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Cite This: Energy Fuels 2019, 33, 5933−5943
Bitumen Coating on Oil Sands Clay Minerals: A Review Qiang Chen† and Qi Liu*,‡ †
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Key Laboratory of Coal Processing and Efficient Utilization (Ministry of Education), School of Chemical Engineering and Technology, China University of Mining & Technology, Xuzhou, Jiangsu 221116, China ‡ Department of Chemical and Materials Engineering, University of Alberta, Edmonton, Alberta T6G 1H9, Canada ABSTRACT: Contamination of bitumen products by mineral solids is an intractable problem in the oil sands industry. Clay minerals with a bitumen coating, a major component of the mineral solids contaminants in bitumen, adversely affect bitumen production in multiple ways: hindering bitumen extraction, hindering dewatering of extraction tailings, stabilizing water-inbitumen emulsions, lowering the quality of bitumen, and so on. In this review, the recent progresses in understanding these bitumen-coated clay particles are summarized, particularly focusing on the spatial distribution of the bitumen coating on clay surfaces and the effect of such coating on clay behaviors. Here, “bitumen coating” is defined as all types of irreversibly adsorbed organic matter on oil sands clay minerals, including (but not limited to) asphaltenes and humic materials. The patchy nature of this bitumen coating has been proven and visualized in several recent works where different approaches have been used, including quantitative nanomechanical atomic force microscopy, total internal reflection fluorescence microscopy, and electron energy-loss spectroscopy. The presence of a bitumen coating makes the clay particles behave “actively” in bitumen production processes, causing the clays to migrate to bitumen products, i.e., water-extracted bitumen froth and solvent-extracted bitumen. The available methods for removal of fine mineral solids from the bitumen products are described. This review also brings forward the challenges and opportunities for future research regarding the characterization and handling of oil sands clay minerals.
1. INTRODUCTION The Alberta oil sands, the third-largest proven oil reserve in the world, contributed 2.8 million barrels of crude oil per day to the global demand in 2017.1 As an important unconventional oil resource, the oil sands contain bitumen (a highly viscous liquid or semisolid form of petroleum), mineral solids (mainly clays and quartz), and water. Two main methods, i.e., surface mining and in situ recovery, are used for the recovery of bitumen from Alberta oil sands.2 Since the contamination of in situ extracted bitumen by fine clay solids is less significant in comparison to surface-mined bitumen,2,3 this review will focus on surface mining of oil sands. Surface mining is applied in relatively shallow oil sands ores (less than ∼75 m of overburden),2 where the oil sands are mined and transported using shovels and trucks. Water-based extraction (Figure 1A) is currently commercially used to liberate and separate bitumen from a mineral matrix. As illustrated in Figure 1A, the conditioned aqueous oil sands slurry is sent to a large gravity separation vessel through a hydrotransport pipeline.4 Entrained or introduced air bubbles attach to bitumen, and the aerated bitumen floats to the surface of the slurry in the vessel, forming a bitumen froth product which typically contains about 60 wt % bitumen, 30 wt % water, and 10 wt % fine solids. Meanwhile, most of the mineral solids in the oil sands settle to the bottom in the separation vessel, forming a waste stream known as primary extraction tailings. The fine solids and water in the bitumen froth must be removed through a froth treatment step to prevent negative impacts on pipeline transportation and downstream upgrading/refining operations. The froth treatment tailings usually are pipelined separately to a tailings settling basin. In Figure 1A, an upgrader is shown to follow the © 2019 American Chemical Society
froth treatment. This is only the case when the froth treatment is carried out by using naphtha (naphthenic froth treatment). When an alkane is used in the froth treatment (paraffinic froth treatment), the upgrader is not required. Because of the potential advantages such as significantly reduced demand for fresh water, elimination of wet tailings which necessitates large areas of tailings ponds, and high bitumen recovery (particularly in the case of low-grade or oilwetted deposits), the nonaqueous extraction process has been studied at bench and pilot scales in the last several decades, where organic solvent(s), such as naphtha, cyclohexane, and so on, is used to partially or completely replace water in the extraction operations, as illustrated in Figure 1B.4,6−9 Unfortunately, no nonaqueous extraction technology has been implemented commercially because of the obstacles such as difficulties in removing the fine solids from extracted bitumen supernatants and poor solvent recovery from the extraction gangue (Figure 1B).6,8 Solids contamination of bitumen product is a nuisance in both water-based extraction and nonaqueous extraction. During the extraction of bitumen from oil sands, the bulk solids, i.e., coarse sand grains (>44 μm), are considered “inert” as they only inadvertently participate in bitumen separation through physical means, e.g., mechanical entrainment/entrapment.10 These coarse solids do not cause problems in either water- or solvent-based extraction processes.11,12 The fine solids, however, have a significant detrimental effect.2,10 Received: March 19, 2019 Revised: May 30, 2019 Published: June 7, 2019 5933
