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Screening of inhibitors for remediation of asphaltene deposits: Experimental and modeling study
Accepted Manuscript Screening of inhibitors for remediation of asphaltene deposits: Experimental and modeling study Mehdi Madhi, Riyaz Kharrat, Touba Hamoule PII:
S2405-6561(16)30172-9
DOI:
10.1016/j.petlm.2017.08.001
Reference:
PETLM 155
To appear in:
Petroleum
Received Date: 17 September 2016 Revised Date:
27 May 2017
Accepted Date: 4 August 2017
Please cite this article as: M. Madhi, R. Kharrat, T. Hamoule, Screening of inhibitors for remediation of asphaltene deposits: Experimental and modeling study, Petroleum (2017), doi: 10.1016/ j.petlm.2017.08.001. This is a PDF file of an unedited manuscript that has been accepted for publication. As a service to our customers we are providing this early version of the manuscript. The manuscript will undergo copyediting, typesetting, and review of the resulting proof before it is published in its final form. Please note that during the production process errors may be discovered which could affect the content, and all legal disclaimers that apply to the journal pertain.
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Screening of Inhibitors for Remediation of Asphaltene Deposits: Experimental and Modeling
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Study
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Mehdi Madhi†, Riyaz Kharrat‡, Touba Hamoule§
† Department of Petroleum Engineering, Petroleum University of Technology, Ahwaz, Iran ‡ Petroleum Research Center, Petroleum University of Technology, Tehran, Iran
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§ Department of Basic Science, Petroleum University of Technology, Ahwaz, Iran
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ABSTRACT
One of the most severe problems during production from heavy crude oil reservoirs is the
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formation of Asphaltene precipitation and as a result deposition in the tubing, surface facilities and near wellbore region which causes oil production and permeability reduction in addition to rock wettability alteration in the reservoir. So one of the economical ways to prevent such
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incidents is using the chemicals which are called Asphaltene inhibitor.
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In this study, the influence of three commercial inhibitors, namely; Cetyl Terimethyl Ammonium Bromide (CTAB), Sodium Dodecyl Sulfate (SDS), Triton X-100 and four noncommercial (Benzene, Benzoic Acid, Salicylic Acid, Naphthalene) inhibitors on two Iranian crude oils were investigated. This study extends previous works and contributes toward the better understanding of interactions between asphaltene and inhibitor. Effect of functional groups and
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structure of inhibitors on Asphaltene precipitation were studied and it seems clear that the nature and polarity of Asphaltene (structure and amount of impurities presented) has a significant impact on the selection of inhibitors. Asphaltene dispersant tests and Core flood tests were
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designed for evaluation of inhibitors in static and dynamic conditions. The results revealed
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distinguished mechanisms for asphaltene solubilization/dispersion (such as hydrogen bonding, ππ interaction and acid-base interaction) and influence of additional side group (OH) on inhibition power of inhibitor.
During the experiments, it was found that increasing inhibitor concentration may lead to
the self-assembly of inhibitor and declining of asphaltene stabilization. So, finding optimum concentration of inhibitor with high efficiency and available at a reasonable price is very important. The results suggest that 600 ppm of CTAB and 300 ppm of SDS were approximately
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optimum concentrations for the studied crude oils. One of the most important findings that differ from previous studies is the revelation of the mechanism behind the SDS/Asphaltene behavior in various concentrations of inhibitor. Effect of chosen inhibitors on Asphaltene precipitation and
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consequently deposition in porous media was studied, and then experimental data were modeled for evaluation of permeability impairment mechanisms. Permeability revived after inhibitor squeezing and cake formation mechanism played an important role in permeability reduction
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before and after treatment in porous media. The findings can also be applied to prediction of future behavior of reservoirs in oil field scale and evaluation of formation damage in the
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different period of production if needed any treatment process.
KEYWORDS
1. INTRODUCTION
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Asphaltene, Precipitation, Deposition, Inhibitor, Permeability reduction
By reduction of conventional oil, oil companies have turned to production from heavy oil
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reservoirs. Asphaltene precipitation and deposition are the well-known problems during
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production. Asphaltene is the heaviest and the most polar fraction of crude oil which is soluble in aromatic solvents but insoluble in normal alkanes[1]. Formation of Asphaltene happens when disruption of thermodynamic equilibrium of crude oil has led to heavy organics aggregation. Asphaltene deposition is influenced by several factors like pressure-temperature reduction[2], CO2 injection[3], acidizing and stimulation techniques[4] and etc. plugging of tubing and surface facilities, permeability reduction[5] (permeability impairment) and wettability alteration[6] are results of asphaltene deposition.
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For prevention of such incidents, chemical materials with different structure and functional groups called asphaltene inhibitors adsorb on asphaltene surface and consequently delay the asphaltene aggregation, so asphaltene kept in solution[7]. Association of asphaltene sheets by
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sharing π-electrons of aromatic rings[8], hydrogen bonding of functional groups (OH, NH, COOH)[9] and acid-base interaction caused by heteroatoms (N, O, and S) and organometallic constituents (Ni, V, Fe) in crude oil[10] were the important and confirmed phenomenon.
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However, Mechanisms of asphaltene aggregation and stabilization are the same. Many researchers have perused the stabilization and phase behavior of asphaltene in statics mode and
received increasing attention.
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porous media. The research on asphaltene deposition and inhibition/ peptization has thus
Some of these attempts point to the impact of functional groups and inhibitor/dispersant structure in retardation of asphaltene aggregation and flocculation[11-17], mechanisms of
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inhibitor adsorption on asphaltene molecules[18, 19], self-association of asphaltene and inhibitors[20, 21], usage of vegetable oils as inhibitors[22] and reduction of wettability alteration[23, 24]. Some considerable and influential related studies stated in more detail in the
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following.
González et al.[11] have investigated the dispersion of asphaltene by different oil soluble
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amphiphiles (Alkylphenols with different degree of ethoxylation) and found that the asphaltene adsorption on mineral surfaces have been reduced by addition of amphiphiles. Chang et al.[12] have studied the efficiency of series of asphaltene inhibitors by means of X-ray scattering technique, precipitation and dissolution experiments. Influence of chemical structure including polarity of head groups, the length of alkyl tails and existence of extra polar group was studied. It was shown that the strong inhibition of asphaltene is due to the interaction between the acidic
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head of inhibitors and asphaltene. It was also found the inhibition efficiency is in the order: DBSA>NP>NBDO>NB. In a similar study, Boukherissa et al.[13] have studied the mechanism of asphaltene inhibition using ionic liquids. Results of their research demonstrated the
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significance of the length of alkyl chain and boronic acid presence in inhibitor structure. Ramos et al.[14] have utilized viscometric method[25] in order to study the effects of some inhibitors on the onset of asphaltene precipitation. The Behavior of asphaltene aggregation in n-pentane
confirmed by performing surface tension measurements.
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insoluble/ model systems was investigated and the existence of critical micelle concentration
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Al-Sahhaf et al.[15] have performed n-heptane titration of crude oil in presence of inhibitors for studying the onset of asphaltene precipitation. Effectiveness of inhibitors is in following order: DR > DBSA > NP > R > T > DO. Additionally, effect of acidic base interaction confirmed and experimental data were in good agreement with predicted amounts of inhibitors which
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calculated by micellization model. Shadman et al.[16] have examined the effect of series of inhibitors on the onset of asphaltene precipitation in Iranian oilfield. This study indicated that the inhibitor which has the acidic group like sulphonic acid will perform better inhibition.
