Asphaltene Aggregation in Crude Oils during Supercritical Gas

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Asphaltene Aggregation in Crude Oils during Supercritical Gas Injection Ronald Nguele, Mohammad Reza Ghulami, Kyuro Sasaki, Hikmat Said-Al Salim, Arif Widiatmojo, Yuichi Sugai, and Masanori Nakano Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.5b02903 • Publication Date (Web): 22 Jan 2016 Downloaded from http://pubs.acs.org on January 23, 2016

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Asphaltene Aggregation in Crude Oils during Supercritical Gas Injection Ronald Nguele†*, Mohammad R. Ghulami†, Kyuro Sasaki†, Hikmat Said-Al Salim ‡, Arif Widiatmojo †, Yuichi Sugai † and Masanori Nakano ₡ †

Resource Production & Safety Engineering Laboratory, Kyushu University, Fukuoka 819-

0395 Japan ‡

Department of Chemical & Petroleum Engineering, North Wing UCSI University, Cheras,

56000 Kuala Lumpur, Malaysia ₡

Research center, Japan Petroleum Exploration, Chiba 261-0025, Japan

KEYWORDS: Supercritical gas; CO2 injection; Asphaltene solubility; Asphaltene aggregation; Heavy oil recovery.

ABSTRACT- This paper presents the aggregation of asphaltenic materials in three dead crude oils including two heavy samples from Hokkaido (Japan) and an extra heavy sample from Canada. In this study, a modified ASTM D3279 method and PVT test were used to estimate the amount of precipitated asphaltene and the experimental bubble-point pressures of the samples respectively. Upon which, a crude oil characterization was performed following pseudo-component approach with the use of molecular weight and specific gravity

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of single carbon number from oil assay data as distribution variables. A simplified thermodynamic model, derived from the solubility model, was used to correlate the maximum asphaltene soluble with the aggregated amount. This study has highlighted that oil precipitation, during its titration, occurs as a function of both the molecular weight of the titrant and the carbon-to-hydrogen ratio in the asphaltene phase. Furthermore, the kinetics and the stability of intermolecular forces, developed during the miscibility process, are believed to alter oil polarity and gas solubility. More specifically, pressurization of the system [oil supercritical gas] decreases the solubility parameters of the asphaltene fraction and increases the solvating strength of gas. Both effects were found to occur concurrently. This study has also demonstrated that asphaltenes are less soluble in impure gases compared to the pure one. At/near the bubble-point pressure, the supercritical gas, in contact with the oil, develops a potential as either a flocculant or coagulant. The increase in pseudo equilibrium temperature attained after gas injection was found also to alter asphaltene aggregation.

INTRODUCTION Oil production consists of three distinct stages including primary, secondary and tertiary recovery. The latter, refers as enhanced oil recovery (EOR), aims at increasing production from a depleted oil reservoir. Practically, EOR consists at injecting in the reservoir a foreign material (known as displacing fluid or solvent). Consequently, the mobility of residual oil is promoted through a series of physicochemical process(es) involving petroleum and displacing fluids and the reservoir rocks (Thomas 2008). If the displacing fluid is a gas (advancing gas), EOR method is referred as gas flooding whose efficiency lies upon the achievement of the miscibility front between the gas and the oil. Nevertheless, up to 40% of the residual oil could be extracted from a depleted oil reservoir using gas injection after the primary and secondary recovery stages 3.


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For example, in Wasson Field (Denver, USA), a total recovery of about 19.5% was achieved using carbon dioxide (CO2) injection for the oilfield with an estimated original-oilin-place (OOIP) of about 2 billion barrels 4. Gas injection in general and CO2 –EOR in particular, has gained prominence in petroleum industry mainly because of (i) the cheap price of CO2 compared to other gases (Blunt et al. 1993), (ii) its availability 7 and more importantly (iii) its ability to develop a high solubility in various type of crudes

8–10

. Moreover, at its

supercritical state, CO2 exhibits singular properties (low viscosity and high diffusivity) which were revealed useful for oil extraction

11,12

. Using a dead oil (density of 0.8573 kg/L) into

which super critical CO2 was injected, Rudyk et al. (2013) were able to achieve a total oil recovery ranging from 44 – 77 %. However, they found that by adding a low molecular weight solvent to the advancing gas, the extraction of heavier fractions of the oil could be improved

13

. Hussain (2014), also from a dead oil as feed material, highlighted the optimal

condition at which CO2-EOR recovery was maximal. He pointed that a possible recovery of about 60 % is reachable if the gas is injected at 60 oC and 60 MPa 14. However, one of the major drawbacks of gas injection is associated to the well-documented organic deposition. Heavier fractions, which tend to settle down during the gas miscibility process, are primarily of flow assurance issues during oil production

15,16

. Precipitated

fractions deposit mainly in casing, tubing and/or surface equipment. Subsequently, reduction of reservoir formation porosity, alteration of rock wettability as well as wellbore plugging are few issues amongst many that have been often reported

17–20

. In fact, organic materials that

precipitate are a complex mixture of asphaltene, resins and wax. At the early stage of the production, i.e. during the primary and secondary recoveries, certain oilfields did not experience aforementioned problems. Upon acidizing the well (i.e. altering reservoir acidity) followed by CO2-EOR, flocculation and deposition of asphaltenic materials were observed 21. In Hassi Messaoud oilfield (Algeria), deposited asphaltene caused a severe plugging of


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tubing which was remediated by a constant washing and scrapping. As a result, a considerable increase in maintenance costs was incurred 22. Asphaltene is a general term for the fraction of crude oil that is soluble in aromatic solvent (e.g. benzene, toluene, xylene) but not in light paraffin (n-alkanes). Asphaltene is a brown to dark amorphous solid. Its chemical structure, however, has been subject to extensive works. At first, the aromaticity of asphaltene was clearly established 23. Speight (1999), further proposed that asphaltene is a condensed aromatic ring interconnected with heteroatoms and/or aliphatic/naphthenic rings linkages

24

. In the crude oil, asphaltene

along with resins are found in stable poly-dispersed colloidal form. In other words, resins and asphaltene are in suspension in colloidal state. The pseudo-equilibrium could be broken by the change in reservoir environment i.e. temperature/pressure and the nature of the crude oil 21,25,26

