Experimental evaluation of asphaltene inhibitors selection for standard and reservoir conditions

Journal of Petroleum Science and Engineering 137 (2016) 74–86

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Experimental evaluation of asphaltene inhibitors selection for standard and reservoir conditions Mohammad Ali Karambeigi a, Manouchehr Nikazar a,n, Riyaz Kharrat b a b

Chemical Engineering Department, AmirKabir University of Technology, Tehran, Iran Petroleum University of Technology, Ahvaz, Iran

art ic l e i nf o

a b s t r a c t

Article history: Received 14 June 2015 Received in revised form 26 October 2015 Accepted 12 November 2015

Asphaltene precipitation is a serious technical problem in petroleum industry. Several procedures are used to remove or prevent asphaltene precipitation, but the uses of asphaltene inhibitors provide the most practical and economical solution for deposits treatment. In this study, several effective impacts of inhibitors (salicylic acid, phthalic acid, nonylphenol, phenanthrene, benzoic acid and IR95) on asphaltenes were investigated including decrease in the amount of asphaltene precipitation at standard and reservoir condition, onset shifting, and asphaltene deposition at reservoir condition. During static and onset shifting tests, the hydroxyl group in inhibitors creates a compact planar phenol structure which seems to make a stable π–π interaction with the asphaltenes. In this case, salicylic acid creates an effective π–π interaction with the asphaltenes in a way that the carboxyl functional group and the extra hydroxyl group (–OH) on benzoic ring can strengthen the attachment with the asphaltenes because of the polarity. Results of dynamic test reveals that the adsorption of anionic chemicals in carbonate reservoirs is expected to be high because of the expected positive surface charge of carbonate minerals. The amount of adsorption of anionic chemicals on minerals is expected to depend on the surface charge of the mineral. Salicylic acid has an extra hydroxyl group on benzoic ring and with 34% asphaltene precipitation reduction has the best efficiency among non-commercial inhibitors. On the other hand, high capability of IR95 to be adsorbed on the porous media restarts the ability of asphaltene particles for precipitation on the pore surface. & 2015 Elsevier B.V. All rights reserved.

Keywords: Asphaltene Inhibitor Reservoir condition Adsorption Dynamic test

1. Introduction Several authors defined asphaltene over the years, from 1924 by Nellensteyn (1924) up to 2006 by Wang et al. (2006). They described asphaltene as the portion of oil that is soluble in aromatics like benzene and toluene and insoluble in straight chain n-alkenes such as n-pentane or n-heptanes. The phenomenon of asphaltene deposition has become a severe problem to almost all petroleum production, processing and transportation facilities. The precipitation of heavy organic solids especially asphaltenes in reservoirs, wells, and facilities has a detrimental effect on the economics of oil production because of reduction in well productivity and clogging up of the production facilities. Asphaltenes remain in solution under reservoir temperature and pressure conditions and begin precipitating when the n

Correspondence to: Chemical Engineering Department, Amir Kabir University of Technology, 424 Hafez Ave., Tehran 158754413, Iran. E-mail address: [email protected] (M. Nikazar). http://dx.doi.org/10.1016/j.petrol.2015.11.013 0920-4105/& 2015 Elsevier B.V. All rights reserved.

production temperature or pressure drops below onset conditions. The precipitation of asphaltene is caused by a number of factors including changes in pressure, temperature, chemical composition of the crude oil, mixing the oil with diluents or other oils, and during acid stimulation (Kokal and Sayegh, 1995). The Colloidal Instability Index (CII) is one accurate test for measurement of stability of asphaltenes in crude oils. It considers the crude oil a colloidal solution made up of the pseudo components: saturate, aromatic, resin and asphaltene and expresses the stability of asphaltenes in terms of these components. CII is defined as the sum of the asphaltenes and its flocculants (saturates) to the sum of asphaltene peptizers (resins and aromatics) in crude oils.

CII =

Asphaltene + Saturate Aromatic + Resins

Empirical evidence has shown that values of 0.9 and more indicate oil with unstable asphaltene, while values below 0.7 indicate stable asphaltenes. Between 0.7 and 0.9, the stability of the asphaltenes is uncertain (Gaestel et al., 1971).