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Marcano et al.[17] studied the effect of three chemical additives on asphaltene aggregates with NIR-Laser scattering and found out DBSA is more effective than others. Leon et al.[18, 19]
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compared the adsorption isotherm of nonyl phenol, nonylphenolic resin and native resin on asphaltene particles. Conclusions revealed that native resin penetrates in asphaltene molecules but the other inhibitors adsorb in two stages. In another study, adsorption of three amphiphiles on asphaltene molecules was studied and obtained data through adsorption of amphiphiles on nheptane/asphaltene mixture shown that there are two-step adsorptions where amphiphile
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molecules adsorbed on asphaltene surface and in the second step, amphiphile hemimicelles on the solid/liquid interface formed. Barcenas et al.[20] have performed a set of vapor pressure osmometry experiments and
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modeling study for evaluating the inhibition of asphaltene agglomeration/precipitation by using three inhibitors. It was concluded that self-association of inhibitor molecules reduced inhibitor adsorption on the active site of the asphaltene molecules, as a result the reduction in inhibitor
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efficiency. Rogel[21] stated the influential of the inhibitor on asphaltene aggregation and free energy of formation of asphaltene and inhibitor by molecular thermodynamic model. This model
optimum concentration of inhibitor.
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confirms that addition of more inhibitor will not change the size of asphaltene and there is an
This study differs from previous researches and contributes to our understanding of inhibitors effect on asphaltene deposition mechanisms in porous media. This study focuses on the
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mechanisms of asphaltene precipitation and deposition with the presence of inhibitors in porous media. Cationic (polar head group with the positive charge), anionic (polar head group with the negative charge), nonionic (without production of ions in solution) and four noncommercial
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inhibitors were used for investigation of the effect of functional groups and mechanisms of
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asphaltene stabilization.
2. MATERIALS AND METHODS 2.1. Materials
Two Iranian crude oils with different asphaltene contents and oAPI were used and the amount of asphaltene were determined by means of IP143[26]. Other fractions of crude oil separated using ASTM D4124[27].Two cylindrical outcrop carbonate samples (no clay present) from
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asmari formation have provided. Properties of crude oils and outcrop cores are summarized in Table 1 and Table 2 respectively. Table 1: Properties of crude oils
?? (gr/cm3)
µ (cp)
Oil A
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0.9821
Oil B
19
0.8823
A1 A2
Asphaltene
(wt%)
(wt%)
Table 3
57.8
26.5
6.9
8.8
Table 4
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62
5
11
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(wt%)
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Type of rock
Resin
(wt%)
Table 2: Properties of core samples
Cores
Saturate Aromatic
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oil
°API
Crude
Kw
L
D
(%)
(cm)
(cm)
limestone
12.5
21.9
6.941
3.698
limestone
16.7
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6.893
3.712
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(md)
The densities of the oils were measured using ANTON-PAAR model DMA 45 densitometer. The viscosities of the oils were measured using Brookfield DV-II+ at various Temperatures.
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Table 3 and Table 4 show the variation of viscosities with temperatures. Table 3: Viscosities at different temperatures (crude oil A)
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T(°C) µ (cp)
511.93
40
50
60
70
209.3
114.57
68.504
44.674
Table 4: Viscosities at different temperatures (crude oil B)
T(°C)
40
45
50
µ (cp)
35.32
28.78
24.26
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n-hexane, n-butanol, Toluene, and cyclohexane were purchased from Merck and their
Table 5: Solvents properties
Materials
MW
??
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properties are shown in Table 5.
BP 3
(gr/cm )
(°C)
n-hexane
86.17
0.66
69
n-Butanol
74.12
0.81
116
Toluene
92.14
0.87
110
Cyclohexane
84.16
0.78
81
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(gr/mole)
Synthetic brine used in these experiments was made of 22%wt/w potassium chloride. Simple synthetic brine was used with the aim of reducing possibilities of chemical reactions among the rock and inhibitors.
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Four non-commercial and three commercial inhibitors were used and their properties and structure were shown in Table 6 and Figure 1. SDS (Sodium Dodecyl Sulfate) and CTAB (Cetyl Terimethyl Ammonium Bromide) solutions were made in the mixture of water/n-butanol and n-
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Merck.
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butanol, respectively. Other inhibitors were prepared in toluene. All of the inhibitors provided by
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Table 6: Properties of inhibitors
BP (°C)
S (gr/L)
Benzene
78.11
0.878
80.1
Soluble in toluene
Naphthalene
128.17
1.14
218
30.2 gr/L in toluene
Benzoic acid
122.12
1.27
249
Salicylic acid
138.12
1.44
211
Slightly soluble in toluene
CTAB
364.45
0.39
250
37gr/L in H2O
SDS
288.372
1.1
288
Triton x-100
647
1.07
>200
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(gr/mole)
?? (g/cm3)
10.6 gr/L in toluene
100 gr/L in H2O
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MW
freely Soluble
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Inhibitors
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Figure 1: Structure of inhibitors
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2.2. Experimental Procedures 2.2.1 Asphaltene Dispersant Test Asphaltene dispersant test is proposed by Maneck[28] and used for evaluation of inhibitor
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the experimental equipment is given in Figure 2.
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efficiency in the static condition, but some steps of procedure were modified[29]. A diagram of
Figure 2: Schematic of asphaltene Dispersant Test
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Crude oil was diluted with toluene (1:1 V/V) since it is difficult to work with viscous oil, also accuracy and reproducibility of tests will increase.10 ml of n-hexane was added to each centrifuge tubes. The desired concentration of crude oil solution was added to the centrifuge
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tubes. The centrifuge tubes were shaken for 2 minutes to agitate the asphaltene stability, then the centrifuge tubes were left for 30 minutes in the water bath of 40° in order to let the asphaltenes precipitate. They were then centrifuged at 1500 rpm (rotation per minute) for 2 minutes and clear
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brown supernatant phase without asphaltene was formed above deposited asphaltene. The deposits level was evaluated and noted DBlank. Different dosages of inhibitors added to 10 ml of
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n-hexane and above procedure repeated again and noted as DTreatment . The amount of asphaltene reduction measured and Efficiency of inhibitors in each concentration calculated by means of below equation:
(1)
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− % = ( ) × 100
2.2.2 Inhibitor Efficiency Evaluation Test in Porous Media
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The most important part of work is the evaluation of inhibitors that are tested in static tests in reservoir conditions. The optimum concentration of inhibitors is determined in static mode and
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evaluated in porous media. All tests were carried out at a temperature of 90℃ and injection rate of 0.2 ml/min. overburden pressure was kept at 3500 psi. Schematic diagram of the Apparatus shown in Figure 3. The setup consisted of the oven with temperature controller, syringe pumps, six transfer vessels, stainless steel core-holder, sample collector, Data acquisition system and a differential pressure transmitter. The pressure difference between inlet and outlet of the core is recorded by Data Acquisition system and converted to permeability through Darcy equation. The following procedures are suggested by Minsseiux[30].
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1. Injection of brine (220000 ppm KCl) until complete saturation of core samples and measurement of water permeability. 2. Injection of cyclohexane until reaching Swi and measurement of cyclohexane permeability.
injected to the core.
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3. Injection of crude oil at the constant rate and recording permeability at each pore volume
inhibitor to core samples with soaking time of 24 hours.
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4. Squeezing inhibitor slug at the optimum concentration (determined from dispersant tests) of
5. Again injection of crude oil and continuous recording of oil permeability.
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6. Comparison of crude oil permeability before and after inhibitor injection.