DOI: 10.1021/acs.energyfuels.9b00852 Energy Fuels 2019, 33, 5933−5943
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Figure 1. Simplified flow diagram for oil sands processing using (A) water-based extraction method4,5 and (B) nonaqueous extraction method.6
In oil sands context, fine solids are defined as mineral particles with diameters less than 44 μm. The major components of these fine solids are found to be clay minerals.2,13 These clay minerals are often associated with a significant amount of irreversibly adsorbed bitumen-derived organic matter, which is not extractable with common organic solvents (such as toluene).10,14 The intimate association of bitumen components with clay particles is one of the fundamental features of oil sands fine solids.2,4,13 The coating of bitumen components dramatically changes the properties of clay minerals, both physically and chemically, leading to significantly different clay behaviors.10,15 For instance, although most clay minerals are naturally water-wet (i.e., hydrophilic), their surface wettability is often altered to be bi-wet or even oil-wet (i.e., hydrophobic) by the adsorption of hydrocarbons such as asphaltenes, resins, or humic materials.10,16,17 This alteration of their surface properties can significantly affect the particle separation behavior, since the wettability of the fine particles determines their partition to the organic phase, aqueous phase, or at the organic/aqueous interface.5,18,19 Therefore, caution needs to be taken when applying the general knowledge of standard clay minerals to the oil sands-derived clay minerals, due to the bitumen coating in the latter case.2,10,15 The bitumen-coated clay particles can adversely affect the entire chain of oil sands bitumen production. In water-based
extraction, these clay particles can hinder bitumen aeration, stabilize water-in-bitumen emulsions, cause a foaming problem in the tailings solvent recovery unit,20 result in fouling of upgrading/refining equipment, and contribute to the formation of indefinitely stable mature fine tailings suspensions.4 In nonaqueous extraction, these clay particles have a detrimental effect on both fine solids removal from bitumen product and solvent recovery from extraction gangue.6 These issues will be discussed in detail in section 4.3. Due to the detrimental role of clay particles in oil sands processing, their content in an oil sands ore is typically considered to be a good predictor for ore processability using the water-based extraction process.2,10 Many studies have been conducted to understand the properties and structures of oil sands clay minerals, using samples from both water-based extraction14,21,22 and nonaqueous extraction.7,8,23 The present work presents an attempt of a critical review on this topic to arrive at a common understanding of clay behavior between aqueous and nonaqueous extraction. Here we use the term “bitumen coating” to refer to the irreversibly adsorbed bitumen-derived organic matter on oil sands clay minerals which survived after solvent (e.g., toluene) washing. The fundamental understanding of this bitumen coating and its impact on clay behaviors are summarized. The remaining challenges and future opportunities regarding oil sands clay minerals are also discussed. 5934
DOI: 10.1021/acs.energyfuels.9b00852 Energy Fuels 2019, 33, 5933−5943
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Figure 2. Schematic representations of (A) clay mineral showing a stack of clay platelets with face and edge surfaces and (B, C) crystalline structures of 1:1-type kaolinite, 2:1-type illite, and 2:1-type montmorillonite.4,29
2. CLAY MINERALS The mineralogy of Alberta oil sands is very complex, evidenced by a large number of mineral species identified (over 90), formation of polymorphs of some minerals (e.g., anatase, rutile, and brookite are all polymorphs of TiO2 but with significantly different crystalline structures), and the presence of ill-defined or poorly characterized minerals.2,4,24 Nevertheless, the primary constituent mineral in the Alberta oil sands is quartz (∼90 wt %), with small amounts of feldspar, clay, and other minerals.25 The quartz and feldspar grains are relatively easy to separate from bitumen due to their large size (usually >250 μm); however, the clay minerals are among the most common minerals migrating into the bitumen product and are therefore selectively enriched in the bitumen product and consequently very problematic.2,4 Clay minerals are aluminum phyllosilicates with a platy shape, having both face (basal plane) and edge surfaces (Figure 2A).26 Most studies reported and confirmed that kaolinite and illite are the dominant clay minerals in the Alberta oil sands.7,27 Some swelling clay minerals (such as montmorillonite, kaolinite-smectite and illite-smectite), although present in small amounts mostly in the 1.5 w/w)
• high contaminants (1−2 wt % water, 0.5 wt % solids)
cons
• high quality of bitumen product
• low solvent/bitumen ratio (0.6−0.75 w/w)
• high yield (no asphaltene precipitation)
pros
Abbreviations: NFT, naphthenic froth treatment; PFT, paraffinic froth treatment; IL, ionic liquid; EO−PO, ethylene oxide−propylene oxide copolymer; EC, ethyl cellulose; M-EC, magnetic-particlemodified ethyl cellulose; CNRL, Canadian Natural Resources Limited.
