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Asphaltene Deposition during Bitumen Extraction with Natural Gas Condensate and

Naphtha

ZhenBangQi, Ali Abedini, Atena Sharbatian, Yuanjie Pang, Adriana Guerrero, David Sinton

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Citation (published version)

Qi, ZhenBang, Ali Abedini, Atena Sharbatian, Yuanjie Pang, Adriana Guerrero, and David Sinton. "Asphaltene Deposition during Bitumen

Extraction with Natural Gas Condensate and Naphtha." Energy & Fuels (2017).

Publisher’s Statement “This document is the Accepted Manuscript version of a Published Work that appeared in final form in Energy and Fuels, copyright ©

American Chemical Society after peer review and technical editing by the publisher. To access the final edited and published work see

10.1021/acs.energyfuels.7b03495.”

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1

Asphaltene Deposition during Bitumen Extraction with Natural Gas

Condensate and Naphtha

ZhenBang Qi,† Ali Abedini,

† Atena Sharbatian,

† Yuanjie Pang,

† Adriana Guerrero

b,‡ David Sinton

*†

† Department of Mechanical and Industrial Engineering and Institute for Sustainable Energy, University

of Toronto, 5 King’s College Road, Toronto, ON, M5S 3G8, Canada

‡ Suncor Energy Inc., 150 – 6 Ave SW, Calgary, AB, T2P 3E5, Canada

ABSTRACT

Solvent bitumen extraction processes are alternatives to thermal processes with potential for

improved economic and environmental performance. However, solvent interaction with bitumen

commonly results in in situ asphaltene precipitation and deposition, which can hinder flow and

reduce the process efficiency. Successful implementation requires selecting a solvent that

improves recovery with minimal flow assurance problems. The majority of candidate industrial

solvents are in the form of mixtures containing a wide range of hydrocarbon fractions, further

complicating the selection process. In this study, we quantify the pore-scale asphaltene

deposition using two commonly available solvent mixtures, natural gas condensate and naphtha,

using a microfluidic platform. The results are also compared with those of two typical pure

solvents, n-pentane and n-heptane, with all cases evaluated with both 50 and 100 µm pore-throat

spacing. The condensate produced more asphaltenes and pore-space damage than the naphtha,

and exhibited deposition dynamics similar to that of pentane and heptane. This similarity is due

to the presence of a large amount of light hydrocarbon fractions in condensate (~85 wt% of C5s–

C7s) dictating the overall deposition dynamics. Naphtha which contains heavier fractions (~70

wt% of C8s–C11s) and aromatic/naphthenic components generated less asphaltenes and exhibited

a slower deposition rate, resulting in less pore damage and overall better performance.

2

1. INTRODUCTION

Thermal processes such as steam-assisted-gravity drainage (SAGD) have been widely

employed for bitumen extraction.1–3

SAGD involves injecting the saturated steam into the

reservoir to lower the viscosity of the bitumen by the steam latent heat generation, which in turn

results in bitumen flow toward the producer under gravity drainage. The typical time frame for

field scale SAGD process is over 10 years, depending on the formation size, reservoir

characteristics, and operational parameters.4 While thermal processes are effective, they have

significant economic and environmental challenges.4 Solvent-based processes are proposed as an

alternative to thermal processes to improve the recovery performance and reduce the greenhouse

gas emission associated with bitumen production.5–8

However, hydrocarbon solvents have been

reported to have caused pore-throat plugging and reservoir damage due to asphaltene deposition,

particularly near the well-bore.9–11

Asphaltenes are the heaviest fraction of crude oil, mainly

composed of aromatic rings containing heteroatoms (e.g., nitrogen, oxygen, sulfur, and metals)

attached to alkane chains. Asphaltenes are generally defined as crude oil fractions that are n-

alkanes-insoluble and toluene-soluble.12

During solvent injection, hydrocarbon solvents

containing n-alkanes (e.g., pentane or heptane) dilute the bitumen, which results in precipitation

of asphaltenes.13

The precipitated asphaltenes aggregate and form large asphaltene micelles that

deposit on the rock surfaces.14–18

The removal of asphaltenes from the produced fluid can be a

benefit as it reduces the fluid viscosity, provided that the precipitated asphaltenes cause minimal

or acceptable levels of reservoir damage via clogging of pores, reducing the permeability of the

reservoir rock.19–22

Permeability reduction results in low recovery of both oil and injected

solvents. Precipitated asphaltenes can also be a challenge for down-hole production units as well

as the surface facilities. Therefore, it is important to understand how and to what extend

3

asphaltenes precipitate and deposit due to solvent injection in order to properly design and

implement solvent-based injection processes as viable alternatives to steam.