Figure 3: Schematic of Inhibitor Efficiency Evaluation Test
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3. MODELING Several mathematical models for plugging by particles movement have been proposed for prediction of permeability impairment[31, 32]. By analysis of experimental data of several
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coreflood experiments and different crude oil, new formula based on Wojtanowicz et al.[33] model was presented by Minsseuix[5].
Gradual pore blocking occurs when colloidal particles precipitated and deposited in the whole
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core with accessible surfaces of pore framework. Then the permeability reduction is given by: = 1 − ( )
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(2)
Where is the permeability during fluid injection, is the initial permeability and is the injected pore volume.
Plugging of pore throat or redirection of flow to the larger pore which can cause new pore = 1 − ( )
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blockage is called Single pore blocking. Then the permeability response to this mechanism is: (3)
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In-situ cake formation happens when intensive plugging caused by in-situ filtration cake or bridging of trapped particles. The corresponding permeability reduction becomes:
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= 1 + !( )
(4)
Where , and ! are constant parameters and calculated by data fitting.
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4. RESULTS AND DISCUSSIONS 4.1 Blank Test Blank tests were performed on to crude oils and nine runs were made to decide which
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concentration should be used for dispersant tests. As shown in Figure 4, by the addition of diluted crude oil, asphaltene precipitation increases. It can be concluded that the higher precipitation, higher the deposition. The 0.8 ml and 0.6 ml crude oil solutions were chosen for
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dispersant test.
Figure 4: asphaltene deposition for Blank Test
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4.2 Dispersant Test So after determination of the right amount of diluted crude oil for the Blank test, the efficiency
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of each inhibitor in each crude oil was calculated and as seen in Figure 5 and Figure 6, the higher
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inhibitor concentration, higher the efficiency in asphaltene reduction.
Figure 5: Inhibitors efficiency in oil A
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Figure 6: Inhibitors efficiency in oil B
By comparison of the effect of CTAB inhibitor between oil A and B in Figure 7 concluded that oil A had more negatively group in its structure than oil B.
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SDS reduced the asphaltene to a certain amount (an optimum amount) and after addition of
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more inhibitor, the asphaltene deposits increased to a fixed amount (Figure 8). In both oil A and oil B at 300 ppm of SDS, asphaltene reached to its minimum amount 0.4 ml and 0.38 ml respectively. This suggests that asphaltene of oil B having more positively charged functional group comparison to asphaltene of oil A, so SO3 group can make the attachment with asphaltene and stabilize them. The reason for increasing of asphaltene after 300 ppm was the usage of water as the solvent. Water molecules could attract to asphaltene molecules by means of hydrogen bonding, so as the inhibitor concentration increased, the amount of water also increased and after
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300 ppm, hydrogen bonding slightly weakened the effect of acid-base interaction (SO3) and
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small amount of asphaltene produced in both oils.
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Figure 7: effect of CTAB in both crude oils
Figure 8: Effect of SDS in both crude oils
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As shown in Figure 9, triton x-100 performed stronger inhibition in oil A than oil B. The evidence suggests that the polar group of the hydrocarbonic chain which causes interaction
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between bulk crude oil and asphaltene were less in oil B than oil A.
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Figure 9: Effect of triton x-100 in both crude oils
The results of the effect of OH and COOH (carboxylic acid) functional groups are illustrated in
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Figure 10 and Figure 11. It was concluded that in both crude oils, salicylic acid had greater
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inhibition strength than benzoic acid. The reason behind this phenomenon is the attachment of extra hydroxyl group to salicylic acid. In both crude oils, benzoic acid performed slightly better inhibition than benzene because of the presence of carboxyl (COOH) group which attached to the benzene ring. Benzene rings can dissociate the asphaltenes by π-π interactions and addition of Hydroxyl and Carboxyl groups can empower asphaltenes stabilization with the formation of hydrogen bonding.
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Figure 10: Comparison of salicylic acid, benzoic acid and benzene in oil A
Figure 11: Comparison of salicylic acid, benzoic acid and benzene in oil B
As seen in Figure 12 and Figure 13, benzene has higher inhibition power than naphthalene in oil A but in oil B, naphthalene at low concentration lowered amount of asphaltene. These
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phenomena can be attributed to the molecular structure of asphaltene in oil B. Contrary to expectations, double benzene rings with double π-π interaction must perform better inhibition than the mono benzene ring, but Because of higher self-association of naphthalene moleculesin
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higher concentrations, the efficiency of naphthalene for asphaltene stabilization has reduced.
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Figure 12: Comparison of naphthalene and benzene in oil A
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Figure 13: Comparison of naphthalene and benzene in oil B
The reason of the constant amount of asphaltenes in each asphaltene dispersant test and some inhibitors concentrations were that in low concentrations, there are monomers that can occupy
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active sites of asphaltene molecules and made them stabilize, but by increasing inhibitor concentration, self-association of inhibitors occurs and the amount of asphaltene will not change from determined concentration. Similar findings were reported by Barcenas et al. study which is
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brought in the literature[20]. These static tests have shown that the CTAB inhibitor with the
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concentration of 600 ppm in oil A and SDS inhibitor with the concentration of 300 ppm in oil B were the optimum concentration for squeezing in reservoir condition. 4.3 Inhibitor Efficiency Evaluation Test in Reservoir Condition 4.3.1 Efficiency of Inhibitor on Oil A / A1 The initial cyclohexane permeability was 9.04 md at residual water saturation (Swi=30%). The first injection of oil A was performed and the amount of permeability reduced to 2.56 md and resulted in an oil permeability reduction of 71%. Then slug of n-Butanol/CTAB solution at
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optimum concentration was squeezed according to the previously procedure described. During the second injection of crude oil, the initial oil permeability restored to 9.5 md, followed by stabilization trend at 2.93 md compared with 2.56 md reached at the end of previous crude oil
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injection as shown in Figure 14. The trend of permeability reduction has maintained and
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plugging resumed.
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Figure 14: Effect of CTAB solution on oil A in Asmari carbonate
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4.3.2 Efficiency of Inhibitor on Oil B / A2 The initial permeability of cyclohexane was 7.68 md at residual water saturation (Swi=32%) and after the first injection, initial permeability reduced to 4.16 md and oil permeability reduction of 45.8 %. then a slug of n-Butanol/water/SDS (inhibitor) was squeezed at the optimum concentration. During the second injection initial Permeability restored to 14.86 md. Figure 15 shows permeability evolution during second injection and after the squeeze of inhibitor a sharp increase in oil permeability was obtained.
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Figure 15: Effect of SDS solution on oil B in Asmari carbonate
4.4 Modeling of Experimental Data
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Experimental data of first and second injections were fitted in specific equations for determination of dominant mechanism. Plotting of K/Ki versus PV injected (Figure 16 and
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squeezing.
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Figure 17) shows the major mechanisms govern the porous media before and after inhibitor
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Figure 16: Permeability reduction models for Oil A/A1
Figure 17: Permeability reduction models for Oil B/A2
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Permeability reduction models were studied and best model was chosen. The fitting parameters
Table 7: Results of modeling of asphaltene deposition
Squeezing Stage
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and results of permeability model before and after squeezing brought in Table 7.
Injected
Dominant
Fitting
pore volume
mechanism
parameter
R-square
Coreflood tests
Oil A/A1
0 - 1.54
Cake forming
2.204
0.8315
squeezing
Oil B/A2
0 – 0.99
Cake forming
3.035
0.3421
After inhibitor
Oil A/A1
squeezing
Oil B/A2
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Before inhibitor
Cake forming
1.727
0.9871
0 – 1.04
Cake forming
3.282
0.9794
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0 – 1.81
Comparison of experimental data with proposed models indicated that according to equation 4 in first crude oil injection in both A1 and A2 cores, the dominant mechanism was cake formation.