a
bitumen supernatants from nonaqueous extraction
bitumen froth from water-based extraction
product
Table 1. Removal of Fine Solids from Bitumen Products:a Main Methods and Their Characteristics3,6
Energy & Fuels Review
DOI: 10.1021/acs.energyfuels.9b00852 Energy Fuels 2019, 33, 5933−5943
Review
Energy & Fuels dynamics),15 the changes in clay surface properties caused by the bitumen coating are largely responsible for their problematic behaviors during oil sands processing.21,51 In the following, the problems caused by these bitumen-coated clay particles are discussed separately in terms of extraction methods. 4.3.1. Water-Based Bitumen Extraction. In the water-based extraction process, bitumen aeration, where bitumen droplets attach to air bubbles to achieve effective flotation, essentially determines the recovery of bitumen.5,41 The bitumen-coated clay particles can adsorb on the surface of a bitumen droplet (the so-called slime coating phenomenon2,67), form an “armour” on the bitumen surface, and thus lower the probability for air-bitumen attachment due to the clay’s biwet properties. This would hinder bitumen aeration and consequently reduce bitumen recovery.5 If the armored bitumen droplet does get recovered into the bitumen froth, the extracted bitumen product would have a lower grade due to the adsorbed fine clay particles.2 The formation of stable water-in-bitumen emulsions poses another challenge in oil sands processing.4 The emulsified water may result in corrosion problems for pipelines and downstream upgrading operations because of its dissolved salts content.13,21 While asphaltenes have been identified as an emulsifying agent in bitumen emulsions,68,69 the bitumencoated clay particles are also able to stabilize the emulsions due to their bi-wet characteristics, analogous to Janus particles.27,66 These clay particles can firmly adsorb at the oil/water interfaces, forming the so-called Pickering emulsion and making the separation of water and solids from bitumen exceedingly difficult. Chen et al.21 investigated the influence of hydrophobicity distribution of particle mixtures (i.e., fine clay particles isolated from bitumen froth) on emulsion stabilization. They found that the emulsification behavior of the particle mixtures was dominated by a specific subfraction of particles with intermediate hydrophobicity (showing a critical surface tension of 27−30 mN/m). The hydrophobicity of clay particles was largely controlled by the degree of bitumen coating on clay surfaces. Unwanted foaming has been observed during recovery of solvent from bitumen froth treatment tailings.20 Different from ordinary foams encountered in other industries, which are usually generated by the dispersion of air bubbles in liquid, the foams generated in oil sands bitumen froth treatment are dispersions of light hydrocarbon vapor in liquid. Xu et al.20 identified that the cause of foam formation is the presence of bitumen-coated fine solids, other than the surfactants present in the tailings water. In addition, the presence of these clay particles may exacerbate the fouling problems in downstream units, such as upgrading and refining.13 In oil sands tailings management, the bitumen-coated clay particles are largely responsible for the formation of a stable gel-like structure, leading to poor dewatering and consolidation of oil sands mature fine tailings.70 This was typically considered as the main reason why oil sands tailings are more difficult to dewater than most hard rock mine tailings. In this context, the bitumen coated-clay particles possibly play contradicting roles in oil sands tailings dewatering. Formation of the gel-like structure mentioned above makes dewatering difficult. On the other hand, the bitumen coating on the clay surfaces renders them partially hydrophobic, which intuitively should make dewatering of the oil sands tailings easier, as has been shown by Huang et al.70 in a filtration process.