Asphaltene precipitation and deposition is a complex phenomenon due to the complex

solvent-oil phase behavior. Series of experiments have been carried out to quantify the

asphaltene precipitation and resulting formation damage during enhanced oil recovery processes.

A high-temperature high-pressure PVT cell was used to study the effects hydrocarbon solvent

dilution ratio, temperature, and pressure on the asphaltene onset and precipitation rate.23–25

Slim

tube apparatus was also employed to monitor the pressure fluctuation and flow turbulence as a

result of asphaltene precipitation during solvent injection.26

In addition, high-pressure

coreflooding has been applied to estimate permeability reduction as a result of asphaltene

deposition during immiscible and miscible CO2 injection processes.27–29

Asphaltene deposition

during vapor extraction process with propane and butane has been measured using sand-packed

physical models.30,31

In addition, the roles of morphology and mineralogy of the rock were

analyzed with regard to asphaltene deposition and associated reservoir damage.32

However, these

previous methods provide macroscopic damage measurements (e.g., permeability reduction), and

cannot resolve the pore-scale dynamics inherent to reservoir processes.

Microfluidics is an emerging technology within the energy sector that allows direct

visualization and rapid quantification of phase properties and fluid transport.33–47

There is

precedent for microfluidic pore-scale analysis of asphaltene precipitation and deposition.37,48–53

Asphaltene precipitation and deposition have been investigated using a uniformly patterned glass

micromodel with a synthesized crude oil and n-heptane.48

Pore-scale of asphaltene precipitation

during solvent-based recovery processes were visualized using micromodels, indicating that

asphaltenes reduced the displacement efficiency mainly through blocking the pore throats and

4

changing the surface wettability.37,49–51

Another microfluidic device was used to analyze the

dynamics of the asphaltene deposition in the porous media using different volumetric ratios of n-

heptane.52

Once a local deposition was initially formed on a post, further asphaltene deposition

grows in low-shear zone, which is against the fluid flow direction. A similar microfluidic

platform was also applied to evaluate the role of chemical dispersants on asphaltene deposition

kinetics. The results showed that the deposition rate is a function of the intermolecular

interactions of asphaltene–dispersant system.53

The majority of the previous microfluidics-based

studies employed a synthesized crude oil (e.g., dissolved asphaltene in toluene) and a single

precipitant or pure solvent (e.g., pentane or heptane). While the results provide insight into the

dynamics of asphaltene precipitation, relevant asphaltene deposition data from industrial solvent

mixtures is required for selecting a solvent that improves the recovery with minimum flow

assurance problems.

Diluents (i.e., industrial solvents containing wide range of hydrocarbon fractions) are

diluting or thinning agents which are used for reducing the viscosity of the processed bitumen,

allowing it to be pumped through pipelines. Typical diluents are in the form of natural gas

condensate, refined naphtha or synthetic crude oil.54

Recently, diluent has been applied for

solvent-based bitumen extraction processes in the field.55

Depending on the composition of

different diluents, they exhibit distinct phase behavior once mixed with bitumen, and to date, the

available data on asphaltene deposition dynamics due to diluent injection is limited.

In this paper, we determine the pore-scale of asphaltene deposition using two pure

solvents (i.e., n-pentane and n-heptane) and two industrial diluent samples (i.e., condensate and

naphtha) currently employed for solvent process pilot-test implementations in the Athabasca

formation. Microfluidic chips with 50 and 100 µm pore-throat spacings were imaged with optical

5

and fluorescence microscopy to quantify the formation damage and deposition dynamics during

solvent injection into bitumen-filled porous media. Scanning electron microscopy (SEM),

fluorescent emission spectrum analysis, and viscosity measurements are also conducted to

characterize the precipitated asphaltenes and deasphalted oils obtained by each solvent.

