1. Introduction
Asphaltenes are the heaviest and most polar fraction of crude oil. They are polyaromatic molecules surrounded by aliphatic and heteroatomic chains (N, O, S), they can have also metals (Fe, Ni, V) (Speight, 2004); where their chemical composition varies from crude oil to other one as shown in Table 1; where the asphaltene isolated from Iraq crude oil has not Azote in its elemental composition (DeCanio et al., 1990) in compared with the elemental composition of Kuwaitian asphaltenes (Ancheyta et al., 2002), this table regroups also the chemical composition of asphaltenes extracted from Aranian (Sato et al., 2005), Canadian (Ibrahim and Idem, 2004) and Chinese (Chen et al., 2012) crude oils; they have the same chemical elements and metals, but their tenors change following the source of crude oil.
Table 1. Elemental analysis and metal content of asphaltenes from different sources.
| Source | Composition (wt %) | Metals content | ||||||
|---|---|---|---|---|---|---|---|---|
| C | H | N | O | S | Fe | Ni | V | |
| Iraq (DeCanio et al., 1990) | 82.7 | 8.4 | – | 1.2 | 7.7 | – | 145 ppm | 308 ppm |
| Kuwait (Ancheyta et al., 2002) | 81.62 | 7.26 | 1.46 | 1.02 | 8.46 | – | 320.2 ppm | 1509.2 ppm |
| Iran (Sato et al., 2005) | 83.2 | 6.8 | 1.4 | 1.5 | 5.9 | – | 390 ppm | 1200 ppm |
| Canada (Ibrahim and Idem, 2004) | 83.60 | 6.95 | 1.06 | 2.60 | 4.64 | 79 μg/g | 100 μg/g | 140 μg/g |
| China (Chen et al., 2012) | 82.89 | 8.32 | 0.69 | 3.25 | 2.56 | 13.6 μg/g | 0.5 μg/g | 8.0 μg/g |
Generally, asphaltenes are characterized by a high molecular weight which plays an important role in the insolubility of asphaltenes. This mass generally ranges from 500 to 1000 uma; it is varied considerably depending on the source of crude oil and the operating conditions. (Boduszynski, 1988, Lichaa, 1977).
Asphaltenes do not have an exact chemical structure. Nevertheless, they are characterized by polyaromatic rings containing heteroatoms (O, N, S) and aliphatic side chains (Pina et al., 2006).
Two models have been proposed in the literature to describe asphaltenes structure. The first is the “continental” or “island” model which provides a monomeric molecular asphaltene structure has a molecular weight in the range of ∼500–1000 Da, with a maximum of ∼750 Da, consisting of 6–7 aromatic rings condensed by several aliphatic groups with heteroatoms as shown in Fig. 1 (A) (Castillo et al., 2001, Groenzin and Mullins, 2000). The second model presented in Fig. 1 (B) is the “archipelago” or “rosary type” which proposes that the individual asphaltene monomers are composed of polycondensed groups contain 5 to 7 aromatic rings each one is linked by short aliphatic side chains possibly containing polar heteroatomic bridges (Acevedo et al., 2007, Strausz et al., 1999). This proposed molecular model has a molecular weight around 6000 g/mol greater than the mass molecular weight determined at the present time (Kelland, 2014).
Fig. 1. Structures of a proposed asphaltene molecule; A: continental and B: archipelago (Kelland, 2014).The operating definition admits that asphaltenes constitute the insoluble hydrocarbon fraction in a large excess of alkane at boiling temperature but soluble in toluene. The length of this alkane is variable depending on the used standard, it may be n-pentane according to ASTM D893-69 and ASTMD2006-70 (Speight et al., 1984), n-heptane according to NF AFNOR T60-115 (Savvidis et al., 2001), IP143/90 (Nazar and Bayandory, 2008) and DIN51-595 (Ortega et al., 2015). However, GOST11858-56 standard (Boukherissa, 2008) is based on the use of petroleum ether as a precipitant.
