed to obtain a ΔPS parameter, which represents the time taken for the elution of the middle 50% area (between 25% and 75%) distribution of the solubility profile. Higher ∆PS parameter value indicates higher instability of asphaltenes [10]. In fact, because the solubility parameter of a mixture is given by the volumetric average of the components, it is possible to convert the time scale to a solubility parameter scale (in MPa0.5) as described elsewhere [10]. Fig. 1 is provided as an example to describe the interpretation of solubility profiles and calculation of the ΔPS parameters for samples C2, C3, C6, and C5.
3 ACS Paragon Plus Environment
Energy & Fuels
0.040
Normalized Response, dimensionless
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 13
C2 C3 C5 C6
0.035 0.030 0.025 0.020 0.015 0.010 0.005 0.000 13
14
15
16
17
18
19
Time, minutes
Fig. 1. Asphaltenes solubility profile comparison for samples C2, C3, C6, and C5. As the distribution extends further to the right (higher solubility parameter solvent), the sample is expected to contain higher solubility parameter asphaltene molecules. Thus, two distinct types of distribution can be observed; unimodal (one peak in the graph) and bimodal (two peaks in the graph) distribution. Unimodal distribution denotes similar solubility behavior for the all of the components within the sample. On the other hand, bimodal distribution means that there are two different groups of molecules which are insoluble within one another. In Fig. 1, samples C2 and C6 display unimodal distribution with sample C2 having a small shoulder, whereas sample C3 and C5 show bimodal distribution. Solubility profile of sample C3 shows the clearest separation within the two peaks. . In general, stability problems in crude oils and related materials can be attributed to the immiscibility of the molecules that compose those materials. Two substances with solubility parameters different enough so that they are immiscible can be mutually solubilized by the addition of a third component, whose solubility parameter lies between the solubility parameters of the two substances [10]. Thus, it is possible to suppose that there are two main causes of instability on the petroleum materials: (1) the presence of molecules with a high solubility parameter and (2) the absence of molecules to act as an intermediate material between high solubility parameter asphaltenes and the dispersion medium. The bimodal distribution indicates a lower stability because it shows a gap in the solubility distribution of molecules that can imply immiscibility between the components and, therefore, a high precipitation risk. For this reason, asphaltenes from unstable materials are characterized by wider solubility profile distributions than asphaltenes from stable materials. A characteristic parameter of the solubility profile distribution, ΔPS, can be obtained and correlated to the colloidal stability of the samples using the p4 ACS Paragon Plus Environment
Page 5 of 13 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
value as measured by the ASTM 6703 [10]. The solubility profile of crude oils was measured for all 11 samples and the results are given in the appendix (Fig. A-1). 4. Experimental Results and Discussion 11 different crude oil and bitumen samples were first characterized in terms of their density, viscosity, SARA (Saturates, Aromatics, Resins, and Asphaltenes) fractions, and the ΔPS parameter. As observed, API gravity and viscosity of the crude oil samples have significant variation, ranging from 6.11 to 27.05 °API and from 500 to 19,000,000 cP, which enables us to visualize the asphaltenes behavior for different crude oils with different properties (Table A-1). SARA fractionation is based on the solubility of the crude oil components in different solvents and provides information on the weight percent distribution of each fraction within an oil sample [13]. However, the amount of each fraction does not produce sufficient direct information to characterize the crude oil samples [19, 20]. Hence, to assess the contribution of SARA fractions on the physical properties of crude oil, the weight ratio of heavy (resins + asphaltenes) to light (saturates + aromatics) fractions is compared with the viscosity and density results (Fig. 2). It can be observed that both viscosity and density a have direct linear relationship with the heavy to light weight ratio of the SARA fractions, thus indicating that an increase in the concentration of heavier fractions (resins + asphaltenes) will make the crude oil denser and more viscous. Oil samples C3, C4, and C9 showed anomalous behavior and were treated as an outlier in these correlations. It should be noted that the density of crude oil in Fig. 2-B is estimated from the measured API gravity values given in Table A-1.