. Those parameters are said to influence solubility of asphaltene – resin system, thus to

alter the stability of colloidal suspension which is frequent in undersaturated reservoirs. Furthermore, the introduction of a foreign material (advancing gas) of low molecular weight in such system is believed to force asphaltene to be unstable and then to precipitate. This was the case in an oilfield in Abu-Dhabi (UAE) where asphaltene precipitation occurred upon CO2 injection. Further investigations revealed that the size of asphaltene particles were responsible of the deposit. 27, 28 . The mechanisms inherent to asphaltene deposition are still subjects to discuss. However, it is accepted that the deposition, during CO2 injection, is subsequent to the mass transfer between the gas and the oil. Thus, the mechanism of asphaltene deposition should be regarded as a result of physicochemical process (es) involving asphaltene/resin and displacing gas. It could be interesting to have an insight about the steps (or stages) through which asphaltenes undergo before depositing. In fact, once the miscibility is reached to its


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maximal (generally around/at the bubble-point pressure), further deposition is less expected 29

. Focusing on the bubble-point pressures, Monger and Fu (1987) found that organic

deposition was rather imputed to liquid-liquid phase equilibria. This is to say that their molecular size and structure of asphaltene affect the way molecules partition into a CO2-rich gas phase

30,31

. Moreover, onset pressure (the pressure at which the deposition occurs) is

reported slightly above the bubble-point pressure while it attains the maximum value about its bubble point pressure

32

. Additionally, the concentration of gas as well as the fraction of

low molecular weight paraffins alter the distribution of asphaltenic materials in the oil. This belief was experimentally demonstrated by Huang (1992) who correlated oil recovery with the fraction of C5 - C19 and asphaltene content. He pointed that a decrease in oil recovery should be expected when the fraction C5 - C19 decreases

17

. Although extensive literature

reviews cover asphaltene and wax precipitation, to the best of our knowledge, the recent few that have tackled the effect of the supercritical state of injecting gas on asphaltene deposition rather focused on the quantitative deposition rather. For example, Seifried et al. (2015) presented that precipitation of asphaltene upon injection of CO2 is quantitatively different from that induced by hydrocarbon systems

33

. Therefore, in this study, the terminology

“aggregation” will be preferential used as it is believed to be the phenomenon preceding deposition. The present work addresses primarily the issue of asphaltene aggregation upon supercritical gas injection with a focus given to supercritical CO2 (sCO2). Also, a tentative analysis is presented in regard of physicochemical process (es) that involve aggregation of asphaltenic materials and their deposition. At first, our oil samples (dead crude oils) are characterized and modeled as pseudo-components. The thermodynamic model, based on which the asphaltene aggregation is computed, is further discussed. The experimental section of this work focuses on estimating asphaltene content in the samples as well as the experimental determination of


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bubble-point pressures of each dead crude oil. Upon which, the effect of sCO2 purity on solubility of asphaltene is examined. The last section investigates on the extent to which the reservoir temperature, in equilibrium with the gas, alters asphaltene aggregation.

MATERIALS AND METHODS MATERIALS. Three dead oil samples were selected as feed materials for this study. The crude oils, supplied by Japanese Petroleum Exploration (Japan), were collected from the surface equipments. Table 1 outlines the physical properties of the oils. Table 1. Physical properties of dead crude oilsa Oiliness API, in o Oil Sp. gr. at 288 K Oil viscosity at 303 K, in mm2/s Oil mol. weight , in kg/kmol a

HC-1

HC-2

BT-1

Heavy oil 16.6 0.956 50 266.7

Heavy oil 11.6 0.988 874.0 338.5

Extra heavy oil 7.60 1.016 6970 584.9

Mol. wt.= molecular weight; Sp. gr.= specific gravity.

METHODS Asphaltene precipitation by oil titration – To extract organic materials, a direct method (i.e. oil titration) was performed for the three dead crude oils. Although the accuracy of this technique is a subject to argument, the prime purpose of its use in this work is to estimate the amount of asphaltene content in the oil samples. The experimental procedure, illustrated in Figure 1, was modified from ASTM D3279 as presented by Buenostro-Gonzalez (2004) 34.


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Figure 1. Experimental procedure of oil titration. Prior oil titration, the candidate oils were centrifuged for 4 hours at 3000 rpm. This was done to ensure a complete dewatering and demulsification of the samples. A known amount of dead crude was dissolved in toluene (Junsei chemical, Japan) in a ratio of 1:20 (v:v). To insure a complete dissolution of the oil, the mixture (oil + toluene) was heated at 90oC. The mixture was further centrifuged for another 30 mins at a constant speed of 5000 rpm. The supernatant fluid was separated from the precipitated organic matters by filtration. The filtrate was mixed with n-pentane (Junsei chemical, Japan) at the ratio of 1:5 (v:v) and shaken for 1 hour in Vortex Genie 2 (Scientific Industries, USA). The solution was then left to equilibrate overnight to allow a phase separation at a constant temperature of 25oC. A vacuum filtration was performed to remove sedimented organic materials from supernatant fluid. During the filtration, hot n-pentane was used to wash off resins and waxy products from asphaltenes. This step was repeated until the solution, i.e. the filtrate, became clear in color. The amount of precipitated asphaltene was determined by the difference of weight of filter paper (pore size 10 µm) before to after the vacuum filtration.

Supercritical gas injection – Pure CO2 (99.99% purity) was chosen as primary advancing gas. CO2 injection aimed at replicating production of undersaturated oils whose recovery mechanism (i.e. expansion drive of oil-in-place) is liable to bubble-point pressure. Also, CO2 was used to cause the oil to swell because of its low minimum miscible pressure (MMP). Table 2 summarizes the gas injection conditions in the different crudes as performed in this study. Table 2. Experimental conditions of gas injection a CO2:HC-1 CO2:HC-2 CO2:BT-1

Injecting pressure, in MPa

Cell temperature, in K

Gas state

7.00 7.63 7.07

313.15 313.15 343.15

Saturated Saturated Saturated


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a

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Gas supercritical conditions for CO2 :7.38 MPa/ 304.1 K. Gas injection experiments were conducted in a PVT analyzing cell sketched in Figure 2.

The principle of this equipment is discussed elsewhere

35

. For each dead oil sample, the

advancing gas was contacted with the oil for a minimum of 72 hours during which the cell pressure was increased step-wise after each pseudo-equilibrium was attained. At the end of the PVT test, the analyzing cell was slowly depressurized. The vapor phase was routed towards a gas trapping cell. The gas trapping system was designed to trap the vaporized oil from PVT test.