Studies of petroleum asphaltenes have rapidly increased during the past years because of the increasing of problems caused by asphaltenes in petroleum industries. This can be clearly seen in Fig. 2 which illustrates the number of papers published in scientific journals from year 2005 until November 2016 (collected from Google Scholar database) due to this growing volume of crude oils production face drastic changes in petroleum feed properties, which will affect all production system. For this reason, our work has been extensively covering asphaltene deposition problems during oil production and its removal and prevention methods.
Fig. 2. Number of publications about asphaltenes in the period 2005–2016.The asphaltene instability which causes precipitation is independent of the amount of asphaltenes present in the crude oil; however, it depends on the properties of asphaltene itself and the properties of the other crude oil fractions. For example, asphaltenes of Boscan crude oil from Venezuela constitute 17.2 wt% do not cause problems in compared with Hassi Messaoud crude oil from Algeria contains 0.15 wt% of asphaltenes, which cause many problems in oil production system (Sarma, 2003).
This current paper will review the factors influencing the deposition of asphaltenes during oil production, including the problems induced by the asphaltene deposits, and the methods used to remediate them. Furthermore, this review regroups also different inhibitors and dispersants which have been developed in these recent years to prevent the deposition of asphaltenes.
2. Factors influencing the deposition of asphaltenes
2.1. Effect of chemical composition
Chemical composition of crude oil plays an important role in the stability evaluation; asphaltenes of a stable crude oil are characterized by low aromaticity (low condensation of aromatic rings) and high hydrogen content. Nevertheless, in unstable crude oil asphaltenes are characterized by low hydrogen content and high aromaticity (Rogel et al., 2001). It seems easy to estimate the stability of a crude oil through Stankiewics plot which takes into account SARA fractions. In this method, saturates/aromatics ratios are plotted against asphaltene/resins ratios as shown in Fig. 3 in order to evaluate the tendency of asphaltene precipitation. However, two regions are clearly marked as stable and unstable zones (Stankiewicz et al., 2002).
Fig. 3. Asphaltene stability criterion of Stankiewicz (Stankiewicz et al., 2002).In the crude oil asphaltenes have a colloidal form stabilized by the petroleum resins, because resins have an intermediate polarity between asphaltenes and aromatics. These resins are structurally similar to asphaltene with much lower molecular weight. their molecules are characterized by small aromatic ringsand long alkyl chains and contain fewer heteroatoms than asphaltenes (Fig. 4)(Murgich et al., 1996). Therefore, they are likely to adsorb on the surface of asphaltenes (Pereira et al., 2007); the polar sites of resins interact with the polar sites of asphaltenes while the nonpolar sites of resins interact with the oil phase in order to form a steric layer around the asphaltene particles and create a combined entity called “micelle” (Schantz and Stephenson, 1991).
Fig. 4. Molecular structures of petroleum resins (Murgich et al., 1996).The composition of reservoir fluid changes due to natural depletion during primary fluid recovery which may result loss of lighter components leading to a decrease of gas/oil ratio (GOR) and an increase of fluid density. These two effects will reduce the flocculation tendency of asphaltenes (Leontaritis, 1989). The injection of miscible fluids (CH4, natural gas) during secondary oil recoveryhas the potential to cause asphaltenes flocculation (Kokal and Sayegh, 1995), because natural resins in petroleum act as a peptizing agent for asphaltenes are partially or completely dissolved in the presence of an excess of low hydrocarbons molecular weight (Boukherissa, 2008, Takhar et al., 1995), for this reason asphaltenes are depeptized, coagulated and precipitated (Haskett and Tartera, 1965).
The results of asphaltene precipitation of Arab-D crude oil from Ghawar field at different GOR values showed that precipitation of asphaltenes occurs at relatively low GOR values (∼625scf/bbl). Whereas, the amount of precipitated asphaltenes is very low at the conditions of appearance and increases with increasing of gas/oil ratio (Kokal et al., 2003).