5 ACS Paragon Plus Environment
1.6
C2
1.4 1.2
C9 C3
1 0.8
C11 C1
C8 C5 C7
C10 C4
0.6 0.4 0.2 0 1.E+02
C6
y = 0.0873ln(x) - 0.0852 R² = 0.8321 1.E+04 1.E+06 Crude Oil Viscosity, cP
1.E+08
B-The relation between crude oil viscosity and SARA fractions
Heavy to Light Fractions Weight Ratio, wt:wt
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
Heavy to Light Fractions Weight Ratio, wt:wt
Energy & Fuels
Page 6 of 13
1.5
C2
y = 12.26x - 11.111 R² = 0.8095
1.3 1.1
C8
C7
0.9 C1
0.7
C9
C5
C3
C11 C10
C4
0.5 C6
0.3 0.88
0.93 0.98 Crude Oil Density, g/cm3
1.03
B- The relation between crude oil density and SARA fractions
Fig. 2. Relationships between SARA fractions and physical properties of crude oils. The outliers for the correlation between heavy to light fraction weight ratio with crude oil viscosity (C3 and C9) and with crude oil density (C3 and C4) are given in grey and were excluded from the correlations given on each graph. (It should be noted that resins and asphaltenes fractions of crude oils, which have polyaromatic structures and non-hydrocarbon components, were referred as heavy fractions of crude oil due to their high molecular weight) In addition to highlighting the basic correlation between the physical properties and the SARA fractions of crude oil, Fig. 2 also indicates that the density and viscosity of oil samples do not follow the same incremental order from sample C6 (lowest heavy to light ratio of 0.39) to sample C2 (highest heavy to light ratio of 1.51). To better understand the mechanism behind the variations in the order of the viscosity and density, we analyzed the elemental composition of the crude oil with carbon, hydrogen, and trace metal contents (Table A-2). Crude oil comprises of distinct molecules that are physically or chemically bonded to each other [21]. The polar asphaltenes fraction of the crude oil generally consists of the non-hydrocarbon and unsaturated hydrocarbon compounds. Thus, an increase in its concentration will lower the hydrogen content and hydrogen to carbon ratio. Conversely, the nonhydrocarbon content of the crude oil will tend to increase with the increase in the asphaltenes content. Fig. 3 depicts that most of the oil samples analyzed in this study follow a linear trend for hydrogen content, hydrogen to carbon weight ratio, and non-hydrocarbon content with the asphaltenes content of the crude oils, as described in the literature [19]. However, four samples namely C3, C4, C7, and C9 behave as outliers and are excluded from the trend analysis. It is essential to understand more about the
6 ACS Paragon Plus Environment
Page 7 of 13
behavior of the outliers rather than the samples following regular trends to develop a better analysis of the precipitation tendency of asphaltenes derived from different characteristic crude oils.
30
C9
20
50
C3
C11 C1 C10 C4
10
C6
0
y = -25.877x + 309.03 R² = 0.992
Asphaltenes Content, wt%
40
C8 C2 C5 C7
C2
40
C5
30 20
C9
C7 C11
C1
11 12 13 Hydrogen Content of Crude Oil, wt%
14
A- The relation between the amount of asphaltenes and the hydrogen content of crude oil
C10
C4
10 0
10
50
C3
C8
C6
y = -2178.7x + 320.17 R² = 0.9883
0.12 0.13 0.14 0.15 0.16 Hydrogen to Carbon Ratio of Crude Oil, wt:wt B-The relation between the amount of asphaltenes and the hydrogen to carbon ratio of crude oil
Asphaltenes Content, wt%
50
Asphaltenes Content, wt%
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
C3 C2
40
C8
C7
C5 C9
30 C4
20
C1 C11 C10 C6
10
y = 17.531x - 114.83 R² = 0.8765
0 2
5 8 11 14 17 Non-Hydrocarbon Content of Crude Oil, wt% C- The relation between the amount of asphaltenes and the non-hydrocarbon content of crude oil