(1)

(2)

1

2

Figure 2. Schematic apparatus of PVT analyzing cell and flue gas trapping system (1): PVT analyzing cell; (2): Gas trapping system 1 CaCO3; 2 Hot toluene. The cell contained hot toluene. The saturated crude oil was withdrawn from the bottom of the cell. Both saturated and trapped vaporized oils were further titrated with n-pentane following the experimental procedure previously discussed.


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CRUDE OIL CHARACTERIZATION Reservoir fluids including crude oil and natural gas vary in composition primarily because of (1) depositional environment, (2) geological maturity of the reservoir and (3) the migration path of the fluid to the source

36

. This is to say that reservoir hydrocarbon liquids are

composed of many thousand components which cannot all be identified and measured. Nevertheless, a typical crude oil contains in general known components including hydrocarbons (paraffins, naphthenes, aromatics), non-hydrocarbon elements (CO2, H2S, N2). As far as oil recovery is concerned, the knowledge of the chemical composition of oil to be displaced is essential. In fact, the accuracy in predicting its behavior towards the design and upon application of a tertiary recovery method is dependent. Furthermore, it is reported that thermodynamics, i.e. phase behavior, of oil is altered by chemical composition of oil. Therefore, it is important to develop a technique that models accurately the candidate reservoir oil fluid. In this regard, literature has reported two commonly accepted approaches: (i)

The pseudo-component approach - This approach treats oil chemical mixture as a

single pseudo-component or as conveniently grouped sub-fractions. In other words, oil is divided into light and several C7+ fractions 37. However, this method is reported to be timeconsuming, especially if the oil to be characterized is composed various families of compounds such as paraffinic, olefinic, naphthenic and/or aromatic hydrocarbons. Also, the calculations of pseudo-component compositions, as well as their critical properties, are reported to be highly sensitive to selection of heavier fractions 38. (ii)

The continuous approach - In this approach, fluid composition is treated as a

continuous distribution functions either in analytical or numerical form, with respect to one (or more) measurable variables 39,40. A statistical distribution, F(I), models the composition. I is the distribution variable and usually chosen to be a property such as boiling point (Tb),


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carbon number (SCN), or molecular weight (MW). However, continuous method is found inaccurate and inefficient when the number of the families of compounds exceeds unity. The use of Gaussian quadrature technique was introduced to overcome this issue 26,41. Also, it was established that the choice of measured variables altered the results of the oil characterization. Riazi and Daubert (1980, 1987) investigated in the choice of variables by combining the specific gravity (S), carbon-to-hydrogen (C/H) Tb and MW as distribution variables. They concluded that it is advisable to use as variable S and Tb over C/H and MW respectively 42,43. In this work, the candidate oils were characterized following a modified pseudo-component approach based on their assay data. Step 1: Splitting the sample dead oil into pseudo fractions. Lei et al (2010) reported that 90% of precipitated asphaltene in stock oil is composed of C30 - C60. Thus, the fraction C60+ models the insoluble (or precipitating) asphaltene

44

. Extending above observations to our

study, we assumed two pseudo-phases (or sub-fractions) including solvent and asphaltene phases. The solvent phase was composed of non-hydrocarbon elements and hydrocarbons whose molecular weight was lower than 382 kg/kmol i.e. the fraction C1 - C29. Since our oils were dead samples, the fraction (C1-C8) was taken as nil. Therefore, the solvent phase tallied to the phase C9 – C29. The asphaltene phase corresponded to the sum of hydrocarbons of molecular weight equal or greater than 382 kg/kmol i.e. C30 – C60+. Asphaltene phase was further subdivided into soluble asphaltene (C30 – C60) and insoluble asphaltene (C60+). Step 2: Estimation of pseudo-component critical properties. Critical properties and acentric factor of the pseudo-components are required in calculation of the phase behavior using equation of state (EoS). Based on the available data, several correlations are proposed in the literature.


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If a pseudo-fraction composed of n hydrocarbon CnH2n+ζ of xi mole fraction each, let MW and S to be its average molecular weight and average specific gravity respectively,

MW was calculated from equation (1): n

MW = ∑ xi MWi i =1

(1)

where MWi is the molecular weight of single hydrocarbon, in kg/kmol. Similarily, S was computed from equation (2): n

∑ x MW i

S=

i

i =1

n

∑ x MW S i

i

i =1

i

(2)

where Si is the specific gravity of single hydrocarbon, dimensionless. The pair (MW, S) was further used, as proposed by Riazi-Daubert (1980), to estimate critical properties of each pseudo-fraction 42.

θ = a( MW )b S c exp  d ( MW ) + e ( S ) + f ( MW ) S 

(3)

where θ is any physical parameter. In this work, it represented either critical pressure (pc expressed in MPa) or critical temperature (Tc expressed in oK); MW is the molecular weight, in kg.kmol-1; S is the specific gravity, dimensionless; a, b, c, d, e and f are correlation constants whose values are dependent to the desired

physical property 42.


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Acentric factor, ω, was computed from Kesler –Lee correlation as expressed in equation (4),

6.09648  p  − ln  c  − 5.92714 + + ln [θ ] − 0.169347θ6 14.7  θ  ω= 15.6875 15.2518 − − 13.4721ln [θ ] + 0.43577θ 6 θ

(4)

where θ is dimensionless factor, θ=Tb/Tc. . It has to be noted that equation (4) is valid if and only if θ < 0.8. Using equations (3) and (4), the critical properties of the pseudo-fractions of the dead oils were computed as summarized in Table 3. Table 3. Oil Pseudofraction

Solvent

Asphaltene a

characterization using pseudo-components method a Composition, in % mol

MW, in kg/kmol

S, (-)

Tc, in K

pc, in MPa

ω, (-)

78.21b

208.9 b

0.8619 b

734.5 b

1.64 b

0.5427 b

C/H, % mol C/mol H 37.0b

92.45c

226.6 c

0.8523 c

746.3 c

1.45 c

0.5899 c

46.6c

51.31d 21.79 b

141.1 d 129.5 b

0.8649 d 0.9327 b

660.1 d 669.3 b

2.61 d 3.18 b

0.4393 d 0.5019b

24.3d 10.6 b

7.550 c

40.08 c

0.9260 c

474.9 c

9.72 c

0.3667 c

3.68 c

48.69 d

443.8 d

0.9260 d

924.9 d

0.58 d

0.2975 d

23.9 d

MW= molecular weight; S= specific gravity, Tc= critical temperature; pc= critical pressure;

ω= acentric factor; C/H = carbon-to-hydrogen ratio; b

HC-1;

c

HC-2;

d

BT-1.