Due to several years of oil extraction, the reservoir is subjected to a remarkable decline in its production and as a promising solution the recovery assisted by the injection of CO2 is necessary to recover the maximum of oil. In this case, the injection of CO2 into the reservoir can cause precipitation of asphaltenes in the reservoir because of its miscibility with crude oil (Leontaritis and Mansoori, 1988, Monger and Fu, 1987, Tuttle, 1983, Vafaie-Sefti et al., 2003).
The existence of water in petroleum reservoirs increases the complexity of asphaltene precipitation deposition, because the formation water contains different ions with different charges which may disturb the stability of asphaltenes (Hu et al., 2015). The effect of salinity on asphaltene stability is related to the adsorption affinity of anions and cations of salts presented in water. In addition, the salt concentration has negative impact on the stability of asphaltenes. However, this impact is highly dependent on the metal content of asphaltenes and the ions content of brines (Demir et al., 2016).
2.2. Effect of pressure
The precipitation of asphaltenes occurs during the decrease of pressure above the bubble point; this decrease of pressure will decrease their solubility and the oil becomes a poor solvent for asphaltenes. Below the bubble point the change of oil chemical composition due to gas release improves the solubility of asphaltenes, while the pressure drops down the oil becomes a good solvent for asphaltenes (Hirschberg et al., 1984, Vargas et al., 2009).
The calculation of density and solubility parameter for a crude oil during a natural depletion test at reservoir temperature demonstrated that during the decrease of pressure above the bubble point, density and solubility parameter of crude oil decrease and make the asphaltenes less stable which result their precipitation (Fig. 5). However, the reduction of pressure below the bubble point releases the dissolved gas from the crude oil and increases the density and the solubility parameter; in this case the precipitated asphaltenes dissolve again in the bulk oil (Fig. 6) (Bahrami et al., 2015).
Fig. 5. Evolution of density and solubility parameter of the crude oil during a natural depletion test at reservoir temperature (Bahrami et al., 2015).
Fig. 6. Amount of precipitated asphaltenes during a natural depletion experimental test at reservoir temperature (Bahrami et al., 2015).2.3. Effect of temperature
The effect of temperature on the asphaltenes stability can be complex and various factors can be identified. The first factor is the solubility of asphaltenes which increases with increasing of temperature, and consequently a low mass of asphaltene precipitates at high temperatures. The second factor is the change of crude oil composition due to heating; when the mixture of the oil is heated light fractions mainly the alkanes dilate and reduce the solubility parameter of crude oil making the asphaltenes less soluble in, for this reason at higher temperatures the low solubility of asphaltenes will lead to quick aggregation and shorter reaction time for precipitation detection. The last factor is the role of viscosity in the aggregation rate; the oil viscosity decreases with increasing temperature. Furthermore, the diffusivity of asphaltene particles increases and leads to faster aggregation (Maqbool, 2011).
A study was investigated about the impact of temperature on asphaltene precipitation for Iranian crude oil and the results of this study showed that precipitation of asphaltenes decreases as the temperature increases (Fig. 7) which means that this phenomenon can occur due to the variation in molar volume of oil components leading to a change in the oil solubility (Afshari et al., 2010).
Fig. 7. Asphaltene precipitation during natural depletion experimental test at two different temperature values (Afshari et al., 2010).2.4. Electrokinetic effect
Due to the electrical potential generated by the flow of fluids through the reservoir pores or tubing the electrokinetic effects destabilize asphaltene micelles and contribute to their flocculation and the magnitude of these electrokinetic effects is dictated mainly by the velocity of reservoir fluids. The precipitation problem of asphaltenes is greater near the well bores; where the flow velocity is highest (Kokal and Sayegh, 1995, Sarma, 2003).