4.3.2. Nonaqueous Bitumen Extraction. Contamination of extracted bitumen product by fine clay solids and solvent recovery from extraction gangue are two fundamental issues associated with nonaqueous extraction.6 Clay minerals with a bitumen coating play a detrimental role and are the causes for both issues. Nikakhtari et al.8 reported that the migration of clay minerals into solvent-extracted bitumen was significantly affected by the organic surface deposits (bitumen coating) on the clay particles. The more carbon-rich (thus more hydrophobic) clays were easier to be carried into the bitumen product. Similarly, Hooshiar et al.7 observed an enrichment of bitumen-coated clay particles in the solvent-extracted bitumen supernatants with kaolinite and illite being the dominant clay species. The results suggest that the bitumen coating plays a crucial role in the concentration of clay particles in the solvent/ bitumen phase. These clay contaminants are pernicious to the quality of bitumen product and must be removed before further processing.6 In fact, the fine solid content in the product bitumen should preferably be lowered to less than 0.03 wt % (300 ppmw) in order to use the bitumen directly as high conversion refinery feedstock, eliminating the need for an upgrader which is costly to build and run and causes significant environmental issues due to high energy consumption and GHG emissions. Osacky et al.58 examined the performance of four different types of Alberta oil sands (four petrologic “end members”, i.e., marine clay, marine sands, estuarine clay, and estuarine sands) in nonaqueous bitumen extraction. They found that the recovery of bitumen decreased with increasing weight percentage of clay minerals in the samples, likely because the clay-rich oil sands had a relatively small size of bitumen-filled pores, leading to poor accessibility by the solvent. The relatively low extractability from clay-rich oil sands suggests a relatively high content of residual bitumen in the extraction gangue, which is supported by the observations of Osacky et al.,58 who reported that the clay minerals retained 20−58% of the solvent-unextractable bitumen materials in the tested oil sands ore samples. The presence of viscous residual bitumen significantly slows down the removal of solvent from the gangue due to the reduced capillary transport in the porous gangue, as revealed by Panda et al.71 On the other hand, the bitumen coating on clay particles can promote solvent sorption on clays, which is also undesirable for solvent recovery. Tan et al.72 observed that organic-rich solid substrates gave a higher cyclohexane uptake than a clean solid substrate due to the partitioning of cyclohexane into the organic coatings. Hence, one can see that the bitumen-coated clay particles can contribute to the poor solvent recovery from nonaqueous extraction gangue by the retention of both bitumen and solvent.
5. SOLIDS REMOVAL Considerable effort has been devoted to developing methods to remove the problematic clay minerals from bitumen products.3,6 Table 1 summarizes the main methods of fine solids removal from bitumen froth (generated in water-based extraction, Figure 1A) and bitumen supernatants (generated in nonaqueous extraction, Figure 1B). Currently, two technologies are employed commercially for bitumen froth cleaning in the Alberta oil sands industry: naphthenic froth treatment (NFT) and paraffinic froth treatment (PFT). As presented in Table 1, each technology 5939
DOI: 10.1021/acs.energyfuels.9b00852 Energy Fuels 2019, 33, 5933−5943
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converted to a per unit surface area basis, whether the swelling clays still adsorbed more bitumen. This would help answer one of the fundamental questions whether there is any specificity of different clay surfaces in bitumen adsorption. The QNM-AFM used by Chen et al.14 and Liu et al.60 was able to visualize the coated organic materials on the platy clay particles; however, the mineral or chemical nature of the underlying clay is unknown. The integration of atomic force microscopy (AFM) with an X-ray diffraction (XRD) or X-ray fluorescence (XRF) analyzer, although challenging, would be promising for in situ identification of both the inorganic mineral substrate and the organic bitumen coating. Such AFMXRD or AFM-XRF integration could significantly expand the application of AFM in material analysis. In addition, where experimental techniques are found out-of-depth, molecular dynamic simulation can be used to understand the bitumen− clay interactions.75 The faces and edges, and further, the tetrahedral siloxane faces and the octahedral aluminum faces, of clay platelets may behave differently toward bitumen adsorption.4 Interestingly, Couillard and Mercier23 observed that organic carbon appeared to accumulate preferentially at the clay edges, as marked by the dashed box in Figure 5B. Unfortunately, quantitative comparison is lacking and the observed evidence of carbon coating on edges is elusive. AFM adhesion mapping can be a useful technique in probing these