It has to be noted that soluble and insoluble asphaltene are considered to have the same thermodynamic properties as suggested by Kohse (2000) 45.


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THERMODYNAMIC

MODEL

OF

ASPHALTENE

AGGREGATION

AND

DEPOSITION Asphaltene aggregation, thus its deposition in an oil reservoir relies upon the variations of resevoir environment i.e. pressure and temperature and the oil chemical composition. Moreover, existing thermodynamic models that helps the understading, the modeling and the prediction of phase behavior of asphaltene deposition are developed based on how asphaltene fraction is defined in the crude oil. In this regards, several models have been proposed. However, they are conventionally grouped into two categories: (1) The solubility model. This approach believes that asphaltene and solvent phases are in liquid state in the oil. Their thermodynamic properties are generally derived from the Flory– Huggins-type solution theory, using an energy interaction parameter estimated from Hildebrand’s solubility parameter. This theory, discussed extensively by Mousavi-Dehghani et al. (2008), has served as basis of considerable works in modeling of organic deposition 25,26,46–50

.

(2) The solid model. In this approach, oil is treated as a multicomponent mixture in which the heaviest component is split into two pseudo-components including a non-precipitating component (resin/ asphaltene micelles) that remains soluble in the oil and a precipitating component that forms the aggregated asphaltene 45,51. From this model, two other approaches were derived including colloidal and micellization models. Both consider asphaltenic materials as macromolecules whose size and nonpolar van der Waals interactions dominate the asphaltene phase behavior. Inherent thermodynamic properties are calculated from a modified version of statistical association fluid theory (SAFT) EoS. More specifically, the colloidal model (or thermodynamic–colloidal model) solves the equilibrium between the resins absorbed in asphaltenes and the resins that are present in the solvent. On the other


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hand, the micellization model applies the micellization theory discussed by Nagarajan and Ruckenstein (1991) 52. In this work, the thermodynamic model applied was modified from a simplified form of the solubility model presented by Chung and Jones (1991)

26

. To which, we assimilated the

concept that the fraction of asphaltene that either aggregates, flocculates and/or precipitates, occurred within the asphaltene phase and it is implicit to soluble asphaltene. In other words, the maximum soluble asphaltene (which is the key parameter computed from solubility model) was used to estimate the amount of asphaltene that deposits. A step-by-step algorithm, illustrated in Figure 3, summarizes the procedure of calculation of soluble asphaltene. Consider a case in which an asphaltene-containing fluid split into a binary mixture of a solvent phase of n hydrocarbons for total mole fraction (xsolv) and asphaltene phase of p hydrocarbons for total mole fraction (xasph), for one mole of the fluid, xsolv + xasph = 1

(17)

Assuming that in the asphaltene phase, a fraction is insoluble, one can write, xasph = ( xasph )

solu

+ ( xasph )

insolu

(18)

Equation (17) in (18) written in terms of number of moles, the amount of aggregated asphaltene in dead oil was estimated from equation (19),

  n MWsolv Sasph  %asph = 1 −  solv + φasph )max   ×100 ( Soil    noil MWoil

(19)

where % asph is the amount of aggregated asphaltene, in wt. %; nsolv and noil are the number of moles of the solvent-phase and feed oil respectively, in

mol;


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MWsolv and MWoil are the average molecular weight of the solvent-phase and feed oil

respectively, in kg/kmol; Ssolv and Soil are the average specific gravity of the solvent-phase and feed oil

respectively, dimensionles. Thence, a correlation was established between the solvent and the asphaltene phases.


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Given (from crude oil assay) SCNi, MWi, xi, Si

Pseudo-component characterization

Asphaltene phase

Solvent phase (MW)solv, xsolv, (Tb)solv, (Tc)solv, (pc)solv

(MW)asph., (Tb)asph, (Tc)asph, (pc)asph ; (ω)asph

Soluble asphaltene*

( xasph )

Injecting gas / Pseudo- equilibrium conditions zgas, pinj, Tinj

solu

Insoluble asphaltene*

(x )

n=60

= ∑xi

insol

asph

p

= ∑xi i=n+1

i=30

Perfom Vapor-liquid equilibrium for the system Gas- crude oil: Modeled from Nguele et al. (2015) xgas, ygas, nliq, nvap, Zliq

Calculate the molar volume of oil-rich phase:

(Vm )

liq

= Z liq

noil RTinj

(VmLiq)

Determine the heat of vaporization of each pseudo-component: ( Hi)

(5)

pinj

 Tc − Tinj (∆H i )Tinj = (∆H i )Tb  i  Tc − Tb  i i with

   

0.38

(

(6)

)

( ∆H i )Tb = 4.245 ×10−3 Tbi 8.75 + 4.751log(Tbi ) 

Compute the mole fractions of solvent and asphaltenephases in oil-rich phase:

xsolv and xasph

Compute the molar volume of solvent and asphaltene in oil-phase: (Vsolv)liq, (Vasph)liq

Calculate of parameter solubility (δi ) and the volume fraction (Φi) of the solvent and asphaltene phase

(7)

xasph = xgas (1 − ( xasph )solu. ) − (1 − ( xasph )i nsolu. )

(8)

xsolv = 1 − xasph

(9)

liq Vasph = xasphVmliq

(10)

liq liq Vsolv = Vmliq − Vasph

(11)

 ( ∆H i )Tinj − RTinj   Vi l   liq V = ni ∑Vi liq

δi = 

φiliq

(12) (13)

i

n

Calculate δsolv and δasph , parameters the solubility for solvent and asphaltene phase respectively

δ solv. = ∑ φiliqδ iliq

δ asph =

i =1 p

∑φ

δ

liq liq i i

(14) (15)

i = n +1

Compute the maximum volume asphaltene soluble: (Φasph)max

(φ )

asph max

2  V liq  liq (δ asph − δ solv ) liq liq 2  Vasph (φsolv )  = exp  asph − 1 φsolv − liq   Vsolv  RT inj   

(16)

Estimate the amount of deposited asphaltene (% asph.)

Figure 3. Sequential algorithm used to determine deposited asphaltene during gas injection. Modified from Chung et al. (1991) 26; * The thermodynamic properties of both soluble and insoluble asphaltene phases are taken equal 45.


16

Page 17 of 39

RESULTS AND DISCUSSIONS Crude oil titration and supercritical gas solubility - Figure 4 shows the results of titration of our dead oil samples. The build-up in asphaltene content was correlated with the C/H ratio in the asphaltene phase.