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Even after inhibitor squeezing process, cake formation happened again. In oil B/A2 and oil A/A1 first coreflood tests, poor fitting is caused by quick entrapment of asphaltene in cores and
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resulted in drastic permeability reduction. The tests are repeated twice for data validation and similar results were obtained. The schematic of asphaltene deposition and permeability impairment in presence of inhibitor are presented in Figure 18. During the injection of asphaltenic crude oil, asphaltene particles are deposited on pore surface and pore throat. This phenomenon influenced by factors like electrostatic charge differences between asphaltene and formation rock, pore structure and composition of particles. asphaltene particles are reduced the cross-sectional area of the pore and incoming particles accumulated not only in pore throat, but
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also within all pore bodies. Another layer of asphaltene particles deposit on former layer and formation of internal filter cake happens. After that, Inhibitor is squeezed to the porous media and adsorbed on asphaltene molecules through interaction between their polar head group.
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Dissociated and stabilized asphaltene particles removed from porous media. In the second injection of asphaltenic crude oil, the presence of inhibitors resulted in the reduction of asphaltene precipitation and deposition, so the rate of permeability impairment in this stage was
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much lower than the first injection and permeability changes were evidence of this claim that
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inhibitors acted as resins and peptized the asphaltene molecules in the fluid phase.
Figure 18: Schematic of effect of inhibitor on permeability impairment in porous media a) Surface deposition and pore-throat plugging b) Permeability reduction caused by In-situ cake formation in first crude oil injection c) Inhibitor squeezing and Adsorption of inhibitors on asphaltene molecules d) Removing dissociated and stabilized asphaltene from pore network e) Presence of inhibitor in pore
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network f) Stabilization of asphaltene molecules in second injection g) Improved permeability caused by reduction in asphaltene deposition
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5. CONCLUSIONS This study has demonstrated that due to diversity in the structure of asphaltene, different inhibitors are needed and according to the asphaltene dispersant tests (static tests), asphaltene of oil B has more positively and lesser negatively charged functional groups than asphaltene of oil
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A. comparison of inhibitors has shown that the strength of inhibition mechanisms were in the
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following order: Acid-base interaction> hydrogen bonding> π-π interaction. The investigations revealed that 600 ppm of CTAB and 300 ppm of SDS are the optimum concentration for oil A and oil B respectively, but by reviewing all the inhibitors, it was concluded that at high concentration of inhibitors, self-association of inhibitor monomers occurs and interaction between inhibitors and asphaltene are reduced. So as a result the amount of asphaltene then
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remains constant. The structure of inhibitors reflects the impact of functional groups (π-π interactions, acid-base interaction and hydrogen bonding) on asphaltene stabilization. Through the experiments; it was found that existence of hydroxyl (OH) and carboxyl (COOH) groups in
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the structure of benzene rings enhanced the asphaltene inhibition power.
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This study differs from previous researches and contributes to our understanding of inhibitors effect on asphaltene deposition mechanisms in porous media. Modeling of experimental data has indicated that a cake formation mechanism is dominant in the entire porous media before and after inhibitor squeezing. Inhibitors dissolve/stabilize the asphaltene deposits and delay asphaltene deposition in the second injection, so permeability revived. The findings can also be applied to prediction of future behavior of reservoirs in oil field scale and evaluation of formation damage in different period of production if needed any treatment process.
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ACKNOWLEDGEMENTS The authors would like to thank the Research Department of Ahwaz Petroleum University and
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National Iranian South Oil Company (NISOC) for supporting this study.
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NOMENCLATURE
??
Density
'( +!)*
Viscosity
cp
-
Porosity
%
L
Length
D
Diameter
MW
Molecular Weight
S
Solubility
BP
Boiling Point
Inhibitor Efficiency
Amount of asphaltene
Amount of asphaltene
Permeability
Water Permeability Initial Permeability
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!)
'( +)./0 '( +1 ℃ %
)/
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3
in dispersant test
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in blank test
!)
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µ
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Temperature
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℃
T
Pore Volume injected
)/
)2 )2 )2 )/
constants which are
a, b, c
calculated by data fitting
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Sodium Dodecyl Sulfate
CTAB
Cetyl Trimethyl Ammonium Bromide
OH
Hydroxyl group
COOH
Carboxyl group
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SDS
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ABBREVIATION
Degree of gravity (American petroleum API
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institute)
Potassium chloride
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KCl
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7.
8. 9. 10. 11. 12.
13. 14.
15.
16.
17.
18.
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6.
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Yen, T.F. and G.V. Chilingarian, Asphaltenes and asphalts, 2. 2000: Elsevier. Hirschberg, A., et al., Influence of temperature and pressure on asphaltene flocculation. Society of Petroleum Engineers Journal, 1984. 24(03): p. 283-293. Choiri, M., Study of CO2 effect on asphaltene precipitation and compositional simulation of asphaltenic oil reservoir. 2010. Jacobs, I. and M. Thorne. Asphaltene precipitation during acid stimulation treatments. in SPE Formation Damage Control Symposium. 1986. Society of Petroleum Engineers. Minssieux, L. Core damage from crude asphaltene deposition. in International Symposium on Oilfield Chemistry. 1997. Society of Petroleum Engineers. Crocker, M. and L. Marchin, Wettability and adsorption characteristics of crude-oil asphaltene and polar fractions. Journal of petroleum technology, 1988. 40(04): p. 470474. Mansoori, G.A. Modeling and prevention of asphaltene and other heavy organic deposition in oil wells. in SPE Latin America/Caribbean Petroleum Engineering Conference. 1994. Society of Petroleum Engineers. Yen, T., Structure of petroleum asphaltene and its significance. Energy Sources, Part ARecovery, Utilization, and Environmental Effects, 1974. 1(4): p. 447-463. Nahid Siddiqui, M., Infrared study of hydrogen bond types in asphaltenes. Petroleum science and technology, 2003. 21(9-10): p. 1601-1615. Paul Maruska, H. and B.M. Rao, The role of polar species in the aggregation of asphaltenes. Fuel science & technology international, 1987. 5(2): p. 119-168. González, G. and A. Middea, Peptization of asphaltene by various oil soluble amphiphiles. Colloids and Surfaces, 1991. 52: p. 207-217. Chang, C.-L. and H. Fogler. Asphaltene stabilization in alkyl solvents using oil-soluble amphiphiles. in SPE International Symposium on Oilfield Chemistry. 1993. Society of Petroleum Engineers. Boukherissa, M., et al., Ionic liquids as dispersants of petroleum asphaltenes. Energy & Fuels, 2009. 23(5): p. 2557-2564. Ramos, A., et al. Reversibility and inhibition of asphaltene precipitation in Brazilian crude oils. in Latin American and Caribbean Petroleum Engineering Conference. 1997. Society of Petroleum Engineers. Al-Sahhaf, T.A., M.A. Fahim, and A.S. Elkilani, Retardation of asphaltene precipitation by addition of toluene, resins, deasphalted oil and surfactants. Fluid Phase Equilibria, 2002. 194: p. 1045-1057. Shadman, M.M., et al., An Investigation of the Effect of Aromatic, Anionic and Nonionic Inhibitors on the Onset of Asphaltene Precipitation. Journal of Oil, Gas and Petrochemical Technology, 2014. 1: p. 17-28. Marcano, F., et al., Evaluation of the Chemical Additive Effect on Asphaltene Aggregation in Dead Oils: A Comparative Study between Ultraviolet–Visible and NearInfrared-Laser Light Scattering Techniques. Energy & Fuels, 2015. 29(5): p. 2813-2822. Leon, O., et al., The influence of the adsorption of amphiphiles and resins in controlling asphaltene flocculation. Energy & Fuels, 2001. 15(5): p. 1028-1032.