2. EXPERIMENTAL

2.1. Fluids. A bitumen sample was procured from the Athabasca oil sands in Alberta, Canada.

The fluid properties of the bitumen are presented in Table 1. The bitumen molecular weight and

density were 596.8 g/mol and 1.017 g/cm3, respectively. For convenience of transport, the

bitumen sample was diluted with toluene with mass ratio of 1:1. Two pure hydrocarbon solvents

including n-pentane (Sigma-Aldrich, ≥99%) and n-heptane (Sigma-Aldrich, 99%) and two

diluent samples namely condensate and naphtha (provided by Suncor Energy) - with the fluid

properties presented in the Table 1 - were used for asphaltene experiments. Suncor Energy

provided the measured values for molecule weight of the bitumen, natural gas condensate, and

naphtha and the measured density. The fluid properties and composition of the two diluent

samples were markedly different. The condensate sample contained ~85 wt% of C5s–C7s with a

molecular weight of 82.5 g/mol, that was much lighter than the diluent sample. The naphtha was

rich in heavier hydrocarbon solvents, ~70 wt% of C8s–C11s, with a molecular weight of 116.0

g/mol. The compositional analysis of the condensate and naphtha samples are presented in the

Supporting Information. The asphaltene content of the bitumen for all solvents was measured

using ASTM D2007 titration method at room temperature and reported in Table 1.56

The

deasphalted bitumen sample for each solvent was collected after removing the solvents using a

vacuum oven heated to 100 ºC. QUANTA FEG 250 ESEM was used to take SEM images of the

6

asphaltene particles produced by each solvent. All deasphalted bitumen samples were mixed

with toluene with mass ratio of 1:1. The viscosity of the deasphalted samples and the original oil

were measured using AR2000 Rheometer. Thereafter, the deasphalted samples were mixed with

the solvents with mass ratio of 1:4. The fluorescent emission spectrum for original oil and oil-

solvent mixtures were measured using Nikon A1 confocal microscope with 486 nm laser as the

excitation source.

Table 1. Fluid properties of the Athabasca bitumen and hydrocarbon solvents used in microfluidic

asphaltene experiments (the properties are reported at 21ºC).

Fluid Molecular

weight

(g/mol)

Density

(g/cm3)

Viscosity

(mPa.s)

Asphaltene

yield

(wt%)

Comments

Athabasca

bitumen

596.8 1.017 > 106

Bitumen sample has over 90

wt% of C20+ and over 70% of

C30+. There are little light

components in the bitumen (C1–

C10 < 0.1 wt%).

n-pentane* 72.15 0.626 0.23 43 n-C5 was purchased from Sigma-

Aldrich with 99.5 mol% purity.

n-heptane* 100.20 0.684 0.41 29 n-C7 was purchased from Sigma-

Aldrich with 99.5 mol% purity.

Condensate 82.5 0.648 0.28 35 Condensate sample contains ~85

wt% of C5s–C7s.

Naphtha 116.0 0.757 0.43 2 Naphtha sample contains ~70

wt% of C8s–C11s.

* Data of pure solvents are taken from National Institute of Standards and Technology (NIST)

2.2. Microfluidic apparatus. Figure 1a shows the schematic diagram of asphaltene deposition in

the porous media. A silicon-glass microfluidic chip was designed and fabricated using deep

reactive ion etching (DRIE) and a shadow mask process. Two distinct porous patterns were

fabricated to model the pore network of a typical oil sand formation. The pore and grain sizes of

unconsolidated oil sands typically found in Athabasca formation are in a range of 40–180 µm

7

and 45–250 µm, respectively.57–59

Both patterns have the same diamond-shape grains (dp = 150

µm) but with two separate pore throat sizes of 50 µm and 100 µm as shown in Figure 1b. The red

arrows represent pore throat and yellow arrows are defined as the paths for fluid to flow in this

paper. The length and depth of the porous media were 5.4 mm and 60 (±1) µm, respectively. The

width for the micromodel was five posts for both pore throat sizes. The porosities for the 50 µm

and 100 µm micromodel are 67% and 78%, respectively. A syringe pump (Harvard Apparatus)

and a Isco pump (Teledyne-Isco 260D) were used to inject oil and solvent into the microfluidic

chip, respectively.