differences;14 however, precise control of the particle orientation for AFM measurements would be a great challenge. Because platy clay particles preferentially orientate on the substrate with their basal faces nearly parallel to the substrate surface, their edges are typically inaccessible to the AFM tip for probing.4 Xu and co-workers46,48 used an ultramicrotome cutting technique to prepare the clay edges and differentiated the anisotropic basal faces of clay minerals by depositing clay particles on substrates bearing different charges. Their studies were conducted under aqueous solutions and mainly focused on the surface charge properties of clay minerals. Their approach may be useful in the study of the organic adsorption on the different clay surfaces (i.e., siloxane basal faces, aluminum basal faces, and edges) under nonaqueous conditions. 6.2. Combination of Partial Upgrading and Bitumen Cleaning. Development of partial upgrading processes to improve the fluidity of bitumen and heavy oil for pipeline transportation has gained increasing attention recently.76,77 A combination of partial upgrading and bitumen cleaning would be attractive.4 For instance, direct low- and intermediatetemperature thermal treatment of bitumen froth, instead of froth treatment, followed by partial upgrading, could provide several benefits: (1) the number of process steps is reduced; (2) the contained emulsified water can be easily removed as steam; (3) the filterability of the contained solids can be improved, enabling solids removal by in situ hot filtration without any solvent addition;73 (4) the viscosity of bitumen can be reduced, thereby reducing the requirement of diluent for transportation. However, a concern with this protocol is that water removal by thermal evaporation will leave chloride salt in the bitumen, which may cause equipment corrosion problems. A desalter is likely still required either prior to or after the combined partial upgrading and bitumen cleaning (preferably prior to because of the need to add water in the desalter). Future work regarding this concept is suggested to verify and evaluate the proposed process.
has its advantages and disadvantages. More details on froth treatment technologies are available in a review by Rao and Liu.3 Considering the facts that NFT cannot provide bitumen product meeting pipeline or market specifications, and that PFT results in a significant reduction in bitumen recovery,3 alternative methods for bitumen froth cleaning are desirable if they can effectively remove the fine solids and reduce hydrocarbon loss at the same time. Chen et al.73 proposed a method in cleaning the bitumen froth by a combination of hydrothermal treatment (∼390 °C) and in situ hot filtration (∼200 °C) without any solvent addition. This appears to be a viable method: in their laboratory-scale tests, the solids content was reduced to below 0.1 wt %, and no significant loss of hydrocarbon was observed. Cleaning of bitumen supernatants generated in nonaqueous extraction is a nontrivial task, because direct use of traditional separation methods including centrifugation, filtration, and gravitational sedimentation is ineffective or impractical.6,7 The suspended fine particles in solvent/bitumen solution, typically in the colloidal size range, are extremely stable due to strong solvent/bitumen-fines attractions, “neutral buoyancy”, or “Brownian motion”.6,74 Many efforts have been made to separate these problematic fine solids particles from bitumen, by aggregation, agglomeration, or destabilization, as summarized in Table 1. The basic remedy is to turn the colloidal particles into larger entities, which would enable the particles to settle more easily in conventional solid−liquid separation processes. A detailed description of these methods is out of the scope of the present paper; the interested reader is referred to a recent review on nonaqueous bitumen extraction.6
6. CHALLENGES AND OPPORTUNITIES 6.1. More Accurate Determination of Bitumen Distribution on Clay Minerals. As described in section 4.2, direct visualization of the bitumen coating on clay surfaces is possible by using several novel approaches (e.g., QNMAFM, TIRF, and EELS). However, more details of this bitumen coating on clay minerals are needed:4 For example, which type of clay is more likely to adsorb bitumen? Do different bitumen components preferentially adsorb on clays? Is the adsorption mainly on the basal surfaces or edge surfaces? On tetrahedral siloxane faces or octahedral aluminum faces of clay minerals (see Figure 2)? Or did intercalation of bitumen occur into the interlayer space, as claimed by Geramian et al.?28 Different types of clay are present in the oil sands fine solids, primarily kaolinite and illite but also the swelling clays such as kaolinite-smectite and illite-smectite, although the swelling clays are present in much smaller concentrations.2 How the nonswelling clays (kaolinite, illite) and the swelling clays (kaolinite-smectite, illite-smectite) affect oil sands operations is still unclear. The swelling clays typically exist in the