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León, O., E. Contreras, and E. Rogel, Amphiphile adsorption on asphaltene particles: adsorption isotherms and asphaltene stabilization. Colloids and Surfaces A: Physicochemical and Engineering Aspects, 2001. 189(1): p. 123-130. Barcenas, M., et al., Study of medium effect on asphaltene agglomeration inhibitor efficiency. Energy & Fuels, 2008. 22(3): p. 1917-1922. Rogel, E., Effect of Inhibitors on Asphaltene Aggregation: A Theoretical Framework†. Energy & Fuels, 2010. 25(2): p. 472-481. Junior, L.C.R., M.S. Ferreira, and A.C. da Silva Ramos, Inhibition of asphaltene precipitation in Brazilian crude oils using new oil soluble amphiphiles. Journal of Petroleum Science and Engineering, 2006. 51(1): p. 26-36. Piro, G., et al., Asphaltene adsorption onto formation rock: An approach to asphaltene formation damage prevention. SPE Production & Facilities, 1996. 11(03): p. 156-160. Amro, M.M., Effect of scale and corrosion inhibitors on well productivity in reservoirs containing asphaltenes. Journal of Petroleum Science and Engineering, 2005. 46(4): p. 243-252. Escobedo, J. and G.A. Mansoori, Viscometric principles of onsets of colloidal asphaltene flocculation in paraffinic oils and asphaltene micellization in aromatics. SPE Production & Facilities, 1997. 12(02): p. 116-122. Standard, A., D6560-12. Test Method for Determination of Asphaltenes (Heptane Insolubles) in Crude Petroleum and Petroleum Products, ASTM International, West Conshohocken, PA, 2012. International, A., ASTM D4124-01. Standard Test Methods for Separation of Asphalt into Four Fractions, 2001, ASTM International West Conshohocken, PA. Manek, M. Asphaltene dispersants as demulsification aids. in SPE International Symposium on Oilfield Chemistry. 1995. Society of Petroleum Engineers. Abrahamsen, E.L., Organic flow assurance: Asphaltene dispersant/inhibitor formulation development through experimental design. 2012. Minssieux, L. Removal of asphalt deposits by cosolvent squeeze: mechanisms and screening. in SPE Formation Damage Control Conference. 1998. Society of Petroleum Engineers. Shutong, P. and M. Sharma, A model for predicting injectivity decline in water-injection wells. SPE Formation Evaluation, 1997. 12(03): p. 194-201. Wang, S. and F. Civan. Productivity decline of vertical and horizontal wells by asphaltene deposition in petroleum reservoirs. in SPE international symposium on oilfield chemistry. 2001. Society of Petroleum Engineers. Wojtanowicz, A., Z. Krilov, and J. Langlinais. Study on the effect of pore blocking mechanisms on formation damage. in SPE Production Operations Symposium. 1987. Society of Petroleum Engineers.
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S2405-6561(16)30172-9
DOI:
10.1016/j.petlm.2017.08.001
Reference:
PETLM 155
To appear in:
Petroleum
Received Date: 17 September 2016 Revised Date:
27 May 2017
Accepted Date: 4 August 2017
Please cite this article as: M. Madhi, R. Kharrat, T. Hamoule, Screening of inhibitors for remediation of asphaltene deposits: Experimental and modeling study, Petroleum (2017), doi: 10.1016/ j.petlm.2017.08.001. This is a PDF file of an unedited manuscript that has been accepted for publication. As a service to our customers we are providing this early version of the manuscript. The manuscript will undergo copyediting, typesetting, and review of the resulting proof before it is published in its final form. Please note that during the production process errors may be discovered which could affect the content, and all legal disclaimers that apply to the journal pertain.
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Screening of Inhibitors for Remediation of Asphaltene Deposits: Experimental and Modeling
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Study
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Mehdi Madhi†, Riyaz Kharrat‡, Touba Hamoule§
† Department of Petroleum Engineering, Petroleum University of Technology, Ahwaz, Iran ‡ Petroleum Research Center, Petroleum University of Technology, Tehran, Iran
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§ Department of Basic Science, Petroleum University of Technology, Ahwaz, Iran
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ABSTRACT
One of the most severe problems during production from heavy crude oil reservoirs is the
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formation of Asphaltene precipitation and as a result deposition in the tubing, surface facilities and near wellbore region which causes oil production and permeability reduction in addition to rock wettability alteration in the reservoir. So one of the economical ways to prevent such
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incidents is using the chemicals which are called Asphaltene inhibitor.
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In this study, the influence of three commercial inhibitors, namely; Cetyl Terimethyl Ammonium Bromide (CTAB), Sodium Dodecyl Sulfate (SDS), Triton X-100 and four noncommercial (Benzene, Benzoic Acid, Salicylic Acid, Naphthalene) inhibitors on two Iranian crude oils were investigated. This study extends previous works and contributes toward the better understanding of interactions between asphaltene and inhibitor. Effect of functional groups and
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structure of inhibitors on Asphaltene precipitation were studied and it seems clear that the nature and polarity of Asphaltene (structure and amount of impurities presented) has a significant impact on the selection of inhibitors. Asphaltene dispersant tests and Core flood tests were
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designed for evaluation of inhibitors in static and dynamic conditions. The results revealed
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distinguished mechanisms for asphaltene solubilization/dispersion (such as hydrogen bonding, ππ interaction and acid-base interaction) and influence of additional side group (OH) on inhibition power of inhibitor.
During the experiments, it was found that increasing inhibitor concentration may lead to
the self-assembly of inhibitor and declining of asphaltene stabilization. So, finding optimum concentration of inhibitor with high efficiency and available at a reasonable price is very important. The results suggest that 600 ppm of CTAB and 300 ppm of SDS were approximately
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optimum concentrations for the studied crude oils. One of the most important findings that differ from previous studies is the revelation of the mechanism behind the SDS/Asphaltene behavior in various concentrations of inhibitor. Effect of chosen inhibitors on Asphaltene precipitation and
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consequently deposition in porous media was studied, and then experimental data were modeled for evaluation of permeability impairment mechanisms. Permeability revived after inhibitor squeezing and cake formation mechanism played an important role in permeability reduction
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before and after treatment in porous media. The findings can also be applied to prediction of future behavior of reservoirs in oil field scale and evaluation of formation damage in the
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different period of production if needed any treatment process.
KEYWORDS
1. INTRODUCTION
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Asphaltene, Precipitation, Deposition, Inhibitor, Permeability reduction
By reduction of conventional oil, oil companies have turned to production from heavy oil
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reservoirs. Asphaltene precipitation and deposition are the well-known problems during
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production. Asphaltene is the heaviest and the most polar fraction of crude oil which is soluble in aromatic solvents but insoluble in normal alkanes[1]. Formation of Asphaltene happens when disruption of thermodynamic equilibrium of crude oil has led to heavy organics aggregation. Asphaltene deposition is influenced by several factors like pressure-temperature reduction[2], CO2 injection[3], acidizing and stimulation techniques[4] and etc. plugging of tubing and surface facilities, permeability reduction[5] (permeability impairment) and wettability alteration[6] are results of asphaltene deposition.