2.5. Acid stimulation treatment
Matrix stimulation is a technique used to restore the initial permeability of a damaged formation by dissolving and/or dispersing materials that impair well production through the injection of a fluid (e.g., acid or solvent). However, The stimulation treatments by hydrochloric acid can definitely precipitate asphaltenes from the crude oil and lead to severe permeability damage (Lichaa and Herrera, 1975); where the iron ions are the responsible of asphaltene precipitation during stimulation treatment by HCl acid injection. One might explain the effect of Fe++ and Fe+++ on the precipitation of asphaltenes as possibly a charge neutralization effect due to coordination of iron ion with porphyrin, pyrroles, pyridine, or phenolic hydroxyl groups of asphaltene molecules (Jacobs and Thorne, 1986).
3. Asphaltene deposition problems during oil production
Precipitation and deposition of asphaltenes during oil production are the source of many problems, including, on one hand, their tendency to damage the reservoir rock and, on the other hand, their ability to plug the tubing and the other production facilities.
3.1. Formation damage
Asphaltene flocculation in the reservoir can effectively reduce the mobility of hydrocarbons by clogging the pores and consequently reduce the permeability of reservoir rock, as well as the flocculated asphaltenes can alter the wettabilityof the formation and convert it from water wet surface to oil wet surface and increase the viscosity of fluid by the formation of oil/water emulsions (Leontaritis et al., 1994, Nabzar et al., 2005). Asphaltenes are considered to be responsible for altering the wettability of reservoir rock due to their polar functional groups which interact with oxides of mineral surfaces (Buckley et al., 1989); as asphaltenes are more polar and heavier than the water surrounding the surface of the rock, they can diffuse through the water film to adsorb onto the rock surface and reverse its wettability (Fig. 8) (Leontaritis, 1989).
Fig. 8. Asphaltenes adsorbed on rock surface cause change in wettability(Leontaritis, 1989).Leontaritis and Mansoori explained the mechanism of asphaltenes adsorption of an oil sample by the positive charge of flocculated asphaltenes which facilitates their penetration through the water film to attach the negative charge of mineral surfaces then convert them to oil wet surfaces. This phenomenon increases the residual saturation of oil and affects negatively the crude oil recovery (Leontaritis and Mansoori, 1987).
The qualitatively essential feature for wettability reversal appears to be direct contact between oil/water and mineral/water interfaces after water-film rupture. The deposition of asphaltenes is apparently necessary to alter the mineral surface wettability from strongly water-wet to strongly oil-wet (i.e., from a near zero contact angle through the water phase to one significantly greater than 90°)(Kaminsky and Radke, 1997).
3.2. Manifestation of asphaltene deposits in the well
The problem of asphaltene deposition is not limited in the reservoir; it can reach even the production column by partial or total plugging of the production tubing such as the frequent case of Hassi Messaoud field; where asphaltenes form deposits on the tubing (Haskett and Tartera, 1965).
Asphaltenes have the tendency to deposit also on down hole safety valves (DHSV) and consequently the blocking of their operation. In November 1986 the safety valves in two wells in Ula field in Norway became difficult to open. However, these valves were removed and examined to find subsequently that a black material later identified as asphaltenes had deposited on the valves and interfered with the opening mechanism (Thawer et al., 1990).
3.3. Deposition on surface facilities
Asphaltenes tend to deposit on the valves of wellhead and separators; where the pressure is lower than the bubble pressure. In 1987 a mass of 25 tons of asphaltenes was found within two main gas-oil separators during inspection works in Ula field, Norway (Thawer et al., 1990).
The mainly problem is the safety of the separator control equipment, as asphaltenes can plug the safety devices and valves then block their opening and closing when it is necessary (Kokal and Sayegh, 1995).
4. Asphaltene deposition control
Asphaltene precipitation causes many problems during oil production. Due to the tendency of the precipitated asphaltenes to flocculate and form large particles, as well as the affinity of flocculated particles to adsorb and to deposit on solid surfaces, then these asphaltene deposits may subsequently lead to a decrease in productivity of the well and an increase in production costs. To remedy this problem of deposition which causes a significant economic loss in the oil production system, several solutions are implemented.