12

% asph, wt. %

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

Energy & Fuels

10

8

6

4

2 0.05

0.10

0.15

0.20

0.25

C/H ratio in asphaltene-phase, (-)

Figure 4. Experimental estimation of asphaltene precipitation in feed dead oils under solvent titration method; () HC-1; () HC-2; () BT-1, Dashed line: fitting line. It has been established that C/H ratio as parameter to describe aromaticity of a crude oil. The low C/H, the higher is the likelihood of the oil to contain either naphtenic and/or aromatic materials. Conversely, paraffinic oil is likely to have a high C/H ratio. Therefore, the low values in our samples, as illustrated in Figure 4, suggest a napthenic/aromatic nature of investigated samples. Further to that, deposition in asphaltenic materials was found to increase linearly with the C/H ratio. For example, 36% in increase of deposited asphaltene was established when the C/H ratio was doubled for the solvent/oil ratio i.e. 5 cm3/g-oil. Chung et al. (1991) reported a deposit of 0.81 wt. % in asphaltenic materials26 for the same solvent/ratio Buenrostro-Gonzalez, E et al. (2004) found an average deposition of 2.52 wt. %


17

Energy & Fuels

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

for a solvent/ratio equal to 4 cm3/g-oil

Page 18 of 39

34

. In both cases, the investigated oil were reported

lighter i.e. API 35 and density of 0.857 respectively. It is therefore obvious that the prime difference with our samples could be drawn out from the initial composition the crude. Moreover, if our results are set in parallel with aforementioned authors, we may extend that the solvating power of n-pentane (titrant) not only lies to molecular weight of the oil

53

but

also it is dependent of its C/H ratio. In fact, three acting forces are effective during the fluid solubility (being a liquid or gas) into another including (1) hydrogen bonding, (2) dipolar and (3) dispersion forces. They should be roughly equal to ensure a complete miscibility. When n-pentane (non-polar molecule) is contacted with oil, the dispersion forces are predominant. They increase with the C/H ratio, thus increase the solvating power of n-pentane. Consequently, more asphaltene precipitates. Bubble-point pressure, pb, represents a key parameter for gas-EOR. Conventionally, it is determined either by a constant-composition test or empirical correlations 54. PVT analyzing cell was used to determine pb of the dead oil. Graphically, it represents the pressure at which the solubility of sCO2 was fairly constant. The results of sCO2 injection are illustrated in Figure 5.


18

Page 19 of 39

35

30

Rs, mmol CO2/g-oil

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

Energy & Fuels

25

20

15

10

5 8

10

12

14

16

psat, MPa

Figure 5. CO2 solubility in heavy dead oils. () HC-1; () HC-2; () BT-1. sCO2 solubility and pb were found both dependent of the oiliness of the crude. The lighter the oil, the higher the solubility and the lower pb (Table 4). To understand the ability of sCO2 to develop a better miscibility compared to normal CO2 (beyond its interesting thermodynamic properties), an insight could be drawn out from the polarity of crude oil visà-vis of sCO2. Table 4. Results of experimental bubble-point pressure determination a

HC-1 HC-2 BT-1 South American Oil b a

xCO2, in % mol

(pb)exp, MPa

88.36 91.84 85.64 -

13.0 11.5 9.57 12.0

( pb )exp − ( pb )lit ( pb )exp 0.08 0.22 0.15 0.02

xCO2: mole fraction of the gas at the bubble-point pressure; (pb)exp: experimental bubble-

point pressure; (pb)lit: bubble-point pressure from Bennion and Thomas (1993) at 100oC 9 ; b

Oil has a reported API of 27. CO2 was injected at 70 MPa and 423.15 K. The data are taken

from reference. (50).


19

Energy & Fuels

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Page 20 of 39

Crude oil polarity relies upon its constituents in particular the hetero-compounds found in the heaviest fractions of oil (i.e. resins and asphaltenes). They have a considerable surface activity and an ability to stabilize water-in-oil emulsions. Also, CO2 is normally non-polar but upon increasing pressure and temperature as it is the supercritical state, it becomes more polar 55. When the miscibility front is developed within the cell, three intermolecular forces, above presented, act along with a mass transfer involving oil and sCO2. The difference in sCO2 solubility (and bubble-point pressure) in the samples could be, therefore, justify primarily by (1) kinetic and the stability of the equilibrium of intermolecular forces and (2) chemical composition of the oil. Solubility of asphaltene upon supercritical gas injection - Figure 6 shows the results of the solubility of asphaltene-phase and asphaltene aggregation upon increasing the PVT analyzing cell pressure. All investigated samples exhibited an increase in the maximum volume of the asphaltene soluble with the build-up in pressure within the PVT analyzing cell. The increase in pressure forces the gas to dissolve in the oil. As a result, the solubility of asphaltene increases, somewhat, linearly with the concentration of sCO2 at constant temperature. From the thermodynamic model, the increase in asphaltene solubility is inherent to a subsequent increment in the solubility parameter difference between the crude oil and the asphaltenes (and resins) caused by the injected gas. In contrast, asphaltene, present in the oil, tends to disaggregate with the increase in pressure.


20

Page 21 of 39

(a)

(b) 14

T= 40oC

o

37.04

30

16.775

T= 40 C

12

25

8 20 6 15

16.770

% asph, wt. % (φasph)max, vol. %

10

16.765 37.03 16.760

16.755 37.02 16.750

4 10

16.745

2 37.01

5

0 8

10

12

14

% asph, wt. %

35

(φasph)max, vol. %

16.740 8

9

10

11

12

13

16

psat, MPa

psat, MPa

(c)

38.537

o

T= 70 C

52.506

38.536

38.535

52.505

52.504

38.534

% asph, wt. %

52.505

(φasph)max, vol. %

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

Energy & Fuels

52.504 38.533 52.503

38.532

52.503 8

9

10

11

psat, MPa

Figure 6. Estimated maximum soluble asphaltene in heavy and extra-heavy oils (a) HC-1; (b) HC-2; (c) BT-1; () Maximum asphaltene soluble in the crude oil; () Estimated aggregated asphaltene; Dashed square corresponds to experimental bubble-point pressure. This trend was found to change at/near the experimental bubble-point pressure for two of our samples (HC-2 and BT-1) at which minimal solubility (thus, the highest asphaltene aggregation) was observed. The results of estimated deposition in asphaltene (Table 5) tend to corroborate with the literature stating that the deposition in asphaltene is higher at the bubble-point pressure. Table 5. Results of aggregated asphaltene during supercritical CO2 injection a