2.3. Experimental procedure. The microfluidic chip was mounted in a custom stainless steel

manifold. The chip and manifold were placed under the microscope with required fluid lines

connected. An Olympus BXFM microscope with X-CITE 120 LED light source connected to the

Leica MC 170 HD camera was used to monitor the process. Oil was initially injected into the

microchip for several pore volumes using syringe pump to completely fill the porous media with

no trapped air. Afterward, the solvent was injected into the chip under constant flow rate of

30 µL/min using the Isco pump. The total volume for the 50 µm and 100 µm microfluidic chips

is 0.4 µL and 0.5 µL, respectively. 30 µL/min flow rate is equivalent to 1.25 liquid volumes per

second for the 50 µm chip and 1 liquid volume per second for the 100 µm chip. The time-lapsed

solvent-oil interaction and asphaltene deposition were imaged by fluorescence microscopy with

FTIR filter cube (λex=475 nm/50 nm; λem=540 nm/50 nm). These images were used to quantify

the asphaltene deposition rate for each solvent. Deposition rate is most relevant with respect to

formation damage, and is distinct from other measures, such as the total precipitation rate. Oil

exhibits fluorescent properties with a green color under the microscope, which can be easily

differentiated from the asphaltenes which do not emit any fluorescent signal due to

8

quenching.60,61

At the end of each test, an optical scan of the entire porous media was conducted

using the bright-field microscopy.

3. RESULTS AND DISCUSSION

3.1. Asphaltene and deasphalted oil characterization. The characteristics of both asphaltenes

and the produced deasphalted oil varies greatly with the solvent type. Figure 2 shows the SEM

images of the asphaltenes produced from all solvents tested in this study under the 2000-fold

magnification. While the n-pentane asphaltenes are porous, n-heptane produced asphaltenes with

a smooth surfaces and sharp edges. Differences in the morphology of asphaltenes are due to the

differences in removal of resins and other lighter oil fractions as well as rate of asphaltene

precipitation and dissolution.62–64

In contrast with n-heptane, n-pentane produces asphaltene

aggregates with more resins attached to the asphaltene micelles11

. On the other hand, the

precipitation of asphaltenes with n-heptane is relatively slower than that of n-pentane, providing

a longer time for asphaltenes to form aggregates with rigid structures. The morphology of

condensate asphaltenes is similar to that of n-heptane asphaltenes mainly due to the presence of

light fractions (pentane, heptane) in the condensate composition. For naphtha case, the

morphology of the asphaltenes is different with that of other solvents considered here.

Specifically, the naphtha sample has a much higher solubility parameter due to presence of

heavier alkanes and naphthenic/aromatic components. The combined effect was significant,

producing less asphaltenes than the other solvents. Here, the asphaltene aggregates are soft with

powder-like structure and rough surfaces (Figure 2).

Figure 3a compares the fluorescent emission spectrum measurement of the original oil with those

of the oil-solvent mixtures with precipitated asphaltenes taken out of solution. In contrast with

the original oil sample, the fluorescent emission of the mixtures was blue-shifted (moved left)

9

and narrowed, agreeing with the dilution effects of the solvents as reported in previous studies.65

While the oil emission is spectrally distinct from that of the solvent-exposed oil, the mixtures

were not distinguishable at this excitation wavelength. Figure 3b plots the viscosity of the

produced deasphalted oil for each solvent. Since n-pentane yields the largest amount of insoluble

asphaltene content (~43 wt%), the produced deasphalted oil has the lowest viscosity (36 mPa.s).

In contrast, the naphtha deasphalted oil has the largest viscosity (130 mPa.s) due to the small

yield of insoluble asphaltene (~2 wt%).

3.2. Asphaltene deposition in porous media. A series of solvent injection tests were conducted

using two micromodels with 50 and 100 µm pore spacing with the results shown in Figure 4.