4.1. Removal of asphaltene deposition
Wells partially or totally obstructed by asphaltene deposits are cleaned using the following methods:
4.1.1. Mechanical methods
These methods consist of mechanical scraping of deposits inside the wells (Akbar and Saleh, 1989). The common method is the use of Wire line unit; this method is slow and expensive in the case of a long and hard deposit. Another method is the drilling of the deposit by a hydro-blasting tool using a Coiled tubing unit. Nevertheless, this unit has a disadvantage of limiting the working pressure which makes the cleaning method difficult. There is another method of cleaning by application of pressure to create a differential pressure across the deposit in order to dislodge it.
4.1.2. Ultrasonic treatment
Ultrasonic technique can be used to clean asphaltene clogged sections of oil wells and reservoirs. Cleaning by ultrasonic waves appears to be disrupting the maltenes that form a continuous phase to provide adhesive and ductile properties to the dispersed asphaltenes (Gollapudi et al., 1994). The performance of ultrasonic waves is affected by different parameters such as time, power, frequency, and type of radiation needed to remove asphaltene deposits (Salehzadeh et al., 2016).
This technique was experimentally applied on asphaltene clusters and reservoir rock permeability damage due to asphaltene deposition into carbonate porous media. The results showed the decomposed of asphaltene clusters into fine sizes in that crude oil and the improved of reservoir rock permeability damage after the use of ultrasonic radiation (Shedid, 2004).
4.1.3. Chemical treatment
When mechanical methods are unsuccessful, chemical treatment with solvents is necessary to remove asphaltene deposits (Voloshin et al., 2005, Waxman et al., 1980). Most asphaltene solvents are aromatic solvents (Del Bianco and Stroppa, 1995). The solubility of asphaltenes in different hydrocarbon liquidswas examined (Miadonye and Evans, 2010) and deasphaltened oils with high aromatics content were also used at low cost, alternatively with chemical solvents (Jamaluddin et al., 1996, Jamaluddin and Nazarko, 1995, King and Cotney, 1996); Xylene with a low flash point of 28 °C is probably the most common aromatic solvent (Trbovich and King, 1991). Toluene is even more volatile (flashpoint 5 °C), it is also used, but it is less effective (Galoppini, 1994). However, the use of these hydrocarbon solvents is limited for many reasons; they can create corrosion, safety considerations (risk of explosion and fire because of their low flash point) (Shirdel, 2013).
4.1.4. Thermal treatments
Treating asphaltene deposition by thermal method includes many techniques such as hot oiling, which consists of injecting a hot oil to remove asphaltene deposits from the well. However the use of this technic can cause formation damage (Bernadiner, 1993). A continuous source of heat provided by down hole heater can be also used for a period of time to melt asphaltene deposits in the wellbore or on the tubing then pumped them up with the produced oil. Nevertheless, the application of this technique is limited due to high cost of maintenance and availability of electric power (de Andrade Bruining et al., 1990). Another thermal technique to remove asphaltene deposits consists of using heat-liberating chemicals, which involves pumping down a mixture of equi-molar concentrations of ammonium chloride and sodium nitrate. A buffer is used to delay the exothermic reaction until the fluid reaches the bottom-hole with a large quantity of nitrogen gas. However, this technique is very expensive in comparison with conventional thermal method (Zekri et al., 2003).
4.1.5. Bacteria treatment
Here bacteria are used to treat asphaltene deposition. Almehaideb and his coworkers used specific bacteria in their laboratory tests, which represent a high tolerance of high temperature and salinity conditions prevailing in the studied reservoir rock. In their test they subjected damaged cores to bacteria after a loss of initial oil permeability because of asphaltene deposition. The results of stimulation by bacteria treatment showed a 54% average improvement in the damaged core permeability (Almehaideb and Zekri, 2001).