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Measures for solving and stabilizing asphaltene precipitation and deposition problems are typically three fold: (a) the development of theoretical models (Vasquez and Mansoori, 2000; Pacheco-Sanchez and Mansoori, 1998; Victorov and Firoozabadi, 1996; Islam, 1994); (b) the study of asphaltene interfacial and colloidal behavior in crude oils and model systems (Ramos, 2001; Ramos et al., 2001; Mohamed et al., 1999a; Carbognani, 2001) and; (c) the estimation of chemical additives for the inhibition of asphaltene precipitation (Chang and Fogler, 1994a, 1994b; Mohamed et al., 1999b; Gonza´lez and Middea, 1991; Rogel and Leo´n, 2001). Minssieux (1997) studied the flow properties of asphaltenic crudes and carried out core floods experiments with an oil asphaltene content in the range of 0.1–6% weight in various rock materials. It was concluded that the gradual surface deposition is the damage mechanism in pore space. Different chemistries for asphaltene inhibition have been developed and evaluated at recent years (Squicciarini and Yen, 2007). Asphaltene inhibitors act in a way similar to resins, peptizing the asphaltenes and keeping them in solution. The effectiveness of inhibitors is controlled primarily by their chemical and structural characteristics. However, the inhibitor ability to stabilize asphaltenes depends also on the solvent or dispersion medium (Chang and Fogler, 1993). A few studies have presented alternatives to identify and develop more effective substances. Nevertheless, due to the complex nature of the crude oils it is necessary to estimate these substances with as many types of crude oils as possible in order to obtain more sustainable results. Usually, the studies have addressed the use of nonionic amphiphiles, such as the ethoxilated nonylphenol for asphaltene stabilization process (Gonza´lez and Middea, 1991; Loh et al., 1999; Mohamed et al., 1999b; Ramos et al., 2001; Ibrahim and Idem, 2004a), and the importance of acid–base interactions for asphaltene dissolution process in aliphatic solvents (Chang and Fogler, 1993, 1994a, 1994b; Ramos et al., 2001). Conceptually, there are at least two mechanisms by which a chemical inhibitor could prevent asphaltene deposition in the reservoir and down-hole facilities: In the first case, the inhibitor may be effective in the bulk of the crude oil so that when it is dissolved above a given concentration, it keeps asphaltenes either in solution or as a stable dispersion. This is the way in which inhibitors are generally supposed to be effective and is the case for which quantitative conclusions have been drawn in this work by the static and onset shifting tests. Alternatively, the asphaltene inhibitor may act on the surfaces of rock by limiting the rate of deposition/adhesion of asphaltene particles. IR95 as a commercial asphaltene inhibitor is presently known to act in this way in Iran, and the analysis performed also allows some qualitative conclusions to be drawn for this second mechanism by dynamic tests. In the technical literature, a few case histories of squeeze treatments for asphaltene inhibition are reported (Bouts et al., 1995; Allenson and Walsh, 1997). Also in the present work; an attempt has been made to experimentally evaluate the efficiency of such treatments and briefly compare the economics of the solvent-washes with the squeeze treatments. In this study, several effective impacts of inhibitors on asphaltenes were investigated including decrease in the amount of asphaltene precipitation at standard and reservoir condition, onset shifting, and asphaltene deposition at reservoir condition. Examined inhibitors consist of five non-commercial inhibitors namely benzoic acid, nonylphenol, phenanthrene, phthalic acid and salicylic acid and one commercial inhibitor namely IR95 with patent number 70680 in Iran. The non-commercial inhibitors are selected based on their functional groups to investigate the effect of hydroxyl and carboxyl functional groups on asphaltene stabilization (Karambeigi et al., 2015). As we all know, benzoic acid has

75

one carboxyl functional group, nonylphenol has one hydroxyl functional group, salicylic acid has one hydroxyl functional group and one carboxyl functional group, phthalic acid has two carboxyl functional groups and phenanthrene does not have any functional groups. Among various commercial inhibitors, IR95 showed good effects on asphaltene precipitation reduction during a three-stage inhibitor injection. However, it can be verified that the conditions along the processing and production of crude oils are different from those found in the laboratory.

2. Material and experimental procedure 2.1. Crude oil, core and inhibitors properties Oil sample used in this work belongs to an Iranian oil field. The properties of reservoir and crude oil are given in Tables 1 and 2. A carbonate core sample was used in the experiments. Petrophysical properties of the core samples used are given in Table 3. Porosity and permeability are measured by VINCI TECHNOLOGIES setup. To make synthetic live oil in laboratory, the oil recombination was performed by charging a specified amount of dead oil into a recombination cell. The corresponding gasses were then injected into the recombine cell. Recombine cell was pressurized to 5000 psia and was shaken continuously for 14 days by an electric motor (100 rpm) to ensure complete mixing of oil and gas into single phase liquid. D2007 (SARA test) is a method to separate crude oil into four fractions based on their solubility properties. These four fractions are saturates, aromatic, resin and asphaltene. In this method, the maltenes (the oil without asphaltene obtained from IP/143 test) were separated into saturates, aromatics, and resins using a chromatographic column packed with aluminum oxide. These fractions were sequentially eluted and collected using different solvents: saturates and aromatics were eluted using toluene-nheptane mixtures, while resins were obtained using a mixture of methanol, acetone, and chloroform. Asphaltenes were obtained using IP/143 method. Table 4 display the results of D2007 test. Results of D2007 test show that CII¼1.61. It reveals that the examined oil is very unstable (Gaestel et al., 1971; Asomaning et al., 2000; Asomaning., 2003). Examined inhibitors consist of five non-commercial inhibitors namely benzoic acid, nonylphenol, phenanthrene, phthalic acid and salicylic acid and one commercial inhibitor namely IR95. Physical properties of non-commercial inhibitors are given in Table 5. All above inhibitors were purchased from Merck (Merck Company), with purity higher than 99%. The commercial inhibitor is IR95. 2.2. Experimental procedure 2.2.1. Standard condition tests At first, the standard test was conducted at standard condition Table 1 Properties of reservoir. Specification

Result

Initial Pressure (Pisa) 5750 Saturation Pressure (Pisa) 3904 Temperature (°F) 241.7

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Table 2 Properties of crude oil. Composition