HC-1 HC-2 BT-1 Lei et al. e a

C/H ratio in asphaltene phase, (-) 0.04 0.11 0.24 -

Deposited asphaltene, 102 wt. % At the bubbleAt the end of point pressure b gas injection c

Flue gas c

Relative deposition d, %

4.9 16.7 52.5 5.47

0.04 -

3.51 11.9 37.6 48.3

2.0 6.6 8.6 -

δasph: solubility parameter of asphaltene phase at the bubble-point pressure;


21

Energy & Fuels

b

Estimated from equation (19);

c

Determined by oil titration;

d

Relative deposition ( %) = 100 deposited asphaltene at bubblepoint pressure / estimated

asphaltene in the feed oil 56 ; e

From reference (46). CO2 was injected at its normal state. The reservoir pressure was

assumed to be equal to 23 MPa. If we accept that asphaltene is in suspension in the crude oil and its stability is dictated by the degree of solubility of sCO2, then the solubility parameter of asphaltene phase (Figure 7) could suggest the behavior of sCO2. It could be seen that the solubility decreases with the pressurization of the cell (valid for HC-1 and HC-2) with a pattern that changes somewhat beyond the bubble-point pressure.

0.35

C/H=0.24

0.30

3 1/2

0.25

δasph, (cal/cm )

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

Page 22 of 39

0.20

C/H=0.04

0.15

0.10

0.05

C/H=0.11

0.00 8

10

12

14

16

psat, MPa

Figure 7. Solubility parameter of asphaltene as function of equilibrium pressure; () HC-1; () HC-2; () BT-1.

Porte et al. (2003) suggests that the dispersion forces developed between the advancing gas and oil may provide a rational explanation 57. In fact, those dispersion forces will act upon the


22

Page 23 of 39

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Energy & Fuels

polarizability of either sCO2 and/or oil. To which, one may account the oiliness of the oil i.e. C/H ratio. Therefore, we suspect that the molecules of asphaltenes (and resins) are attracted to each other caused by the weakness in van der Waals forces. Consequently, asphaltene molecules aggregate and its concentration increases

58

. These results highlight, to a certain

degree, the potential of sCO2 as aggregating (or flocculating) agent. These observations were also reported by various authors who termed CO2 as precipitant rather 50. Beyond the bubble-point pressure, the oil becomes saturated. Any further gas injection induces rather the oil to swell. This is to say that a little change in oil composition, as suggested by Hirshberg et al. (1984), is expected 25. Both Figures 6b and 6c were found to agree with thus those observations, traduced herein by a fairly straight line in aggregation in asphaltene curve. However, Figure 6a showed another pattern in which the solubility was increasing even after the bubble-point pressure. In this oil sample, it is believed that the content in asphaltene is low enough for the aggregates to sustain the operating conditions. A possible re-dissolution (or disaggregation) is thought to occur in this situation, issue which is still subject to controversies. The reverse trend arises an intriguing point. On a thermodynamic point of view, how does the oil swelling affects the process of aggregation/disaggregation of heavy fractions? In fact, the production of heavy oils by gas injection lies upon the swelling of the oil that reduces the viscosity of the residual oil. Thus, it would be interesting to evaluate the influence of dispersion forces in the process of aggregation / disaggregation of asphaltenic materials. PARAMETERS ALTERING THE SOLUBILITY, AGGREGATION AND THE DEPOSITION OF ASPHALTENE Above sections have highlighted tentatively the mechanisms inherent to asphaltene aggregation. Up to this point, we have only focused on how pressure as well as a pure


23

Energy & Fuels

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Page 24 of 39

supercritical gas influenced the deposition process. Parameters that were seen to destabilize the colloidal suspension. The following, we have furthered our analysis to the composition of advancing gas, the injecting temperature and the nature of the crude oil. It should be bear in mind aforementioned parameters were studied at/around the respective bubble-point pressures of the samples. Influence of advancing gas composition on asphaltene solubility - To study the effect of advancing gas composition on asphaltene solubility, we assumed the injection of pure sCO2 (performed experimentally in this work) and impure sCO2. Impure sCO2, in this context, refers to sCO2 enriched with lean gas. Literature reports that the extraction of hydrocarbons from a crude oil is strongly influenced by the density of CO2. The higher the density, the more hydrocarbons could be extracted

59

. On other hand, the true miscible displacement is

achieved only at pressure greater than a certain minimum termed as the minimum miscibility pressure (MMP), at which the crude oil and CO2 become completely miscible forming a single thermodynamic phase. That is to say that at MMP, the displacement efficiency of residual oil is theoretically 100%. Having taken into account those two factors, two impure gases were assumed including an enriched CO2 with methane (CH4) and an enriched CO2 with a mixture of ethane (C2) and propane (C3).mixed at a ratio of 1:1 (v:v). The results calculated by the model are presented in Figure 8.


24

Page 25 of 39

(a) pb= 13.0 MPa

40

(b)

Upper onset

o

Upper onset

pb= 11.5 MPa o T= 40 C

40

T= 40 C

30

30

(φasph)max, vol. %

(φasph)max, vol. %

20

Lower onset

20

Lower onset 10

10

0.0

0.2

0.4

0.6

0.8

0.0

0.2

Fraction of injecting gas in the oil phase, (-)

0.4

0.6

0.8


(c) 100

pb= 9.57 MPa o

90

T= 70 C

80

(φasph)max, vol. %

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

Energy & Fuels

70

60

Lower onset Upper onset

50

40

30 0.0

0.2

0.4

0.6

0.8


Figure 8. Effect of advancing gas purity on asphaltene solubility; (a) HC-1; (b) HC-2; (c) BT-1; () Pure CO2; () CO2 enriched with 50% CH4; () CO2 enriched with 25% of (C2 - C3). As expected, the gas composition was found to alter the solubility of asphaltene in the oils. While asphaltene solubility in the lightest crudes increased with the concentration of advancing gas within the oil, a reverse trend in the heaviest oil (BT-1) was observed (Figure 8c). In either case, the solubility of asphaltene upon injection of pure sCO2 was lowered considerably when the displacing gas was changed. Moreover, the plot further conveys interesting insights on the behavior of the gas while contacting an asphaltene-containing fluid. (i) The effect of advancing gas seemly follows an S-shape (HC-1 and HC-2) and an inverted S-shape (BT-1). It is obvious that the oiliness of the oil, rather its composition


