Asphaltene Deposition during Bitumen Extraction with Natural Gas

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Cite This: Energy Fuels 2018, 32, 1433−1439

Asphaltene Deposition during Bitumen Extraction with Natural Gas Condensate and Naphtha ZhenBang Qi,† Ali Abedini,† Atena Sharbatian,† Yuanjie Pang,† Adriana Guerrero,‡ and David Sinton*,† †

Department of Mechanical and Industrial Engineering and Institute for Sustainable Energy, University of Toronto, 5 King’s College Road, Toronto, Ontario M5S 3G8, Canada ‡ Suncor Energy Inc., 150 6 Ave SW, Calgary, Alberta T2P 3E5, Canada S Supporting Information *

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 one to select 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.

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 the 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 © 2017 American Chemical Society

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 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. A 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 the 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 Received: November 13, 2017 Revised: December 21, 2017 Published: December 22, 2017 1433

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The properties are reported at 21°C. bData of pure solvents are taken from National Institute of Standards and Technology (NIST).

43 29 35 2 0.626 0.684 0.648 0.757 72.15 100.20 82.5 116.0

0.23 0.41 0.28 0.43

1.017

Athabasca bitumen n-pentaneb n-heptaneb condensate naphtha

596.8

>10

6

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-scales 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 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 the 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 the 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 a 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

Figure 1. (a) Schematic diagram of asphaltene deposition in micromodel with solvent flow direction shown with red arrows, and (b) porescale bright-field optical images of micromodels with 50 and 100 μm pore spacing (red and yellow arrows represent pore throat and pore path, respectively).

a

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-C5 was purchased from Sigma-Aldrich with 99.5 mol % purity. n-C7 was purchased from Sigma-Aldrich with 99.5 mol % purity. Condensate sample contains ∼85 wt % of C5s−C7s. Naphtha sample contains ∼70 wt % of C8s−C11s.

comments asphaltene yield (wt %) viscosity (mPa·s) density (g/cm3) molecular weight (g/mol) fluid

Table 1. Fluid Properties of the Athabasca Bitumen and Hydrocarbon Solvents Used in Microfluidic Asphaltene Experimentsa

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Energy & Fuels the Athabasca formation. Microfluidic chips with 50 and 100 μm pore-throat spacings were imaged with optical 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 SECTION 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 the 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 °C. QUANTA FEG 250 ESEM was used to take SEM images of the 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

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.

Figure 2. SEM analysis of asphaltenes produced from different solvents: (a) n-pentane, (b) n-heptane, (c) condensate, and (d) naphtha under the 2000× magnifications. 1435

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Energy & Fuels solvents with mass ratio of 1:4. The fluorescent emission spectrum for original oil and oil−solvent mixtures were measured using a Nikon A1 confocal microscope with 486 nm laser as the excitation source. 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 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 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 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 the 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 and 100 μm microfluidic chips is 0.4 and 0.5 μL, respectively. Thirty 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 an 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 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 micelles.11 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 the naphtha case, the morphology of the asphaltenes is different from that of other solvents considered here. Specifically, the naphtha sample has a much higher solubility parameter due to the 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) and narrowed, agreeing

Figure 4. (a) Typical original full-scale image of the chip (left side) with the corresponding postprocessed image using ImageJ software (right side); (b) postrun optical microscopy of the entire porous media for all solvent runs and both 50 and 100 μm cases. 1436

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Energy & Fuels 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 postprocessed 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. Figure 5a−c quantifies 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 was reduced with an increase in 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 a 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 the 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 and 100 μm

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

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 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 provide insight into the 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 and 100 μm micromodels. Naphtha showed a significant reduction in damaged area, pore-throat blockage, and path 1437

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patterns was the same, the total growth of deposited asphaltenes was larger in the 50 μm case. Since the pore space of the 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 min of injection.52

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 the following. • 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 the naphtha case since the deposited asphaltenes did not reach the adjacent posts to block the entire path.

Figure 6. Asphaltene deposition dynamics: (a) pore area occupied by deposited asphaltenes on a single post over 10 min of process in a 50 μm micromodel and (b) average asphaltene deposition growth in the model for all solvents.

blockage when the pore size was increased from 50 to 100 μm. The time-lapsed images of the asphaltene deposition in 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 and 100 μm pore sizes. While the initial deposition rate in both

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ASSOCIATED CONTENT

* Supporting Information S

The Supporting Information is available free of charge on the ACS Publications website at DOI: 10.1021/acs.energyfuels.7b03495. Compositional analysis of condensate and naphtha; asphaltene deposition growth in the 50 and 100 μm microfluidic chips vs number of volume displacement; the velocity profile inside the 50 and 100 μm microfluidic chips (PDF)

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AUTHOR INFORMATION

Corresponding Author

*E-mail: [email protected]. Phone: +1 416 978 1623. ORCID

David Sinton: 0000-0003-2714-6408 Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS The authors gratefully acknowledge Suncor Energy Inc. for financially supporting an ongoing collaborative research project on the solvent injection process. The authors would also like to thank

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. 1438

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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 (D.S.), and a Postdoctoral Fellowship (A.A.). 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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DOI: 10.1021/acs.energyfuels.7b03495 Energy Fuels 2018, 32, 1433−1439