Figure 4a shows a typical original full-scale image with the deposited asphaltene particles in the

pore network (left side) with the corresponding post-processed image using ImageJ software

(right side) in which the black area shows the area occupied by asphaltenes. It is noted that the

inlet channel leading into the porous medium was initially filled with the oil, which is an extra

source for asphaltene deposition in the porous media. Figure 4b compares the amount of the

deposited asphaltenes obtained from all solvent runs for both 50 and 100 µm cases. Comparing

the two pure solvents, pentane precipitated a larger amount of asphaltenes in the porous medium

than heptane – in agreement with previous studies.25

The condensate sample, however,

precipitated less asphaltenes than pentane and more than pure heptane. We attribute this

difference to the large quantity of n-alkanes in the condensate, specifically C5s and C6s (i.e., ~70

wt%), that resulted in significant asphaltene deposition in the porous media (in between that of

pentane and heptane). The naphtha generated the least asphaltenes in the porous media due to the

presence of heavier fractions in general. While the results are consistent for both 50 and 100 µm

cases, the amount of the deposited asphaltenes in the 50 µm is larger in all cases.

10

Figure 5a through 5c quantify the percentage of damaged area, pore throat blockage, and path

blockage as a result of asphaltene deposition for all solvents in 50 and 100 µm micromodels. In

agreement with the optical overall images, pentane produced the most severe damage to the

reservoir in terms of formation damages while naphtha produced the least amount of damage. In

all cases the degree of formation damage reduced with increasing the pore geometry, however

naphtha showed the most significant reduction in percentage of damaged area from 68.7% to

38.5% (~44.0% reduction). All other solvents showed only moderate reduction - n-pentane

(11.7% reduction), n-heptane (19.2% reduction), and condensate (14.4% reduction). The trends

in total area damage are similar to those of pore-throat blockage (Figure 5b). In terms of pore-

path blockage, however, the heptane and naphtha showed very significant reductions in blockage

(Figure 5c).

3.3. Asphaltene deposition dynamics. Figure 6a shows the pore area occupied by deposited

asphaltenes on a single post over 10 min of process in 50 µm micromodel for all solvents with

the deposition growth quantified in Figure 6b. The intensities of the brown color refer to

deposition in different times. Dark brown, lighter brown and the lightest brown colors here

represent the amount of asphaltenes deposited on the post after 2, 5, and 10 min. It was observed

that majority of the asphaltenes deposited on the left tip of the grain, and grew opposite to the

flow direction. The tip of the grain was the earliest point of contact and a stagnation point where

the velocity of flow approaches zero, allowing asphaltene particles to deposit – in agreement

with previous studies.52

The velocity profiles for both 50 µm and 100 µm cases are presented in

the Supporting Information, showing the minimum flow velocity at the tip and near the boundary

of the grains. After the initial deposition, the asphaltenes accumulated and grew in size at the tip,

eventually reaching the adjacent grain to form a blockage in the path. N-pentane has the highest

11

asphaltene deposition rate followed by condensate, n-heptane and naphtha. The early time

deposition of asphaltenes for heptane and naphtha (t = 2 min) was very minimal - nearly

invisible, while the pentane and condensate resulted in severe deposition with half blockage after

2 min and full blockage after 5 min. The results obtained here provides insight to field-scale

process as the amount of oil-in-place is fixed in the reservoir and thus different solvents have

different asphaltene deposition rates and lead to varying degrees of reservoir damage.

With the strong performance of naphtha at early times compared to the other solvents tested, we

analyzed the asphaltene deposition of naphtha over a longer duration – 60 min in both 50 µm and

100 µm micromodels. Naphtha showed a significant reduction in damaged area, pore-throat

blockage, and path blockage when the pore size was increased from 50 µm to 100 µm. The time-

lapsed images of the asphaltene deposition in the both porous media for naphtha at 2, 30, and 60

min were shown in Figure 7a. Figure 7b shows the asphaltene deposition growth for both 50 µm

and 100 µm pore sizes. While the initial deposition rate in both patterns was the same, the total

growth of deposited asphaltenes was larger in 50 µm case. Since the pore space of 50 µm

micromodel is smaller, the deposited asphaltene aggregates reached the adjacent post sooner and

blocked the entire flow path. This path blockage further contributed to additional asphaltene

deposition, generating larger areas occupied by asphaltenes. On the other hand, the pore spacing

is much wider for the 100 µm micromodel and the asphaltene aggregates on a post could hardly

reach the adjacent post to block the entire path. With much less flow hindrance and blocked

paths, the asphaltene particles flowed readily with the deasphalted oil through the porous

medium toward the outlet. Furthermore, the narrow arrow shape deposition has higher shearing

rate near the boundary of the deposited asphaltenes, leading to less additional accumulation after