25

Energy & Fuels

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

Page 26 of 39

defines the shape of asphaltene solubility. Further to that, a rational thought may be that at the bubble-point pressure, if the advancing gas concentration is low enough, then an aggregation of heavy fractions might be promoted. However, rather to deposit, the aggregates re-dissolve (most probably because of the weak thermodynamic equilibrium). The concentration at which the aggregates start to re-dissolve (or to disaggregate) and later flow as suspended particles within the oil was termed in this work as low onset concentration. This was chosen by analogy to lower/upper onset pressure1. The disaggregation continues until a concentration of gas (upper onset concentration) at which asphaltene will be totally miscible within the oil. However, if the concentration in asphaltene is high enough (case BT-1), the effect is expected to be reversed. The gas promotes rather an aggregation until the size of asphaltene is large enough to deposit. Another rational explanation would be that the kinetic of aggregation process is fast enough for the aggregates to grow, resulting in a precipitation. In this case, upper onset concentration corresponds to the maximum deposit. Our observations were similarly observed by Al-kafeef et al. (2005)

60

. It could also be thought there should be

threshold values for asphaltene solubility and the oil composition which defines the transition between an S-shape and/or an inverted S-shape. Unfortunately, we could not define these values on this work. Nevertheless, it may be extended that the chemical composition of the oil forces the supercritical gas to behave either as a flocculant or coagulant. Table 6 .Calculated MMPs, onset gas concentrations for investigated dead oils Enriching gas / MMP (in MPa)a / xlower onset b (-) / xupper onset c (-) a gas ratio HC-1 HC-2 BT-1 CO2 a

CH4 C2-C3

1:1 9:20

4.39 a 13.3 a 4.25 a

0.10 b 0.10 b 0.20 b

0.75 c 0.95 c 0.95 c

19.6 a 58.7 a 13.3 a

0.15 b 0.25 b 0.30 b

0.85 c 0.95 c 0.95 c

25.2 a 75.4 a 24.4 a

0.20 b 0.15 b 0.15 b

0.65 c 0.70 c 0.90 c

Gas ratio: dimensionless ratio of mole fraction of primary gas (pure CO2) to enriching gas

(CH4 or lean gas); MMP: minimum miscible pressure. Estimated from Yuang’correlation for

1

Pressure at which asphaltene flocculation begins. In other words, the pressure at which oil with the least amount of flocculent in which aggregated asphaltene particles appear.59


26

Page 27 of 39

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Energy & Fuels

pure CO2

61

, and sebastian’s correlation for impure CO2

62

at the respective experimental

temperatures; b

xlower onset: mole fraction at lower onset;

c

xupper onset: mole fraction at upper onset. (ii) At a fixed concentration of advancing gas, we found an average decrease in asphaltene

solubility of 12%, 24% and 16% in HC-1, HC-2 and BT-1 respectively when MMP of sCO2 increases of about 2% (MMP of sCO2+CH4). On the other hand, the values were found to further be lowered of about 7% in this case when the MMP was lowered on only 0.13%. For practical purpose, it is often common to use a gas whose MMP is low. Thus, based on Figure 8 and Table 6, the preferential order should seemly followed sCO2 > sCO2+Lean gas > sCO2+CH4. However, it should be highlighted that both lower and upper onset concentrations were fairly altered by the change of gas, thus MMPs. For given gas, the heavier the oil, the higher the MMP and its lower onset concentration. Similarly, for a given oil, the more sCO2 is diluted the higher the MMP and its lower onset concentration. Effect of pseudo-equilibrium temperature on asphaltene aggregation – Temperature is a parameter believed to have a less impact compared to reservoir pressure and oil composition. However, if asphaltene and resins are considered in suspension in oil (as defined by many authors), thus its thermodynamic stability (aggregation and/or dissolution) should be a function of the temperature 63. This means that upon injecting a gas, a pseudo-thermodynamic equilibrium will be achieved between the advancing gas and the reservoir fluids. Therefore, the temperature selected should be viewed rather as pseudo-equilibrium temperature when the gas flooding is performed. Three temperatures, 40oC, 55oC and 70oC were selected. The results are illustrated in Figure 8.


27

Energy & Fuels

(a)

18

(b)

Onset concentrations

16

45

12

% asph, wt. %

% asph, wt. %

Lower onset

50

14

10 8 6

40

35

Upper onset 30

25

4

20

2

0.0

0.2

0.4

0.6

0.8

0.0

0.2


0.4

0.8

1.0

(d)

22

70

0.6


(c) Upper onset BT-1

20

CO2 concentration, %

60

% asph, wt. %

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

Page 28 of 39

50

40

30

20

18

HC-2 16

14

12

HC-1

10

10

8

0.0

0.2

0.4

0.6

0.8

1.0

300

320


340

360

380

400

Tinj, K

Figure 9. Effect of reservoir temperature on asphaltene aggregation; (a) HC-1; (b) HC-2; (c) BT-1; () 40oC; () 55oC; () 70oC; () Verdier et al. (2006) 50 Therefrom, the prime information drawn out were: •

The higher temperature, the lower the amount of aggregated asphaltenes.

•

Both lower and upper concentrations for all investigated samples are less altered by the change in temperature.

•

Rather, the onset concentrations were dependent of the nature of the oi (Figure 9d).

However, beyond the low onset, a sharp decrease in deposited asphaltene was observed in the lightest crudes (Figures 9a and 9b). This suggests a possible disaggregation of asphaltene


28

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Energy & Fuels

which further flows as suspended particles (Figure 9b) under the effect of temperature. Additionally, while computing the deposited asphaltene for HC-1, we found that above a gas concentration equal to 0.57, negative values were yielded. The values are nearly the same opposite

of

those

below

that

concentration.