Fig. 3. The relation between asphaltenes content and the hydrogen, carbon, and non-hydrocarbon content of crude oils. The outliers given in grey dots (C3, C4, C7, and C9) were excluded from the correlations given on each graph. For sample C3, the hydrogen content and hydrogen to carbon weight ratio are measured very high (H = 13.4 wt% - Fig. 3-A and H/C = 0.159 - Fig. 3-B). Consequently, the non-hydrocarbon content of sample C3 can be observed to be extremely low (2.2 wt% - Fig 3-C). Since wax fraction mostly comprises of paraffinic hydrocarbon compounds [7], we believe that the n-pentane insoluble asphaltenes content for C3 does not reflect the real asphaltene content due to the high wax content of C3 which precipitates out along with asphaltenes. C7 has high hydrogen content and non-hydrocarbon contents. It has been measured that this oil has 28 wt% water content. Hence, the high hydrogen and non-hydrocarbon (mainly oxygen) contents of C7 should be associated with water (H2O). As dewatering of the crude oil sample prior to analysis might be important. Thus, mechanical, thermal, and chemical methods were tested to remove water. However, while the mechanical methods were not sufficient to remove the entire water content of C7, the thermal and chemical water removal methods caused an alteration in the chemical composition of crude oil. Therefore, C7 was subjected to the analyses directly without dewatering which might be the reason behind the deviations in correlations. It should also be noted that since both water and asphaltenes are polar, their interaction results in higher amount of emulsion formation with water attached to asphaltenes [22]. Still, the elemental analysis results are not sufficient to explain the anomalous behavior of samples C4 and C9. Therefore, we carried out a detailed analysis of the solubility profiles of the crude oil to evaluate asphaltenes stability. The ΔPS parameters of crude oils were calculated by using solubility profiles given 7 ACS Paragon Plus Environment
Energy & Fuels
in appendix (Fig. A-1) to understand the stability of asphaltenes within bulk crude oil based on their solubility in different solvents (given in the last column of Table A-1). The value of ΔPS is inversely related to the asphaltenes stability. Therefore, a higher ΔPS results in the lower asphaltenes stability and higher precipitation tendency. Accordingly, the asphaltenes of the sample C8 is found to be the most unstable with a ∆PS value of 2.80 and C6 is the most stable with a ∆PS value of 0.40. To analyze the effect of mutual interactions between different crude oil components on the overall asphaltenes stability, we compared the ΔPS parameter with asphaltenes content and resins to asphaltenes weight ratio (Fig. 4).
C3
C8
C4
40
C5
C9
C7
30 C11
20
C1 C10
C2
C6
10
y = 18.075x + 5.4404 R² = 0.877
0 0
0.5 1 1.5 2 ΔPS Parameter, dimensionless
A-Contribution of the asphaltenes content towards overall asphaltenes stability
Resins to Asphaltenes Weight Ratio, wt:wt
50
Asphaltenes Content, wt%
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 8 of 13
2.5
1.4 C6
1.2
C4
1
C10
0.8
C9
C1
0.6 C8
0.4
C11 C2
y = -0.6458x + 1.4865 R² = 0.9216
0.2 0 0
C5
C7 C3
0.5 1 1.5 2 ΔPS Parameter, dimensionless
2.5
B- Contribution of resins to asphaltenes weight ratio on overall asphaltenes stability
Fig. 4. Relationships between asphaltenes content and resins to asphaltenes ratio with ΔPS parameter. The outliers given in grey dots (C2, C4, and C8) were excluded from the correlations given on each graph. It can be observed that the ΔPS parameter increases with the increase in asphaltenes content (Fig. 4-A). In other words, as the amount of asphaltenes increases in the bulk oil, their precipitation tendency increases. The stability of asphaltenes at constant pressure and temperature is controlled by the mutual interaction of asphaltenes with the other fractions of the crude oil [23, 24]. Fig. 4-B suggests that as the resins to asphaltenes ratio increases, the asphaltenes stability increases, highlighting the role of resins in maintaining the stability of asphaltenes. From the comparative correlations given in Fig. 4, samples C2, C4, and C8 can be observed not to follow the trends and behave as outliers. To further investigate the possible reasons for the anomalous behavior of the outliers, an integrated analysis of the SARA fractions and elemental composition with ΔPS parameter was conducted, and the results are given in Fig. 5.