Mole%

Composition

0.18 nC5 N2 CO2 3.86 C6 H2S 4.83 C7 C1 42.85 C8 C2 7.01 C9 C3 4.39 C10 iC4 1.03 C11 nC4 2.77 C12 þ iC5 1.26 Total Measured SG at 60 F ¼0.87  ASTM D4052 test Viscosity at 241.7 °F and 3904 psia ¼0.41 cp  ASTM D445 test API¼ 29.5  ASTM D1298 test C12þ MW (gr/mole) ¼ 500.77  ASTM D2503 test Oil MW (gr/mole) ¼ 90.55  ASTM D2503 test

Mole % 1.73 2.51 2.53 2.72 2.63 2.18 1.68 15.84 100

oils. These solvents were centrifuged for 15 min. Finally, for measuring asphaltene precipitation IP/143 (IP 143/84, 1989) procedure was applied. For IP/143 test, a portion of the sample was mixed with heptane and the mixture was heated under reflux, and the precipitated asphaltene, waxy substances and inorganic material were collected on a filter paper. The waxy substances were removed by washing them with hot heptane in an extractor. After removal of the waxy substances, the asphaltenes were separated from inorganic materials by dissolution in hot toluene, the extraction solvent was evaporated and the asphaltene was weighted. The precipitation reduction (%) versus inhibitor concentration curves and optimum concentration for each inhibitor was obtained. The percentage of precipitation reduction was calculated based on the following equation: precipitation reduction(%) =

Asphaltene blank − Asphaltene treated × 100 Asphaltene blank

(1)

Where asphaltene blank and asphaltene treated are amount (grams) of asphaltenes extracted (using IP/143 tests) from blank oil (without inhibitor) and treated oil (with inhibitor) respectively.

Table 3 Properties of core sample. Rock type

Length (cm)

Diameter (cm)

Permeability (md)

Porosity (%)

Carbonate

14.9

3.82

0.298

10.02

Table 4 Result of D2007 (SARA) test (%weight). Asphaltene 2.5% Resin 17.9% Aromatic 20.3% Saturate 59.3%

(14.7 psia and 73 °F) and the performances of all inhibitors were compared. In each test, 5 cc Toluene as a solvent and the above mentioned inhibitors at various ppms (100, 250, 500, 750 and 1000) were prepared and each of them was dissolved with 50 gr

2.2.2. Static tests High pressure-high temperature system was used for reservoir condition tests (4500 psig and 241.7 °F). The setup of the experiments is shown in Fig. 1 which includes an oven, shaker, 0.5 μm metal filter, PVT cell (length ¼40 cm, outer diameter¼11 cm, inner diameter¼ 6 cm, volume ¼500 cc), and transfer vessel (length ¼75 cm, outer diameter¼12 cm, inner diameter¼ 9 cm, volume ¼1000 cc), recombine cell (length ¼110 cm, outer diameter¼ 16 cm, inner diameter¼12 cm, volume¼3000 cc), hydraulic pump, lines and pressure gauges (Fig. 1). The PVT cell can stand pressure up to 6000 psig, which is quite reasonable regarding most Iranian oil field reservoir pressure. The pressure inside PVT cell can be read by a pressure gauge placed on its top (Fig. 2). Recombined oil was injected into PVT cell and pressure was maintained at 4500 psig and 241.7 °F. To certify that the system has

Table 5 Typical non-commercial inhibitors properties (Samuel et al., 2000). Inhibitor

Molecular formula

MW (gr/mole)

Density (gr/cm3) @ 60 F

Solubility in water (gr/l) @ 60 F

Benzoic acid

C7H6O2

122.12

1.32

2.85

Phenanthrene

C14H10

178.23

1.036

1.105E-3

Nonylphenol

C15H24O

220.35

0.953

5.44E-3

Phthalic acid

C8H6O4

166.14

1.593

5.7

Salicylic acid

C7H6O3

138.12

1.443

1.85

Inhibitor structure

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Fig. 1. A schematic sketch of the high pressure-high temperature system.

2.2.3. Onset shift tests The onset of asphaltene flocculation is defined as the point at which the asphaltenes begin to flocculate. It is required to assess the efficiency of remediation means such as altering the operation conditions or selecting asphaltene inhibitors. Several methods such as light transmission (Escobedo and Mansoori, 1995) and visual method (Fotland et al., 1993) are available for determining the onset of asphaltene flocculation. The visual method was used for onset measurement in this work at standard condition (14.7 Pisa and 73 °F). Visual method is based on the utilization of a microscope with light to visually detect the onset of flocculation. (Fotland et al., 1993). The asphaltene deposition onset was determined by titration of the crude oil by n-heptane as asphaltene precipitant (purchased from Merck with purity Z99.3%), and the particle formation was viewed with the help of an optical microscope (Dino-Lite microscope, MODEL AM351BP, zoom in 220X). At first, the proposed oil sample was titrated by precipitant and a specific time was allocated to affect asphaltene stability in each titration step. Then a small amount of titrated oil was observed by microscope and its image was shot with 100  enlargement. The process of oil titration with precipitant (n-heptane) continued until the appearance of asphaltene particles in the oil bulk. The additive effectiveness on inhibit deposition was estimated by comparing the flocculation onset either, with or without the use of additives.

Fig. 2. Applied PVT cell.

reached its asphaltene stability point the PVT cell was shaken for 24 hours and agitated for more 24 h before sampling. While sampling, oil was passed through the 0.5 μm filter and some asphaltene particles were aggregated in filter. The outlet asphaltene concentration is obtained from the IP-143 test. Then a certain ppm of each inhibitor is injected into the above test and sampling was repeated.