4.2. Prevention of asphaltene deposition
4.2.1. Manipulation of oil production parameters
One method to prevent or reduce asphaltene deposition in the wells is to control pressure, temperature and/or flow rate to avoid the conditions where asphaltenes precipitate. The use of insulating annular to avoid excessive loss of temperature and maintain a constant fluid temperature, nevertheless the application of this method is limited. Another method is to increase the orifice chock size in order to reduce the ratio of gas/oil dissolution (Rs) and consequently reduce the possibility of working in the two phase domain below the bubble point (Kokal and Sayegh, 1995).
4.2.2. Asphaltene inhibitors and dispersants
Mechanical scraping or solvent washing operations are being carried out to remove asphaltene deposits. However, these operations are frequent and asphaltenes continue to deposit after (Albannay et al., 2010). Another method is currently under evaluation to control asphaltenes by chemical prevention using two classes of additives that can prevent their deposition during oil production: Inhibitors and dispersants of asphaltene deposition (Balson et al., 2002, Gupta et al., 2009).
The additives used in the oil field to prevent asphaltene deposition are injected with a small amount (˂1000 ppm) (Izquierdo and Rivas, 1997) into the well continuously in comparing with the solvents which are used only in curative operations (Abdallah et al., 2010).
4.2.2.1. Asphaltene inhibitors
Asphaltene inhibitors provide a real inhibition because they prevent the aggregation of asphaltene molecules. As they can affect the flocculation pressure of asphaltenes, therefore, precipitation and deposition of asphaltenes in the wellbore can be shifted to a point in the production system where they can be treated more easily (Marques et al., 2004, Smith et al., 2008).
In general the inhibitors are polymers or resins (Kelland, 2014). To avoid aggregation of asphaltene molecules, the inhibitor needs several points of molecular interaction for good inhibition, which explains the need for polymers. In addition, if it contains long alkyl chains in this case it can disperse the asphaltene aggregates (Barcenas et al., 2008).
The peptization of asphaltenes in aliphatic solvents using petroleum resins has shown that natural resins isolated from the heavy crude oil of Boscan have a good effect on stabilization of asphaltene in the crude oil of El Furrial in Venezuela (Carnahan et al., 2007).
Among the various chemical compounds tested to inhibit the precipitation of asphaltenes in crude oil the nonionic surfactants such as ethoxylated alcohols/phenols, they offered a good performance to inhibit the precipitation of asphaltenes. The results showed that an effective inhibitor must exhibit a significant interaction with asphaltenes and crude oil, in other words; the solubility of additives in the oil is important (da Silva Ramos et al., 2001).
Few studies have evaluated the use of plant liquid to prevent precipitation of asphaltenes. The cashew shell liquid, for example entirely formed by phenoliccompounds with unsaturated linear alkyl chains (fifteen carbon atoms) meta-substituted in aromatic rings has been successful in inhibition of asphaltene precipitation (Moreira et al., 1999). Vegetable oils such as sweet almond, andiroba, essential oil of coconut and sandalwood are soluble in oil; they have shown a high ability to inhibit the precipitation of asphaltenes with low economical cost (Junior et al., 2006).
A study about inhibition of asphaltene precipitation by nanoparticles has demonstrated that rutile nanoparticles (TiO2) can effectively improve the stability of asphaltenes in an acid medium of pH˂4. In a basic medium, these nanoparticles are not capable of preventing the precipitation of asphaltenes (Mohammadi et al., 2011). Recently in 2016, Lu and his co-workers studied the use of alumina nanoparticles (Al2O3) to inhibit asphaltene precipitation during CO2 injection. These fine particles provided a high performance in inhibition of asphaltene precipitation (Lu et al., 2016). Furthermore, these alumina nanoparticles can prevent asphaltene precipitation with a concentration as low as 2 ppm (Meneses et al., 2016). Even at very low permeability the injection of nano-fluid containing alumina nano-particles into the reservoir rock has a good performance in the prevention of asphaltene precipitation during oil production (Romero et al., 2013).