8 ACS Paragon Plus Environment
C2
C8
1.4 1.2 1
C9
y = -0.768x + 2.3143 R² = 0.894
0.8 0.6
C1
0.4
C6
0.2
C5 C3
C11 C4 C10
C7
y = 0.4212x + 0.2432 R² = 0.9864
0 0
1 2 ΔPS Parameter, dimensionless
3
A-The relation between ΔPS Parameter and SARA fractions
0.1
Metals having inorganic source in Crude Oil, wt%
1.6
Organometallics content, wt%
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
Heavy to Light Fractions weight ratio, wt:wt
Page 9 of 13
y = 0.0098x2.1052 R² = 0.9239
0.08
C5
0.06
C8
0.04 C11 C10
0.02 C6
0 0
C1
1 2 ΔPS, dimensionless
B-The relation between ΔPS Parameter and Organometallic content of crude oil
3
0.07
C2
0.06
y = -0.0574x + 0.1189 R² = 0.7966
0.05 0.04 C9
0.03 0.02
C7
0.01
C4
0 1
C3
1.5 2 ΔPS, dimensionless
2.5
C-The relation between ΔPS Parameter and metals having inorganic source
Fig. 5. Relationships of SARA fractions, organometallic content, and metals having an inorganic source with ΔPS parameter. For Fig. 5-A, the samples following regular and expected trend are given with red dots, while the outliers are highlighted using black dots. Fig. 5-A correlates the heavy to light fraction ratio of crude oils with its ΔPS parameter. Samples C1, C3, C5, C6, C8, C10, and C11 show an expected trend of linear increase (red dashed line in Figure 5-A) in asphaltenes unstability with higher heavy fraction (resins + asphaltenes) concentration. Contrarily, an inverse relationship is observed for the crude oil samples C2, C4, C7, and C9. The linear decreasing trend (black dashed line in Figure 5-A) indicates that the stability of asphaltenes increases with the decrease in heavy to light fraction ratio. The ΔPS values given with red dots in Fig. 5-A also yield exponential correlation with the organometallic content of crude oil (Fig. 5-B). We counted as only the vanadium and nickel contents of crude oils as the organometallic content of crude oils for this study [25]. The other metals are assumed to be in the inorganic content of crude oil; due to reservoir rock migration into crude oil, such as sand, clay, salts, etc (Table A-2). Because there is a possibility of the origin of the monovalent (i.e., Na and K), divalent (i.e., Ca and Mg), and trivalent (i.e., Al and Fe) ions in crude oils being inorganic. Hence, these elements might be in crude oil as mineral forms (i.e.; carbonates, clays, salts). Due to small amounts of these elements present in crude oil when compared to bulk oil carbon and hydrogen contents, the contribution of the inorganic elements in bulk crude oil may be ignored. However, it should be noted that the impact of the mineral content of crude oils on asphaltenes stability might be important even at in small quantities [26-28]. Thus, the y-axis in Fig. 5-C is named as metals having inorganic sources in crude oil. These elements mainly include aluminum, potassium, calcium, magnesium, sodium, and silicon. It has been observed that while the data points given in black dots in Fig. 5-A do not correlate with the vanadium and nickel content of crude oils (Fig. 5-B), they do correlate with the inorganic content of crude oils (Fig. 5-C). These impurities or reservoir fines in the form of metals with inorganic source affect the solubility of asphaltenes in different solvents and result in
9 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 10 of 13
misleading ΔPS values [29]. High concentration of sodium and potassium in sample C2 may be the reason for its anomalous behavior. C9 can also be seen to contain high amounts of sodium and sulfur (Table A-2). The possible presence of sodium sulfate salt originating from reservoir minerals can affect the overall asphaltenes stability [30]. To validate the presence of reservoir fines within the asphaltenes, we analyzed the n-pentane insoluble portion of crude oil C9 using scanning electron microscopy (SEM) technique and the images at two different resolutions are given in Fig.6. The dendritic or branched structure of an inorganic mineral shown clearly at 9,500x magnification confirms the migration of reservoir fines along with the crude oil and its interaction with asphaltenes.