2.2.4. Core flood test The experimental setup was designed to conduct these experiments at high pressures and high temperatures matching the reservoir conditions (4500 pisg and 241.7 °F). The schematic of experimental setup is shown in Fig. 3. The procedure is outlined as follows: 1) Injecting the live oil to the core for several pore volumes until the core reaches Swc (connate water saturation) and measuring the effective permeability (Eq. (4)) of oil and connate water saturation after that the recombined oil charges into the transfer vessel from the recombined cell at around 4500 psig.

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Fig. 3. Schematic of core experiments.

The connate water saturation was measured as the live oil was being injected through the core previously saturated with reservoir water (Eqs. (2) and (3)). Live oil injection continued until pure oil (without any water) comes out from the core.

Vc = Vt − Vs

(2)

While: Vc: Volume of connate water Vt: Total volume of water vacuumed inside the core Vs: Volume of water swapped out by oil

Swc =

Vc Vt

(3)

2) The temperature of the oven is set to the reservoir temperature (241 72 ˚F). 3) Before beginning of the test the viscosity of the injection fluid is measured by passing it through the viscometer and recording the differential pressure between two ends of the viscometer until it reaches a constant value. 4) Pressure drop along the core is measured and recorded in the data acquisition, from which the pressure drop at the end of each pore volume of injection is obtained with averaging between last 10 points. During this experiment permeability was calculated from the measured pressure drop along the core through Darcy’s law (Eq. (4)):

q = 14. 297

KA ∆P μ L

(4)

In the above equation, q is the injection flow rate, which is expressed in cm3/s, A is the cross-sectional area of the porous medium in cm2, L is the length of the porous medium in cm, ΔP is the pressure differential in psig, μ is the viscosity of the fluid in cp, and k represents the permeability of the porous medium, which is expressed in Darcy. Fluid viscosity was obtained before each pressure step through the high pressure viscometer. The obtained

viscosities are depicted in Fig. 9. A reduction in viscosity is observed with a decrease in pressure as expected, due to asphaltene deposition. Based on the pressure and viscosity data, the permeability is calculated from Eq. (4). Permeability along the core decreased as the pressure decreased. This confirms the occurrence of asphaltene deposition/precipitation during the natural depletion scheme. Back pressure regulator (BPR) is used in order to support the pressure at the end of porous media which maintain pressure of exiting fluid. The core holder used in these tests is shown in Fig. 4. It contains a stainless steel body, two screwing caps and an internal cylindrical rubber sleeve to cover the core. This vessel can stand pressure up to 5000 psi. Its diameter and length are 10 cm and 38 cm, respectively. The rubber sleeve contains three pressure ports in order to measure the differential pressure difference along the core between different lengths by using two transducers which were used with different pressure ranges of 0–20 psig, 0– 70 psig, 0–1600 psig and with precision of 0.1 psig in order to measure the differential pressure (DP) as shown in Fig. 3.

3. Results and discussion 3.1. Standard condition tests Fig. 5 shows the asphaltene precipitation reduction for all inhibitors using the same oil. As can be seen, all inhibitors up 100 ppm have almost the same behavior. However, when the concentration of inhibitors increased, a major difference was observed for salicylic acid as one of the best inhibitors and phthalic acid as the weakest inhibitor. It is known that the polar head group has different potential to connect to asphaltene particles (Bouts et al., 1995; Rocha et al., 2006; Kelland, 2009). In fact polarity of these groups determines the power of bond. Hence, the effectiveness of salicylic acid is related to the extra hydroxyl functional group (–OH) connected to benzoic ring. These results suggest that reacting and connecting polar group of inhibitor structure to asphaltene particles stabilize the inhibitor-asphaltene system. As a result the existence of functional polar group in benzoic ring has the prominent role in asphaltene stability in solution (Karambeigi et al., 2015). Phthalic acid after salicylic acid is in the second rank till 100 ppm, but in other concentrations it does not have a desirable

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79

Fig. 4. Applied core holder (Core Lab Company).

Asphaltene precipitation reduction of inhibitors (%)

Nonyl Phenol Benzoic Acid

Precipitation Reduction (%)

Precipitation Reduction (%)

Effect of inhibitors on examined oil

Phthalic Acid Salicylic Acid Phenanthrene IR95

Inhibitor PPM

Fig. 5. Precipitation reduction for all inhibitors at standard condition.

effect. In a general manner, we know that there are free monomers in low concentration of inhibitors that can occupy active sites on asphaltene structures and cause the suspension and stabilization of asphaltene particles in solution. Based on the previous studies (León et al., 2001; Solaimany Nazar, 2011), when the concentration of inhibitors increases, the potential of self-association also increases under hydrogenous bonding. In this case, the results suggest that in higher concentrations of phthalic acid, tendency of self-association in inhibitor–inhibitor is more than interaction between inhibitor–asphaltene. Thereupon, inhibitors tend to be deposited and/or precipitated and asphaltene precipitation and/or deposition increases. Self-association causes that the ability of inhibitors to stabilize asphaltenes reduces and it might hinder the performance of inhibitors in high concentrations. Fig. 5 shows the break point of six inhibitors at 100 ppm and 250 ppm. Before the break point, asphaltene reduction is about 43.7% for IR95 and 30.11% for salicylic acid. For concentrations of 250 ppm to 1000 ppm the slope of graph is decreased. In the average, after 250 ppm the amount of asphaltene precipitation reduction is 8.42% only. Although by increasing inhibitors concentration, the amount of asphaltene precipitation is continuously reduced, but applying higher inhibitors concentration might not