20 minutes of injection.52

12

4. CONCLUSION

In this study, the asphaltene deposition during solvent injection was studied using both pure and

industrial hydrocarbon solvents. The produced asphaltenes and deasphalted oil sample for each

solvent-bitumen system were characterized. In addition, microfluidic tests combined with high-

resolution optical imaging quantified in situ pore-scale data of asphaltene deposition in the

porous media. The results indicated that:

The morphology of asphaltene particles and viscosity of produced deasphalted oil as well as

the amount and rate of asphaltene deposition vary with solvent composition.

The condensate with larger concentration of n-alkanes, specifically C5s and C6s, produced

more asphaltenes with faster deposition dynamics similar to the pure solvents, n-pentane and

n-heptane.

The naphtha, which contained heavier hydrocarbon fractions and aromatic/naphthenic

components resulted in less precipitation of asphaltenes with slower deposition rate and pore

damage in the porous media with a potential of minimal flow assurance problems for field-

scale implementations.

The formation damage due to asphaltene deposition decreased in larger pore sizes. This

reduction is more pronounced for naphtha case since the deposited asphaltenes did not reach

the adjacent posts to block the entire path.

ASSOCIATE CONTENT

13

Supporting Information. Compositional analysis of condensate and naphtha; Asphaltene

deposition growth in the 50 µm and 100 µm microfluidic chips vs. number of volume

displacement; The velocity profile inside the 50 µm and 100 µm microfluidic chips.

AUTHOR INFORMATION

Corresponding Author

* E-mail: sinton@mie.utoronto.ca; Phone: +1 416 978 1623

Notes

The authors declare no competing financial interest.

ACKNOWLEDGEMENTS

The authors gratefully acknowledge funding from Suncor Energy Inc. for financial

supporting an ongoing collaborative research project on the solvent injection process. The

authors would also like to thank Natural Sciences and Engineering Research Council of Canada

(NSERC) for their funding support through the Collaborative Research and Development

Program, the Discovery Grant Program, the Discovery Accelerator Program, an E.W.R. Steacie

Memorial Fellowship (DS), and a Postdoctoral Fellowship (AA). Support through the Canada

Research Chair Program is also gratefully acknowledged, as is infrastructure provided by the

Canada Foundation for Innovation. Authors also thank Dr. Yihe Wang for her assistance in

fluorescence spectrum measurements.

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19

Figure 1. a) Schematic diagram of asphaltene deposition in micromodel with solvent flow direction

shown with red arrows, and b) pore-scale bright-field optical images of micromodels with 50 and

100 µm pore spacing (red and yellow arrows represent pore throat and pore path, respectively).

20

Figure 2. SEM analysis of asphaltenes produced from different solvents: a) n-pentane, b) n-

heptane, c) condensate, and d) naphtha under the 2000x magnifications.

21

Figure 3. a) Fluorescent spectroscopy comparison of original oil and oil-solvent mixtures after

removal of precipitated asphaltenes. b) the viscosity of the produced deasphalted oil for each

solvent. Viscosity tests were conducted off-chip with AR2000 Rheometer, using deasphalted oil

samples obtained by ASTM D2007 (error bar represents one sample standard deviation of analyses

in triplicate). The percent asphaltenes removed is indicated where applicable.

22

Figure 4. a) Typical original full-scale image of the chip (left side) with the corresponding post-

processed image using ImageJ software (right side); (b) post-run optical microscopy of the entire

porous media for all solvent runs and both 50 and 100 µm cases.

23

Figure 5. Porous media damage quantification: a) total damage area, b) pore throat blockage, and

c) path blockage for all solvents in both 50 and 100 µm micromodels after 90minutes of runtime

when no significant change was observed afterward (equivalent to 2700 µL of solvent injection).

24

Figure 6. Asphaltene deposition dynamics: a) pore area occupied by deposited asphaltenes on a

single post over 10 min of process in 50 µm micromodel, and b) average asphaltene deposition

growth in the model for all solvents.

25

Figure 7. Asphaltene deposition growth in 50 and 100 µm micromodels: a) pore-scale deposition on

the posts, and b) time-lapsed asphaltene deposition growth.