Fig. 6. SEM images of the n-pentane insoluble asphaltenes fraction of crude oil C9 at two magnifications; 2,500x on the left and 9,500x on the right. Some recent studies on extended-SARA also pointed out that the sulfur content of asphaltenes has a key role on activity and aggregation of asphaltenes [31, 32]. 5. Conclusions This work determines the factors affecting the asphaltenes solubility and stability within the crude oil based on its characteristics. Understanding the overall asphaltenes stability behavior is complex and depends not only on the interaction of asphaltenes molecules among themselves but also on their interaction with other crude oil components and reservoir components. Presence of paraffinic wax and water within the crude oil samples along with impurities in the form of reservoir fines can significantly affect the stability of asphaltenes. Among the trace metal content of crude oil, the composition of organometallics elements such as vanadium and nickel can destabilize asphaltenes. Conversely, the 10 ACS Paragon Plus Environment
Page 11 of 13 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
metal content of crude oil having inorganic sources like sodium, potassium, and sulfur are seen to impact the asphaltenes solubility. In addition to the highlighting the impact of crude oil solubility on asphaltenes stability, this paper also provides a useful data set which can be used to develop better understanding through the equation of state calculations of asphaltenes phase behavior. Thus, the presented data set can serve as an input data for simulations studies for the potential readers who are seeking for the experimental data to model asphaltenes phase behavior. Acknowledgements We acknowledge the financial support and the opportunity provided by the Society of Petroleum Engineering (SPE) and by the Heavy Oil, Oil shales, Oil sands, & Carbonate Analysis and Recovery Methods (HOCAM) Research Team at Texas A&M University, Petroleum Engineering Department. Nomenclature API
American Petroleum Institute
ASTM
American Society for Testing and Materials
C1-C11
Crude oil or bitumen samples
CHN
Carbon, Hydrogen, and Nitrogen
cP
centipoise
ELSD
Evaporative Light Scattering Detector
EOR
Enhanced Oil Recovery
H/C
Hydrogen to Carbon ratio
HPLC
High Performance Liquid Chromatography
ICP
Inductively Coupled Plasma
ND
Non-detectable
ppm
Parts per million
SARA
Saturates, Aromatics, Resins, and Asphaltenes
SEM
Scanning Electron Microscopy
wt.%
Weight percent
μg/L
Microgram per liter
ΔPS
Asphaltenes stability Parameter
11 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 12 of 13
References [1] Speight JG. The chemistry and technology of petroleum: Chemical industries: v. 44, New York : M. Dekker, 2nd ed., rev. & expanded; 1991. [2] Mukhametshina A, Kar T, Hascakir B. Asphaltene precipitation during bitumen extraction with Expanding Solvent Steam Assisted Gravity Drainage (ES-SAGD): Effects on pore-scale displacement. SPE Journal 2015. SPE-170013-PA. [3] Kar T, Mukhametshina A, Unal Y, Hascakir B. The effect of clay type on steam-assisted-gravitydrainage performance. Journal of Canadian Petroleum Technology 2015; SPE-173795-PA. [4] Demir AB, Bilgesu HI, Hascakir B. The effect of clay and salinity on asphaltene stability. In: SPE Western Regional Meeting, 23-26 May, Anchorage, Alaska, USA, SPE-180425-MS; 2016. [5] Punase AD, Prakoso AA, Hascakir B. The polarity of crude oil fractions affects the asphaltenes stability. In: SPE Western Regional Meeting, 23-26 May, Anchorage, Alaska, USA, SPE-180423-MS; 2016. [6] Goual L, Firoozabadi A. Measuring asphaltenes and resins, and dipole moment in petroleum fluids. AIChE Journal 2002; 48(11): 2646-63. [7] Prakoso AA, Punase AD, Hascakir B. A mechanistic understanding of asphaltene precipitation from varying saturate concentration perspective. In: SPE Latin American and Carribean Petroleum Engineering Conference, 18-20 November, Quito, Ecuador, SPE-177280-MS; 2015. [8] Hammami A, Phelps CH, Monger-McClure T, Little TM. Asphaltene precipitation from live oils: An experimental investigation of onset conditions and reversibility. Energy Fuels 2000; 