(250 ppm) 1-IR95 # 2-salicylic acid # 3-phthalic acid # 4-benzoic acid # 5-nonylphenol # 6-phenanthrene Fig. 6. Asphaltene precipitation reduction by (250 ppm) of each inhibitor (%).

be economical. In this study, IR95 and salicylic acid have the optimum concentration to be 250 ppm and the rest will have 100 ppm as their optimum concentration. However, for comparison between inhibitors efficiency only one concentration should be chosen. Therefore, the approximate optimum concentration of all inhibitors was selected 250 ppm from the standard condition tests in this work. 3.2. Static tests Since the operational parameters such as reservoir pressure and temperature are very distinct from Standard condition and these parameters have an essential effect on inhibitors performance, reservoir condition tests were conducted using HP–HT (around 4500 psig and 241 72 ˚F) setup. Effects of inhibitors on asphaltene precipitation reduction are shown in Fig. 6. Results of these tests reveal that IR95 with 51% asphaltene precipitation reduction has the best efficiency among all inhibitors. IR95 has high polarity and aromatic compositions and acts like natural state of resins, causing to digest asphaltene particles and keep them in solution. Among non-commercial inhibitors, salicylic acid with 34% precipitation reduction has the best efficiency. As can be seen in Figs. 5 and 6, examined inhibitors have the same efficiency at standard and reservoir conditions. At both conditions, salicylic acid after IR95 with 34% asphaltene precipitation reduction has the best efficiency among the tested

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Inhibition capacities of chemical additives

Dilution (mL n-heptane/g oil)

Phenanthrene Nonylphenol Salicylic acid Benzoic acid Phthalic acid IR95 Without Inhibitor Inhibitor/Oil (% Wt/Wt)

Fig. 7. Inhibition capacities of chemical additives.

inhibitors. It might be concluded that pressure and temperature are not determinative on the inhibitors efficiency in static tests. 3.3. Onset shift tests In this work, the flocculation onset was used just as a reference to estimate the additive’s effectiveness to hold the asphaltene within the oil phase. Recent works (Ibrahim and Idem, 2004a, 2004b) have shown that asphaltene precipitation behavior is a function of the crude oil nature or the structural characteristics of the asphaltene molecules, although asphaltene stabilization mechanism is equally a function of the additive's nature. The measured onset values in terms of the volume of n-heptane added per gram of crude oil are shown in Fig. 7. At the onset of flocculation, the asphaltene particles are formed, consequently a rapid change of the absorbance trend is observed. Therefore, the minimum value of the absorption curve is the indicant of flocculation onset. The dotted line shows the flocculation onset without additives and the experimental points over this line show the additive's efficiency to inhibit the asphaltene precipitation as induced by the addition of n-heptane. The enhancement of the onset value of the treated mixture relative to the crude oils with no additives reveals the performance of these compounds on the stabilization of asphaltenes. Pervious works show that both π–π interactions and hydrogen bonding can take place between these asphaltene inhibitors and the asphaltene molecules and the stabilization of the asphaltene is found to depend on the head groups of the amphiphiles (Chang and Fogler, 1993). Östlund et al. (2004) investigated how different amphiphiles react with asphaltene. They found that amphiphiles which contain basic head groups such as –NH2 had the lowest adsorption of the tested compounds. Based on the pervious study (Chang and Fogler, 1993; Kelland, 2009), the results suggest that salicylic acid with an extra hydroxyl group (–OH) on benzoic ring can strengthen the attachment and create effective π–π interaction with the asphaltenes. The hydroxyl group in salicylic acid creates a compact planar phenol structure which seems to make a stable π–π interaction with the asphaltenes. On the other hand, several researchers have further investigated the acid–base interaction between different acidic additives and asphaltenes (Stout, 1983; Auflem et al., 2002; Woodward, 2004; Östlund et al., 2004). Compounds which contained – COOH functional groups are adsorbed better to the asphaltenes than other sub-groups. Previous works indicate that hydrogen bonding between the acidic additives and the asphaltenes basic sites such as amines and hydroxyl groups are more obvious than the bonding of basic additives to acidic sites on the asphaltene molecules (Kelland, 2009). As mentioned above, salicylic acid with the –COOH functional group has a suitable affinity for the asphaltene surface, which seems to work well in stabilizing the asphaltene. However, although phthalic acid has two –COOH