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For prevention of such incidents, chemical materials with different structure and functional groups called asphaltene inhibitors adsorb on asphaltene surface and consequently delay the asphaltene aggregation, so asphaltene kept in solution[7]. Association of asphaltene sheets by
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sharing π-electrons of aromatic rings[8], hydrogen bonding of functional groups (OH, NH, COOH)[9] and acid-base interaction caused by heteroatoms (N, O, and S) and organometallic constituents (Ni, V, Fe) in crude oil[10] were the important and confirmed phenomenon.
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However, Mechanisms of asphaltene aggregation and stabilization are the same. Many researchers have perused the stabilization and phase behavior of asphaltene in statics mode and
received increasing attention.
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porous media. The research on asphaltene deposition and inhibition/ peptization has thus
Some of these attempts point to the impact of functional groups and inhibitor/dispersant structure in retardation of asphaltene aggregation and flocculation[11-17], mechanisms of
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inhibitor adsorption on asphaltene molecules[18, 19], self-association of asphaltene and inhibitors[20, 21], usage of vegetable oils as inhibitors[22] and reduction of wettability alteration[23, 24]. Some considerable and influential related studies stated in more detail in the
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following.
González et al.[11] have investigated the dispersion of asphaltene by different oil soluble
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amphiphiles (Alkylphenols with different degree of ethoxylation) and found that the asphaltene adsorption on mineral surfaces have been reduced by addition of amphiphiles. Chang et al.[12] have studied the efficiency of series of asphaltene inhibitors by means of X-ray scattering technique, precipitation and dissolution experiments. Influence of chemical structure including polarity of head groups, the length of alkyl tails and existence of extra polar group was studied. It was shown that the strong inhibition of asphaltene is due to the interaction between the acidic
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head of inhibitors and asphaltene. It was also found the inhibition efficiency is in the order: DBSA>NP>NBDO>NB. In a similar study, Boukherissa et al.[13] have studied the mechanism of asphaltene inhibition using ionic liquids. Results of their research demonstrated the
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significance of the length of alkyl chain and boronic acid presence in inhibitor structure. Ramos et al.[14] have utilized viscometric method[25] in order to study the effects of some inhibitors on the onset of asphaltene precipitation. The Behavior of asphaltene aggregation in n-pentane
confirmed by performing surface tension measurements.
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insoluble/ model systems was investigated and the existence of critical micelle concentration
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Al-Sahhaf et al.[15] have performed n-heptane titration of crude oil in presence of inhibitors for studying the onset of asphaltene precipitation. Effectiveness of inhibitors is in following order: DR > DBSA > NP > R > T > DO. Additionally, effect of acidic base interaction confirmed and experimental data were in good agreement with predicted amounts of inhibitors which
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calculated by micellization model. Shadman et al.[16] have examined the effect of series of inhibitors on the onset of asphaltene precipitation in Iranian oilfield. This study indicated that the inhibitor which has the acidic group like sulphonic acid will perform better inhibition.
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Marcano et al.[17] studied the effect of three chemical additives on asphaltene aggregates with NIR-Laser scattering and found out DBSA is more effective than others. Leon et al.[18, 19]
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compared the adsorption isotherm of nonyl phenol, nonylphenolic resin and native resin on asphaltene particles. Conclusions revealed that native resin penetrates in asphaltene molecules but the other inhibitors adsorb in two stages. In another study, adsorption of three amphiphiles on asphaltene molecules was studied and obtained data through adsorption of amphiphiles on nheptane/asphaltene mixture shown that there are two-step adsorptions where amphiphile
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molecules adsorbed on asphaltene surface and in the second step, amphiphile hemimicelles on the solid/liquid interface formed. Barcenas et al.[20] have performed a set of vapor pressure osmometry experiments and
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modeling study for evaluating the inhibition of asphaltene agglomeration/precipitation by using three inhibitors. It was concluded that self-association of inhibitor molecules reduced inhibitor adsorption on the active site of the asphaltene molecules, as a result the reduction in inhibitor
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efficiency. Rogel[21] stated the influential of the inhibitor on asphaltene aggregation and free energy of formation of asphaltene and inhibitor by molecular thermodynamic model. This model
optimum concentration of inhibitor.
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confirms that addition of more inhibitor will not change the size of asphaltene and there is an
This study differs from previous researches and contributes to our understanding of inhibitors effect on asphaltene deposition mechanisms in porous media. This study focuses on the
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mechanisms of asphaltene precipitation and deposition with the presence of inhibitors in porous media. Cationic (polar head group with the positive charge), anionic (polar head group with the negative charge), nonionic (without production of ions in solution) and four noncommercial
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inhibitors were used for investigation of the effect of functional groups and mechanisms of
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asphaltene stabilization.
2. MATERIALS AND METHODS 2.1. Materials
Two Iranian crude oils with different asphaltene contents and oAPI were used and the amount of asphaltene were determined by means of IP143[26]. Other fractions of crude oil separated using ASTM D4124[27].Two cylindrical outcrop carbonate samples (no clay present) from
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asmari formation have provided. Properties of crude oils and outcrop cores are summarized in Table 1 and Table 2 respectively. Table 1: Properties of crude oils
?? (gr/cm3)
µ (cp)
Oil A
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0.9821
Oil B
19
0.8823
A1 A2
Asphaltene
(wt%)
(wt%)
Table 3
57.8
26.5
6.9
8.8
Table 4
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62
5
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(wt%)
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Type of rock
Resin
(wt%)
Table 2: Properties of core samples
Cores
Saturate Aromatic
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oil
°API
Crude
Kw
L
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(%)
(cm)
(cm)
limestone
12.5
21.9
6.941
3.698
limestone
16.7
20
6.893
3.712
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(md)
The densities of the oils were measured using ANTON-PAAR model DMA 45 densitometer. The viscosities of the oils were measured using Brookfield DV-II+ at various Temperatures.
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Table 3 and Table 4 show the variation of viscosities with temperatures. Table 3: Viscosities at different temperatures (crude oil A)
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T(°C) µ (cp)
511.93
40
50
60
70
209.3
114.57
68.504
44.674
Table 4: Viscosities at different temperatures (crude oil B)
T(°C)
40
45
50
µ (cp)
35.32
28.78
24.26
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n-hexane, n-butanol, Toluene, and cyclohexane were purchased from Merck and their
Table 5: Solvents properties
Materials
MW
??
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properties are shown in Table 5.
BP 3
(gr/cm )
(°C)
n-hexane
86.17
0.66
69
n-Butanol
74.12
0.81
116
Toluene
92.14
0.87
110
Cyclohexane
84.16
0.78
81
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(gr/mole)
Synthetic brine used in these experiments was made of 22%wt/w potassium chloride. Simple synthetic brine was used with the aim of reducing possibilities of chemical reactions among the rock and inhibitors.
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Four non-commercial and three commercial inhibitors were used and their properties and structure were shown in Table 6 and Figure 1. SDS (Sodium Dodecyl Sulfate) and CTAB (Cetyl Terimethyl Ammonium Bromide) solutions were made in the mixture of water/n-butanol and n-
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Merck.
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butanol, respectively. Other inhibitors were prepared in toluene. All of the inhibitors provided by
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Table 6: Properties of inhibitors
BP (°C)
S (gr/L)
Benzene
78.11
0.878
80.1
Soluble in toluene
Naphthalene
128.17
1.14
218
30.2 gr/L in toluene
Benzoic acid
122.12
1.27
249
Salicylic acid
138.12
1.44
211
Slightly soluble in toluene
CTAB
364.45
0.39
250
37gr/L in H2O
SDS
288.372
1.1
288
Triton x-100
647
1.07
>200
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(gr/mole)
?? (g/cm3)
10.6 gr/L in toluene
100 gr/L in H2O
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MW
freely Soluble
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Inhibitors
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Figure 1: Structure of inhibitors
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2.2. Experimental Procedures 2.2.1 Asphaltene Dispersant Test Asphaltene dispersant test is proposed by Maneck[28] and used for evaluation of inhibitor
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the experimental equipment is given in Figure 2.