14(01): 14-18. [9] Buckley JS. Predicting the onset of asphaltene precipitation from refractive index measurements. Energy Fuels 1999; 13(02): 328-32. [10] Rogel E, Ovalles C, Moir M. Asphaltene stability in crude oils and petroleum materials by solubility profile analysis. Energy Fuels 2010; 24(08): 4369-74. [11] Khayan M. Proposed classification and definitions of heavy crude oils and tar sands. New York: The Future of Heavy Crude and Tar Sands, McGraw-Hill. 1984 [12] Meyer RF, de Witt W Jr. Definition and world resources of natural bitumens. Denver, CO: U.S. Geological Survey Bulletin 1944, Department of the Interior, U.S. Geological Survey; 1990. [13] Speight JG. Chemistry and technology of petroleum. 5th Edition, Boca Raton, FL, USA, CRC Press; 2014. [14] Borton D, Pinkston DS, Hurt MR, Tan X, Azyat K, Scherer A, Tykwinski R, Gray M, Qian K, Kenttämaa HI. Molecular structure of asphaltenes based on dissociation reactions of their ions in mass spectroscopy. Energy Fuels 2010; 24(10): 5548-59. [15] Schuler B, Meyer G, Peña D, Mullins OC, Gross L. Unraveling the molecular structure of asphaltenes by atomic force microscope. J. Am. Chem. Soc. 2015; 137(31): 9870-76. [16] Kharrat AM, Zacharia J, Cherian VJ, Anyatonwu A. Issues with comparing SARA methodologies. Energy Fuels 2007; 21(06):3618-21. [17] Kar T, Ovalles C, Rogel E, Vien J, Hascakir B. The residual oil saturation determination for Steam Assisted Gravity Drainage (SAGD) and Solvent-SAGD. Fuel 2016; 172: 187-95. [18] ASTM. D2007-11: Standard test method for characteristic groups in rubber extender and processing oils and other petroleum-derived oils by the clay-gel absorption chromatographic method; 2011. [19] Evdokinmov IN. Bifurcated correlations of properties of crude oils with their asphaltene content. Fuel 2004; 84(01):13-28.
12 ACS Paragon Plus Environment
Page 13 of 13 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
[20] Redelius P, Soenen H. Relation between bitumen chemistry and performance. Fuel 2015; 140: 3443. [21] Mullins OC, Sheu, EY. Structure and Dynamics of Asphaltenes. Second Eds. New York, Plenunm Press; 1998. [22] Kar T, Hascakir B. The role of resins, asphaltenes, and water in water–oil emulsion breaking with microwave heating. Energy Fuels 2015; 29(06): 3684-90. [23] Lian H, Lin J, Yen TF. Peptization studies of asphaltene and solubility parameter spectra. Fuel 1994; 73 (03): 423-28. [24] Wang J, Buckley JS. Asphaltene stability in crude oil and aromatic solvents - The influence of oil composition. Energy Fuels 2003; 17(06): 1445-51. [25] Speight JG. Handbook of petroleum analysis. New York, John Wiley and Sons Inc.; 2001. [26] Patton CC, Jessen FW. The adsorption of petroleum residuals on iron and steel surfaces. Society of Petroleum Engineers, SPE 1088-MS; 1964. [27] Carbognani L. Effects of iron compounds on the retention of oil polar hydrocarbons over solid sorbents. Petroleum Science and Technology 2000; 18(3-4): 335-60. [28] Ibrahim HH, Idem RO. Correlations of characteristics of Saskatchewan crude oils/asphaltenes with their asphaltenes precipitation behavior and inhibition mechanisms: Differences between CO2and n-heptane-induced asphaltene precipitation. Energy Fuels 2004; 18(05): 1354-69. [29] Coelho, RSC, Ovalles, C, Benson, IP, Hascakir, B. Clay-asphaltene interaction during hybrid solventsteam injection into bitumen reservoirs. In: SPE Canada Heavy Oil Technical Conference, 7-9 June 2016, Calgary, Alberta, Canada, SPE-180723-MS. 2016. [30] Rodriguez-Navarro C, Doehne E, Sebastian E. How does sodium sulfate crytallize? Implications for the decay and testing of building materials. Cement and Concrete Research 2000; 30(10): 1527-34. [31] Qiao, P., Harbottle, D., Tchoukov, P., Masliyah, J., Sjoblom, J., Liu, Q., Xu, Z., Fractionation of Asphaltenes in Understanding Their Role in Petroleum Emulsion Stability and Fouling, Energy Fuels 2017; 31(4): 3330-3337. [32] Qiao, P., Harbottle, D., Tchoukov, P., Wang, X., Xu, Z., Asphaltene Subfractions Responsible for Stabilizing Water-in-Crude Oil Emulsions. Part 3. Effect of Solvent Aromaticity, Energy Fuels 2017; 31(9): 9179-9187
13 ACS Paragon Plus Environment