functional groups; it did not have a strong effect on asphaltene stabilization. The benzene group with no hydroxyl groups causes limited π–π interaction. This might enhance the additives ability to be adsorbed on the asphaltene surface to stabilize and prevent them from aggregating. This shows the importance of hydroxyl groups on benzoic ring in the inhibitors structure and their effect on asphaltene stabilization. 3.4. Core flood test During the core flood test, examined inhibitor acts on the pore surface. To realize how a chemical can be a good inhibitor in squeeze treatment, the adsorption process and electrokinetic properties of rock and inhibitor should be analyzed (Zhang and Somasundaran, 2006). For this reason, the surface chemistry of the core is analyzed by the X-ray-photoelectron-spectroscopy (XPS) (PHI Quantera II XPS, Physical Electronics) and the electrokinetic potential in inhibitor is determined by zeta potential tests (Malvern Zetasizer Nano, Model ZEN3600). IR95 as a commercial asphaltene inhibitor is presently known to act on the surfaces of rock by limiting the rate of deposition/ adhesion of asphaltene particles in the Iranian reservoir. Therefore, IR95 Inhibitor is used in dynamic tests. 3.4.1. Pressure measured along the core The pressure difference between two ends of the core in each stage has been recorded using the existing differential pressure (DP) transducers in the system. Fig. 8 indicates the pressure drop curve at both ends of the core in terms of injection volume in the 4500 Psig. The obtained results can be divided into three sections. In the first section, The live oil tends to enter the core; however, it observes resistances from the core. Therefore, the pressure at this point rises up to the entering threshold, and thereafter live oil can enter the core. In the second section, as live oil enters the core, the inlet pressure of the core is decreased. This can be due to the entry of the live oil. By substituting live oil with dead oil, the viscosity of the fluid inside the core, which is a mixture of live oil and dead oil, starts reducing at the first pore volume. Consequently, the pressure drop will be raised at the core’s both ends. In the third section, the pressure drop mildly will increase with low rate. 3.4.2. Variations of oil viscosity due to asphaltene particles forming Before the test started, the viscosity of flowing fluid should be measured accurately in order to convert the recorded pressure data to permeability data. Since the fluid viscosity is changing with Carbonate @ P=4500psig

Pressure Drop (psi)

80

Injected PV Fig. 8. Pressure drop versus injected pore volume of live oil (1 pore volume¼ 16.63 cc).

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81

Damaged Permeability/Initial Permeability

Carbonate @ P=4500 Psig

Injected PV

Fig. 9. Oil viscosity in the required pressures and 241.7 °F.

Fig. 10. Permeability reduction factor versus injected pore volume of live oil.

pressure changes, it is crucial to measure the viscosity of flowing fluid at each step precisely. A capillary viscometer is used for measurement of injected fluid viscosity. The length and diameter of the viscometer is 10 m and 1/16 in., respectively. Viscometer is calibrated by using water (as a fluid with specific viscosity) and KA viscometer coefficient ( L =0.25) is determined. Eq. (5) is derived to determine the viscosity of fluids based on Darcy equation, injection rate and pressure drop along the viscometer. Fluid is flowing through the viscometer with a constant rate and the resulted differential pressure is recorded by a pressure transducer. For accuracy in the viscosity calculation, velocity profile should be fully developed. When fluid first enters a pipe, its flow is not fully developed. Hence, the fluid has to travel a certain distance undisturbed then it becomes fully developed (Streeter and Wylie, 1984). Fluid mechanic computation shows the velocity profile about 20 cm after inlet is fully developed in this study. To ensure this, the pressure drop is measured 1 m after inlet and 1 m before outlet by differential pressure transducers.

∆P μ = 0. 25 Q

(5)

where μ is fluid viscosity in cp, ∆P is pressure difference in psig; and q is injection rate in cc/min. Since the viscosity of oil plays an important role in Darcy Equation, it is measured at different pressures. As we know, if the oil pressure is more than bubble point pressure, the oil viscosity decreases along with pressure reduction (Danesh, 1998). But for crude oils containing a percentage of asphaltene, viscosity reduces along with pressure drop when their initial pressure is higher than bubble point pressure. However, the interesting point here is that the slope of viscosity reduction on viscosity–pressure curve will be less than the asphaltene-free oil. Therefore, this slope reduction causes asphaltene particles in the oil form a colloidal solution. Consequently, their viscosity is varied by pressure drop. Hence, the oil viscosity is measured at the required pressure intervals, as shown in Fig. 9. This quadratic equation is strictly valid only in this range and cannot be used for the extrapolation. 3.4.3. Decreasing of core permeability due to the asphaltene particles deposition in a porous media Using viscosity measured at different pressures and Darcy equation, the core permeability can be obtained. By calculating the core permeability and possessing primary absolute permeability, the ratio of instantaneous permeability to the initial permeability curve can be obtained in terms of injection volume. The noteworthy point about these curves is the determination of the type of the dominant mechanism in the process of permeability reduction. The ratio of current permeability to initial permeability in terms of pore volume at the pressure of 4500 (psig) is shown in

Fig. 10. The first part of the graph is the effect of oil entering the porous media and moving the dead oil. In the second part, the fluid flow into the core is stabilized, and the permeability mildly decreases due to Asphaltene particles deposition in the porous media. 3.4.4. Type of dominant mechanism in the process of permeability reduction Asphaltene precipitation and deposition are defined as a process where asphaltene confines the porous path for fluid to flow in the rock. Based on experiments, three possible mechanisms for asphaltene precipitation and deposition in porous media have been proposed (Wojtanowicz et al., 1987; Minssieux et al., 1997): 1. Surface deposition: adsorption of asphaltene on the surface of the pores causes gradual pore blocking. In this case, permeability is represented by Eq. (6).

K = 1 − A. t Ko

(6)

2. Pore bridging: asphaltene particles mechanically bridge the pore throats. In this case, permeability is represented by Eq. (7).

K = 1 − B. t Ko

(7)

3. Formation of filtration cake: particles accumulate in large pores upstream the blocked pore space. This mechanism begins to take place when a critical fraction of the pore throats has been blocked. In this case, permeability is represented by Eq. (8).