It

is

thus

presage

a

possible

aggregation/flocculation of the oils. When a colloidal suspension is heated, the temperature alters the cohesiveness of intermolecular forces. This is to say that equilibrium temperature will primarily act upon the distribution of the dispersion forces within the system (oil – gas). According to Porte et al. (2003), the solubility parameter of the gas (δlight) evaluated the dispersion forces. We observed that the solvation power of sCO2 increases with the temperature. Considering the fact sCO2 solubility is higher in lighter crude, these observations explain probably the results in Figure 9. Not only the dipole-dipole forces between the advancing gas and the asphaltene molecules are weakened, but also the solvation power in the asphaltene phase (represented by solubility parameter of asphaltene δasph) were found to decrease with the rise of temperature. Thus, it could be suggested that for the same amount of supercritical gas in the oil and its concentration in asphaltene, the advancing gas may either promote aggregation of suspended asphaltenes (if δasph is large enough which is the case in Figure 9c) or an eventual redissolution (if δasph is small. Figure 9a and 9b). Nature of the oil and asphaltene aggregation – This study has investigated experimentally dead crude samples. We sought to validate the thermodynamic model, herein proposed, on live oils. For this purpose, we have taken data from Burke et al. (1990) who presented experimental asphaltene precipitation data on several live-oil/solvent mixtures at reservoir conditions47. The oil has an average precipitates of 7.8%. We repeated the same


29

Energy & Fuels

procedure discussed in above sections and considered two cases including an injection of sCO2 and sCO2 and lean gas which the temperature under the borehole is 120oC and 70oC respectively. The results obtained were compared with the matching model. Figure 10 shows the results obtained thence. (a)

(b)

80

(2)

(2)

80

(3) % asph, wt. %

60

% asph, wt. %

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

Page 30 of 39

40

(3)

60

40

20

20

0 0.0

0.2

0.4

0.6

0.8


1.0

0.2

0.4

0.6

0.8

1.0


Figure 10. Comparison asphaltene aggregation in dead and live oils, (a) Under pure sCO2 at 120oC; (b) Under sCO2 + lean gas at 70oC () BT-1; () Live oil, Data were taken from Burke et a. (1990) 47; (Dotted line) Predictive pattern followed if BT-1 was a live oil. For the two investigated cases, the live oil followed seemly an exponential rise with curvature weaker than that of dead oil. The fashion followed by the dead oil was similar to that of BT-1. With an average precipitate of 12 wt.% (BT-1) and 4.7 wt.% (live oil), if the equilibrium temperature was set at 120oC (Figure 10a), we found the amount of aggregated asphaltene to decrease of about 36% if the live oil was used as starting material. Between the lower onset and upper onset concentration i.e. for a concentration of gas of 10 to 65 % (mol %), the decrease was on the average of 34%. The latter case, i.e. sCO2+ lean gas, the values were 36% and 43% respectively. Also, the dead oil showed, in both study cases, a concave downward curvature that with a plateau value of 70 wt. % and 74 wt. %. Moreover, the upper onset concentration was not altered by either the change in gas composition or the temperature.


30

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Energy & Fuels

Although the amount of estimated aggregated asphaltene were found much lower in live oil, it did not convey much information on the asphaltene flocculation/disaggregation. Rather, it hides somewhat those effects. In fact, the steps through which the asphaltene undergoes including a rapid growth in particles size (1), flocculation and/or settling (2) and disaggregation (3) are not hihhighted. Rather, one may just assume that sCO2 will act as flocculant until the thermodynamic conditions within the reservoir promote a settling. On the other, we may also suspect that the concentration in light fraction, may alleviate the kinetics of asphaltene aggregation. We may, however, confirm these observations through further experiments.

SUMMARY AND CONCLUSIONS This work has presented aggregation of asphaltenic materials during supercritical gas injection. Using different Japanese dead crude oil samples, we have successfully carried out a CO2 injection at its supercritical state. Oil titration test with n-pentane was carried, at room temperature, to estimate the amount of asphaltene contained in the samples. A simplified thermodynamic model, derived from the solubility model and modified from the literature has been also presented. Through which, the solubility of the asphaltene was correlated with the amount of asphaltene that either aggregates or deposits. Additionally, we have investigated the effects of the purity of advancing gas, reservoir temperature (in here simulated by a PVT analyzing cell) as well as the nature of oil. The key highlights of this work are: (1) The solvation power of the titrant depends not only on its molecular weight, as it has been demonstrated by published works, but also of the carbon-to-hydrogen ratio of the solute i.e. oil.


31

Energy & Fuels

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(2) The kinetics and the stability of the equilibrium of intermolecular forces developed between supercritical CO2 and dead oil composition during the development of the miscibility front participate actively at the alteration of both gas solubility and-bubble point pressures. (3) Thermodynamically, the decrease in solubility parameters of asphaltene subsequent to the build-up in pressure increases the solvating strength of the supercritical CO2. Both phenomena, occurring concurrently, cause invariably a more soluble asphaltene. (4) The concentration and purity of supercritical gas force asphaltene solubility to increase following an S-shape if the oil is light. A decrease following an inverted S-shape is expected if the asphaltene content is high enough. Near the bubble-point pressure, and depending on oil composition, the supercritical gas develops a potential as either a flocculent or coagulant. (5) Pseudo equilibrium temperature alters the solubility parameter of asphaltene and supercritical gas. The solvating power of the gas is thus enhanced as a result promoting either aggregation of suspended asphaltenes (extra heavy oil) or re-dissolution (heavy oils). (6) The concentration of a crude oil in light component alleviates aggregation in asphaltenic materials. AUTHOR INFORMATION * [email protected] AUTHOR CONTRIBUTIONS All authors have given approval to the final version of the manuscript. ACKNOWLEDGMENT


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The authors would like to extend their gratitude towards Japan Petroleum Exploration (JAPEX) for supplying the dead crude oils with their assays. The authors also thank the Ministry of Education, Culture, Sports, Science, and Technology of Japan (MEXT) for the financial support. Last but not least, this work is dedicated to the memory of Ronald’s late mother Rose Nguele. REFERENCES (1). (2)

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TABLE OF CONTENTS Introduction……………………………………………………………………………

2

Materials And Methods………………………………………………………………. Materials……………………………….……………………………………………..

6

Methods……………………………………………………………………………….

6

Asphaltene precipitation by oil titration……………………………………………

6

Supercritical gas injection …………………………………………………………

7

Crude oil characterization……………..……………………………………………...

8

Thermodynamic model of asphaltene aggregation and deposition…………………

12

Results and discussions………………………………………………………………..


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Crude oil titration and supercritical gas solubility………………………………...

16

Solubility of asphaltene alteration by upon supercritical gas injection………

18

Parameters altering the solubility, aggregation and the deposition of asphaltene Influence of advancing gas composition on asphaltene solubility …………….....

21

Effect of pseudo-equilibrium temperature on asphaltene aggregation…………

24

Nature of the oil and asphaltene aggregation………………………………………

28

Summary and Conclusions……………………………………………………………

26

Author Information……………………………………………………………………

27

Author Contribution…………………………………………………………………..

27

Acknowledgement……………………………………………………………………...

27

References………………………………………………………………………………

27


39

Asphaltene Aggregation in Crude Oils during Supercritical Gas

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