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efficiency in the static condition, but some steps of procedure were modified[29]. A diagram of
Figure 2: Schematic of asphaltene Dispersant Test
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Crude oil was diluted with toluene (1:1 V/V) since it is difficult to work with viscous oil, also accuracy and reproducibility of tests will increase.10 ml of n-hexane was added to each centrifuge tubes. The desired concentration of crude oil solution was added to the centrifuge
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tubes. The centrifuge tubes were shaken for 2 minutes to agitate the asphaltene stability, then the centrifuge tubes were left for 30 minutes in the water bath of 40° in order to let the asphaltenes precipitate. They were then centrifuged at 1500 rpm (rotation per minute) for 2 minutes and clear
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brown supernatant phase without asphaltene was formed above deposited asphaltene. The deposits level was evaluated and noted DBlank. Different dosages of inhibitors added to 10 ml of
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n-hexane and above procedure repeated again and noted as DTreatment . The amount of asphaltene reduction measured and Efficiency of inhibitors in each concentration calculated by means of below equation:
(1)
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− % = ( ) × 100
2.2.2 Inhibitor Efficiency Evaluation Test in Porous Media
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The most important part of work is the evaluation of inhibitors that are tested in static tests in reservoir conditions. The optimum concentration of inhibitors is determined in static mode and
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evaluated in porous media. All tests were carried out at a temperature of 90℃ and injection rate of 0.2 ml/min. overburden pressure was kept at 3500 psi. Schematic diagram of the Apparatus shown in Figure 3. The setup consisted of the oven with temperature controller, syringe pumps, six transfer vessels, stainless steel core-holder, sample collector, Data acquisition system and a differential pressure transmitter. The pressure difference between inlet and outlet of the core is recorded by Data Acquisition system and converted to permeability through Darcy equation. The following procedures are suggested by Minsseiux[30].
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1. Injection of brine (220000 ppm KCl) until complete saturation of core samples and measurement of water permeability. 2. Injection of cyclohexane until reaching Swi and measurement of cyclohexane permeability.
injected to the core.
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3. Injection of crude oil at the constant rate and recording permeability at each pore volume
inhibitor to core samples with soaking time of 24 hours.
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4. Squeezing inhibitor slug at the optimum concentration (determined from dispersant tests) of
5. Again injection of crude oil and continuous recording of oil permeability.
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6. Comparison of crude oil permeability before and after inhibitor injection.
Figure 3: Schematic of Inhibitor Efficiency Evaluation Test
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3. MODELING Several mathematical models for plugging by particles movement have been proposed for prediction of permeability impairment[31, 32]. By analysis of experimental data of several
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coreflood experiments and different crude oil, new formula based on Wojtanowicz et al.[33] model was presented by Minsseuix[5].
Gradual pore blocking occurs when colloidal particles precipitated and deposited in the whole
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core with accessible surfaces of pore framework. Then the permeability reduction is given by: = 1 − ( )
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(2)
Where is the permeability during fluid injection, is the initial permeability and is the injected pore volume.
Plugging of pore throat or redirection of flow to the larger pore which can cause new pore = 1 − ( )
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blockage is called Single pore blocking. Then the permeability response to this mechanism is: (3)
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In-situ cake formation happens when intensive plugging caused by in-situ filtration cake or bridging of trapped particles. The corresponding permeability reduction becomes:
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= 1 + !( )
(4)
Where , and ! are constant parameters and calculated by data fitting.
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4. RESULTS AND DISCUSSIONS 4.1 Blank Test Blank tests were performed on to crude oils and nine runs were made to decide which
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concentration should be used for dispersant tests. As shown in Figure 4, by the addition of diluted crude oil, asphaltene precipitation increases. It can be concluded that the higher precipitation, higher the deposition. The 0.8 ml and 0.6 ml crude oil solutions were chosen for
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dispersant test.
Figure 4: asphaltene deposition for Blank Test
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4.2 Dispersant Test So after determination of the right amount of diluted crude oil for the Blank test, the efficiency
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of each inhibitor in each crude oil was calculated and as seen in Figure 5 and Figure 6, the higher
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inhibitor concentration, higher the efficiency in asphaltene reduction.
Figure 5: Inhibitors efficiency in oil A
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Figure 6: Inhibitors efficiency in oil B
By comparison of the effect of CTAB inhibitor between oil A and B in Figure 7 concluded that oil A had more negatively group in its structure than oil B.
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SDS reduced the asphaltene to a certain amount (an optimum amount) and after addition of
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more inhibitor, the asphaltene deposits increased to a fixed amount (Figure 8). In both oil A and oil B at 300 ppm of SDS, asphaltene reached to its minimum amount 0.4 ml and 0.38 ml respectively. This suggests that asphaltene of oil B having more positively charged functional group comparison to asphaltene of oil A, so SO3 group can make the attachment with asphaltene and stabilize them. The reason for increasing of asphaltene after 300 ppm was the usage of water as the solvent. Water molecules could attract to asphaltene molecules by means of hydrogen bonding, so as the inhibitor concentration increased, the amount of water also increased and after
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300 ppm, hydrogen bonding slightly weakened the effect of acid-base interaction (SO3) and
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small amount of asphaltene produced in both oils.
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Figure 7: effect of CTAB in both crude oils
Figure 8: Effect of SDS in both crude oils
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As shown in Figure 9, triton x-100 performed stronger inhibition in oil A than oil B. The evidence suggests that the polar group of the hydrocarbonic chain which causes interaction
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between bulk crude oil and asphaltene were less in oil B than oil A.
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Figure 9: Effect of triton x-100 in both crude oils
The results of the effect of OH and COOH (carboxylic acid) functional groups are illustrated in
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Figure 10 and Figure 11. It was concluded that in both crude oils, salicylic acid had greater
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inhibition strength than benzoic acid. The reason behind this phenomenon is the attachment of extra hydroxyl group to salicylic acid. In both crude oils, benzoic acid performed slightly better inhibition than benzene because of the presence of carboxyl (COOH) group which attached to the benzene ring. Benzene rings can dissociate the asphaltenes by π-π interactions and addition of Hydroxyl and Carboxyl groups can empower asphaltenes stabilization with the formation of hydrogen bonding.
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Figure 10: Comparison of salicylic acid, benzoic acid and benzene in oil A
Figure 11: Comparison of salicylic acid, benzoic acid and benzene in oil B
As seen in Figure 12 and Figure 13, benzene has higher inhibition power than naphthalene in oil A but in oil B, naphthalene at low concentration lowered amount of asphaltene. These
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phenomena can be attributed to the molecular structure of asphaltene in oil B. Contrary to expectations, double benzene rings with double π-π interaction must perform better inhibition than the mono benzene ring, but Because of higher self-association of naphthalene moleculesin
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higher concentrations, the efficiency of naphthalene for asphaltene stabilization has reduced.