K 1 = Ko 1 + C. t

(8)

where “A”, “B” and “C” are constant in dimension of inverse of time. Type of dominant mechanism in the process of permeability reduction can be determined in each stage in terms of injection time regarding the damaged permeability charts. The permeability reduction process in the 4500 psig shows that surface deposition and/or precipitation of particles and pore bridging are dominant mechanisms in the reduction process. Hence, it seems necessary to develop a model that considers the existence of more than a mechanism simultaneously. At this work a combination of surface deposition of particles and pore bridging models are considered by allocating a share to each of the mechanisms, which is expressed as follows:

K = f .(1 − A . t )2 + (1 − f )(1 − B. t ) Ko

(9)

where “K” is permeability at time “t”, “Ko “ is reference permeability, “t” is time, A and B are constants in dimension of inverse of

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K = a. t 2 + b . t + c Ko

K/Ko

Permeability Reduction Factor vs. Time

Time (min) Fig. 11. Regression of experimental data of damage permeability versus time.

time and “f “ is the share allocated to the surface deposition mechanism. By simplifying the above equation, permeability reduction follows a quadratic parabola in term of time.

K = a. t 2 + b . t + 1 Ko

(10)

where “a” is a constant in dimension of inverse of time squared and “b” is a constant in dimension of inverse of time. Therefore, when surface deposition and pore bridging mechanisms exist simultaneously, the above relationship can justify permeability reduction behavior. Of course, this relationship is valid when the mentioned mechanisms are activated from the beginning of the experiment. Otherwise, it is necessary to correct the relationship to the delay time of start of both mechanisms:

(11)

where “c” is a dimensionless constant. The above relationship can be considered a general relationship to describe permeability reduction in terms of time when both surface deposition and pore bridging mechanisms are simultaneously activated (Bagherzadeh et al., 2014). In Fig. 11, the ratio of the damaged permeability to the initial permeability is illustrated for the injection volumes at the 4500 psig pressure and the regressed line of Eq. (11) is also presented. As can be seen a good match is obtained and the simultaneous existence of both surface deposition and pore bridging mechanisms are confirmed. When core permeability reduction is proved, IR95 inhibitor, which has the best influence on the previous tests, is injected into the core in three stages, and the process of dynamic experiments will be repeated. The three-stage injection includes preflush, main flush, and after flush (Cenegy, 2001). During the preflush phase, asphaltene depositions are completely removed from the surface of the pore space, so that the surface gets ready to interact with the inhibitor (Figs. 12 and 13). The pictures were taken by scanning electron microscope (SEM). During the main flush phase, the inhibitor is injected along with a solvent to affect the porous medium surface. According to the experiments conducted during the inhibitor design, IR95 inhibitor is adsorbed better on the porous media surface than asphaltene particles (Fig. 14). It should be mentioned that length scale can be seen on the bottom right of SEM pictures. For example, the bottom rights part of Fig. 14 shows the text of “500 nm” on it with several dots above it. The “500 nm” is equal to the length between the first dot and the last dot above the text on Fig. 14.

Fig. 12. Pore surface before preflush (SEM test).

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Fig. 13. Pore surface after preflush-Clean porous media (SEM test).

Fig. 14. Adsorption of IR95 on the pore surface after main flush (SEM test).

This property prevents asphaltene particles from depositing again. Like any other chemical reactions, Inhibitor deposition on the surface of the porous space causes undesirable reaction products. During the after flush phase, these compounds go out through the porous media. After the inhibitor is injected, dynamic tests are repeated and the permeability damage process is observed (Fig. 15). The best result that can be gained from the conducted dynamic tests is the adsorption of the inhibitor on the surface of the porous media. Based on Fig. 15, if the inhibitor can replace the asphaltene on the surface of the porous media, the asphaltene particles are no longer able to deposit on the porous media surface so that the surface of the porous space will be left free of asphaltene depositions for a long time. In designing inhibitors, not only is their ability to be absorbed on the porous media surface important, but also their ability to excrete asphaltene particles should be paid attention to. Hence, the inhibitor must be able to excrete asphaltene particles from the porous media surface. Fig. 15 shows that due to high capability of IR95 to be adsorbed on the porous media, the ability of asphaltene particles for deposition on the pore surface is reduced. The pressure drop on both ends of the core in addition to the process of permeability damage to the injection volume and time is shown in Fig. 16. As can be seen, inhibitor injection has prevented asphaltene from re-deposition and/or precipitation on the porous space. Fig. 16 illustrates the effect of IR95 on the pressure drop on both ends of the core. In fact, the pressure is reduced about 100 psig less than injection without inhibitor when 1.5 pore volumes are injected. The same behavior is observed at 1.5 pore volume for damaged permeability data (Fig. 17).