It has been also observed that changes in pressure and temperature can cause an increase in the stability of asphaltenes, thereby reducing the level of inhibition necessary to prevent deposition of asphaltenes in crude oil (Aquino-Olivos et al., 2001, De Boer and De Jong, 1992)
4.2.2.2. Asphaltene dispersants
Most of the dispersants are non-polymeric surfactants used to reduce the size of flocculated asphaltene particles (Kelland, 2014). These dispersants do not affect the flocculation point of asphaltenes, but they disperse the flocculated particles of asphaltene to keep them in suspension in the oil (Asomaning and Yen, 2002); the polar and/or aromatic groups of surfactants interact with the aggregated asphaltenes and the long alkyl chains on the periphery of the asphaltene aggregate help to change the polarity of the outside of the aggregate and make it more dispersible in the crude oil (Barcenas et al., 2008). This can also reduce the viscosity of the oil (Ovalles et al., 2011), while other dispersants can slow or stop the flocculation and the aggregation of asphaltenes (Kraiwattanawong et al., 2009). Dispersants may be used downstream of the bubble point, where prevention of asphaltene precipitation is insufficient and flocculated asphaltenes need to be dispersed to prevent their deposition (Kelland, 2014).
Several types of dispersing agents and surfactants have been studied in the literature (Chen et al., 2012, Marcano et al., 2015); Strong organic acids such as dodecyl benzene sulfonic acid (DBSA, n-C12H25-C6H4-SO3H) and other long chain organic surface-active agents such as nonylphenol (NP, n-C9H19-C6H4-OH) (Al-Sahhaf et al., 2002, Chang and Fogler, 1994). Most studies investigate the effect of dispersants on the deposition of asphaltenes measured in terms of the amount of precipitating agent needed to induce precipitation of these compounds (Östlund et al., 2004, Permsukarome et al., 1997). Strong organic acids, especially DBSA, are worked by attacking the heteroatomic sites of asphaltene molecules (Hashmi and Firoozabadi, 2012b, Hashmi et al., 2012). The acid-base interactions obtained along the long chain carbon of DBSA can form a solvation envelope around the asphaltene molecules, as well as dissolve them (León et al., 1999, Rogel and León, 2001). Some studies have been made of a distinct category of dispersants, namely non-ionic dispersants, which suggest a mechanism by which π-bonding plays an important role in the colloidal stabilization of asphaltene particles (Goual et al., 2014, Hashmi and Firoozabadi, 2011, Hashmi and Firoozabadi, 2012a, Karambeigi et al., 2016). Although non-ionic dispersants in the literature do not dissolve asphaltenes, they may be effective in stabilizing asphaltene suspensions at very low doses can reach in some cases 10 ppm (Hashmi and Firoozabadi, 2011).
It has been studied the properties of asphaltenes and their interaction with a few amphiphiles and the authors found that asphaltenes can be derived from dissociation of metal ions and deprotonation of acid groups (such as COOH, OH and SH) or basic groups (such as pyridine groups). This electrical property of asphaltenes plays an important role in the interaction between amphiphiles and asphaltenes; however, negatively charged asphaltenes tend to be dispersed by cationic amphiphiles, whereas positively charged asphaltenes tend to be dispersed by anionic amphiphiles (Wang et al., 2009).
It has been found that continuous injection of deasphaltened and developed oil into the column and production facilities is a useful method to prevent the deposition of asphaltenes; where the asphaltenes and the fractions from C5 to C15 were removed from Marrat crude oil to get the deasphaltened and developed oil then it has been used as a dispersant against the deposition of asphaltenes in this field which showed a good performance (Alkafeef et al., 2003).
Many additives have been used to inhibit the deposition of asphaltenes. Table 2summarizes the main asphaltene inhibitors and dispersants used in the literature in the period 2005–2016 such as synthetized ionic liquids(Boukherissa, 2008, Hu and Guo, 2005), light cycle oil (Ghloum et al., 2010), propoxylated polydodecyl (Ghaffar et al., 2015), henna extract (Monjezi et al., 2016) and other asphaltene inhibition additives.