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Figure 12: Comparison of naphthalene and benzene in oil A
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Figure 13: Comparison of naphthalene and benzene in oil B
The reason of the constant amount of asphaltenes in each asphaltene dispersant test and some inhibitors concentrations were that in low concentrations, there are monomers that can occupy
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active sites of asphaltene molecules and made them stabilize, but by increasing inhibitor concentration, self-association of inhibitors occurs and the amount of asphaltene will not change from determined concentration. Similar findings were reported by Barcenas et al. study which is
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brought in the literature[20]. These static tests have shown that the CTAB inhibitor with the
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concentration of 600 ppm in oil A and SDS inhibitor with the concentration of 300 ppm in oil B were the optimum concentration for squeezing in reservoir condition. 4.3 Inhibitor Efficiency Evaluation Test in Reservoir Condition 4.3.1 Efficiency of Inhibitor on Oil A / A1 The initial cyclohexane permeability was 9.04 md at residual water saturation (Swi=30%). The first injection of oil A was performed and the amount of permeability reduced to 2.56 md and resulted in an oil permeability reduction of 71%. Then slug of n-Butanol/CTAB solution at
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optimum concentration was squeezed according to the previously procedure described. During the second injection of crude oil, the initial oil permeability restored to 9.5 md, followed by stabilization trend at 2.93 md compared with 2.56 md reached at the end of previous crude oil
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injection as shown in Figure 14. The trend of permeability reduction has maintained and
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plugging resumed.
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Figure 14: Effect of CTAB solution on oil A in Asmari carbonate
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4.3.2 Efficiency of Inhibitor on Oil B / A2 The initial permeability of cyclohexane was 7.68 md at residual water saturation (Swi=32%) and after the first injection, initial permeability reduced to 4.16 md and oil permeability reduction of 45.8 %. then a slug of n-Butanol/water/SDS (inhibitor) was squeezed at the optimum concentration. During the second injection initial Permeability restored to 14.86 md. Figure 15 shows permeability evolution during second injection and after the squeeze of inhibitor a sharp increase in oil permeability was obtained.
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Figure 15: Effect of SDS solution on oil B in Asmari carbonate
4.4 Modeling of Experimental Data
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Experimental data of first and second injections were fitted in specific equations for determination of dominant mechanism. Plotting of K/Ki versus PV injected (Figure 16 and
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squeezing.
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Figure 17) shows the major mechanisms govern the porous media before and after inhibitor
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Figure 16: Permeability reduction models for Oil A/A1
Figure 17: Permeability reduction models for Oil B/A2
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Permeability reduction models were studied and best model was chosen. The fitting parameters
Table 7: Results of modeling of asphaltene deposition
Squeezing Stage
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and results of permeability model before and after squeezing brought in Table 7.
Injected
Dominant
Fitting
pore volume
mechanism
parameter
R-square
Coreflood tests
Oil A/A1
0 - 1.54
Cake forming
2.204
0.8315
squeezing
Oil B/A2
0 – 0.99
Cake forming
3.035
0.3421
After inhibitor
Oil A/A1
squeezing
Oil B/A2
M AN U
SC
Before inhibitor
Cake forming
1.727
0.9871
0 – 1.04
Cake forming
3.282
0.9794
TE D
0 – 1.81
Comparison of experimental data with proposed models indicated that according to equation 4 in first crude oil injection in both A1 and A2 cores, the dominant mechanism was cake formation.
EP
Even after inhibitor squeezing process, cake formation happened again. In oil B/A2 and oil A/A1 first coreflood tests, poor fitting is caused by quick entrapment of asphaltene in cores and
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resulted in drastic permeability reduction. The tests are repeated twice for data validation and similar results were obtained. The schematic of asphaltene deposition and permeability impairment in presence of inhibitor are presented in Figure 18. During the injection of asphaltenic crude oil, asphaltene particles are deposited on pore surface and pore throat. This phenomenon influenced by factors like electrostatic charge differences between asphaltene and formation rock, pore structure and composition of particles. asphaltene particles are reduced the cross-sectional area of the pore and incoming particles accumulated not only in pore throat, but
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also within all pore bodies. Another layer of asphaltene particles deposit on former layer and formation of internal filter cake happens. After that, Inhibitor is squeezed to the porous media and adsorbed on asphaltene molecules through interaction between their polar head group.
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Dissociated and stabilized asphaltene particles removed from porous media. In the second injection of asphaltenic crude oil, the presence of inhibitors resulted in the reduction of asphaltene precipitation and deposition, so the rate of permeability impairment in this stage was
SC
much lower than the first injection and permeability changes were evidence of this claim that
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EP
TE D
M AN U
inhibitors acted as resins and peptized the asphaltene molecules in the fluid phase.
Figure 18: Schematic of effect of inhibitor on permeability impairment in porous media a) Surface deposition and pore-throat plugging b) Permeability reduction caused by In-situ cake formation in first crude oil injection c) Inhibitor squeezing and Adsorption of inhibitors on asphaltene molecules d) Removing dissociated and stabilized asphaltene from pore network e) Presence of inhibitor in pore
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network f) Stabilization of asphaltene molecules in second injection g) Improved permeability caused by reduction in asphaltene deposition
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5. CONCLUSIONS This study has demonstrated that due to diversity in the structure of asphaltene, different inhibitors are needed and according to the asphaltene dispersant tests (static tests), asphaltene of oil B has more positively and lesser negatively charged functional groups than asphaltene of oil
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A. comparison of inhibitors has shown that the strength of inhibition mechanisms were in the
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following order: Acid-base interaction> hydrogen bonding> π-π interaction. The investigations revealed that 600 ppm of CTAB and 300 ppm of SDS are the optimum concentration for oil A and oil B respectively, but by reviewing all the inhibitors, it was concluded that at high concentration of inhibitors, self-association of inhibitor monomers occurs and interaction between inhibitors and asphaltene are reduced. So as a result the amount of asphaltene then
TE D
remains constant. The structure of inhibitors reflects the impact of functional groups (π-π interactions, acid-base interaction and hydrogen bonding) on asphaltene stabilization. Through the experiments; it was found that existence of hydroxyl (OH) and carboxyl (COOH) groups in
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the structure of benzene rings enhanced the asphaltene inhibition power.
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This study differs from previous researches and contributes to our understanding of inhibitors effect on asphaltene deposition mechanisms in porous media. Modeling of experimental data has indicated that a cake formation mechanism is dominant in the entire porous media before and after inhibitor squeezing. Inhibitors dissolve/stabilize the asphaltene deposits and delay asphaltene deposition in the second injection, so permeability revived. The findings can also be applied to prediction of future behavior of reservoirs in oil field scale and evaluation of formation damage in different period of production if needed any treatment process.
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ACKNOWLEDGEMENTS The authors would like to thank the Research Department of Ahwaz Petroleum University and
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EP
TE D
M AN U
SC
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National Iranian South Oil Company (NISOC) for supporting this study.
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NOMENCLATURE
??
Density
'( +!)*
Viscosity
cp
-
Porosity
%
L
Length
D
Diameter
MW
Molecular Weight
S
Solubility
BP
Boiling Point
Inhibitor Efficiency
Amount of asphaltene
Amount of asphaltene
Permeability
Water Permeability Initial Permeability
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!)
'( +)./0 '( +1 ℃ %
)/
TE D
3
in dispersant test
EP
in blank test
!)
M AN U
µ
SC
Temperature
RI PT
℃
T
Pore Volume injected
)/
)2 )2 )2 )/
constants which are
a, b, c
calculated by data fitting
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Sodium Dodecyl Sulfate
CTAB
Cetyl Trimethyl Ammonium Bromide
OH
Hydroxyl group
COOH
Carboxyl group
SC
SDS
RI PT
ABBREVIATION
Degree of gravity (American petroleum API
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institute)
Potassium chloride
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EP
TE D
KCl
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