The permeability reduction factor versus time is shown in Fig. 18. The effect of inhibitor addition results in lower reduction of permeability at the point when live oil is injected. Based on the observation of Fig. 18, longer time is taken to have a productivity reduction of the reservoir when inhibitor is injected. By the reduction of permeability, the slope of the reduction factor decreases. It means that it takes longer time for the wells to lose their productivity due to permeability drop resulting from asphaltene deposition. One of the important points, meanwhile, is less washing frequency of the wells per year. For each washing period, the well needs to be closed for two days; which means closing the well during every clearing operation. It is anticipated that the number of clearing times of the wells can be reduced to one-fourth by injecting IR95 inhibitor. The well can produce oil with its extreme predictability, which results in prolonging the life time of the well. The reason for this is high adsorption of the inhibitor on the surface of the porous media. The electrostatic force is a determining factor during the inhibitor adsorption process (Zhang and Somasundaran, 2006). Therefore, the electrokinetics properties of mineral surfaces and chemicals (i.e., the surface charge and zeta potential) are the important parameters for selecting inhibitors for an asphaltene inhibitor injection process. Generally, the sign of the surface charge is the same as that of the zeta potential. The adsorption of cationic chemicals on negatively charged minerals can be reduced by multivalent cations (e.g., Mg2 þ , Ca2 þ , and Al3 þ ) because of the competition of monovalent chemical and multivalent cations on the negative binding sites. Pervious works show the adsorption of the anionic chemicals is usually lower than that of cationic surfactants on silica (SiO2) minerals (Thibaut et al., 2000; Ma et al.,

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Fig. 15. The pore surface 12 PV after inhibitor job (SEM test).

Carbonate @ P=4500 Psig

Pressure Drop (psi)

Damaged Permeability/Initial Permeability

Carbonate @ P=4500psig

Injected PV Fig. 16. Pressure drop versus injected pore volume of live oil (with inhibitor).

2013) because of the negative surface charge of silica (Mannhardt et al., 1993; Kosmulski, 2003) at a pH higher than 4. The surface charge of carbonate minerals (e.g., calcite and dolomite) is positive (Somasundaran and Agar, 1967; Pokrovsky et al., 1999) and it depends on concentrations of potential determining ions (i.e., CO23−, Ca2 þ , and/or Mg2 þ (Heberling et al., 2011)). Concentration of potential determining ions exists in the natural carbonate minerals shown in the XPS analysis results (Table 6). Table 6 reveals the amount of multivalent ions concentration (Ca2 þ , Mg2 þ and Al3 þ ). It is proposed for determining the sign of the surface charge. Examined natural carbonate core consists 84% cations concentration and the sign of surface charge is positive. Generally, the amount of adsorption of a chemical on minerals is expected to be dependent on the surface charge of the mineral. If the surface charge becomes positive, the adsorption of anionic

Injected PV Fig. 17. Permeability reduction factor versus injected pore volume of live oil (with inhibitor).

chemicals is highly expected on the mineral surface and vice versa. The results of zeta potential test in Fig. 19 demonstrate that the IR95 inhibitor is an anionic chemical. High adsorption of anionic chemicals in carbonate reservoirs is expected. This is due to the positive surface charge of carbonate minerals. However, the silica and clay impurities with negatively charged binding sites can yield adsorption of a significant amount of cationic surfactants and maybe cause the high adsorption of cationic surfactants on some natural carbonate minerals. At last, by considering technical and economic parameters, it might be concluded that salicylic acid is not suitable for commercial usages in field scale. It should be mentioned that salicylic acid is expensive and its application in field scale needs great volume of aromatic solvent. Furthermore, when non-commercial

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Fig. 18. Regression of experimental data of damage permeability versus time (with inhibitor).

Table 6 XPS analysis results for carbonate rock. Atomic Composition % Weight Ca Mg Al Other

47% 23% 14% 16%

85

the bonding of basic additives to acidic sites on the asphaltene molecules. The hydroxyl group in inhibitors creates a more compact planar phenol structure which seems to make a stable π–π interaction with the asphaltenes. In this case, salicylic acid creates an effective π–π interaction with the asphaltenes. In addition, the carboxyl functional group and the extra hydroxyl group (–OH) on benzoic ring can strengthen the attachment with the asphaltenes because of their polarity. However, although phthalic acid has two –COOH functional groups; it does not have a strong effect on asphaltene stabilization. The benzene group with no hydroxyl groups causes limited π–π interactions. Results of dynamic test reveals that substitution of asphaltene by inhibitor on pore space can excrete adsorption of asphaltene particles and reduces permeability drop slop. It means that it lessens the frequency of well washing during a year and well can produce oil with its extreme predictability, which results in prolonging the life time of the well. This is due to the high adsorption of the inhibitor on the surface of the porous media. High adsorption of anionic chemicals in carbonate reservoirs is expected. This is due to the positive surface charge of carbonate minerals. The amount of adsorption of chemicals on minerals depends on the surface charge of the mineral.

Acknowledgment The authors would like to acknowledge Tehran Petroleum University of Technology-petroleum Research Center for providing the laboratory facilities of this work.

References

Fig. 19. Zeta potential test results by zeta probe.

inhibitors react with reservoir water, H þ ions are released. This phenomenon causes the accumulation of asphaltene particles around the H þ ions. It should be noted that the cores of asphaltene particles are negatively charged. Accumulation of asphaltene particles around the H þ ions can increase asphaltene deposition.

4. Conclusions In this work, several chemicals were screened and selected as potential asphaltene precipitation inhibitors and/or as potential asphaltene deposit solubilizers. Results show that salicylic acid after inhibitor (IR95) with 34% asphaltene precipitation reduction has the best efficiency among the tested inhibitors. It is also confirmed that the way inhibitors with high polarity and aromatic compositions act is similar to that of natural state of resins which leads to the digestion of asphaltene particles and keep them in solution. Compounds with –COOH functional groups react better with asphaltenes than other sub-groups. This indicates that hydrogen bonding between the acidic additives and the asphaltenes basic sites such as amines and hydroxyl groups are more obvious than

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