Harvey W. Yarranton

Asphaltene self-association and water-in-hydrocarbon emulsions

The configuration of asphaltenes on the water-oil interface was evaluated from a combination of molar mass, interfacial tension, drop size distribution, and gravimetric measurements of model emulsions consisting of asphaltenes, toluene, heptane, and water. Molar mass measurements were required because asphaltenes self-associate and the level of self-association varies with asphaltene concentration, the resin content, solvent type, and temperature. Plots of interfacial tension versus the log of asphaltene molar concentration were employed to determine the average interfacial area of asphaltene molecules on the interface. The moles of asphaltenes per area of emulsion interface were determined from the molar mass data as well as drop size distributions and gravimetric measurements of the model emulsions. The results indicate that asphaltenes form monolayers on the interface even at concentrations as high as 40 kg/m(3). As well, large aggregates with molar masses exceeding approximately 10,000 g/mol did not appear to adsorb at the interface. The area occupied by the asphaltenes on the interface was constant indicating that self-associated asphaltenes simply extend further into the continuous phase than nonassociated asphaltenes. The thickness of the monolayer ranged from 2 to 9 nm.

Phase Behaviour and Physical Property Measurements for VAPEX Solvents: Part I. Propane and Athabasca Bitumen

The saturation pressure and solubility of propane in Athabasca bitumen, as well as the liquid phase densities and viscosities, were measured for temperatures from 10 to 50°C. Equilibration proved challenging for this fluid mixture and required some experimental modifications that are discussed. Only liquid and liquid-vapour phase regions were observed at propane contents below 20 wt%. A second liquid phase appeared to have formed at higher propane contents. The saturation pressures, where only a single dense phase formed, ranged from 600 to 1,600 kPa and these were fitted with a modification to Raoults law. Viscosities less than 210 mPa.s were obtained at a propane content of 15.6 wt%. All of the viscosity data of the liquid phase were predicted from the propane and bitumen viscosities using the Lobe mixing rule.

Effect of surfactants on interfacial films and stability of water-in-oil emulsions stabilized by asphaltenes

The effect of additives on asphaltene interfacial films and emulsion stability was analyzed through the change in film properties. Surface pressure isotherms were measured at 23°C for model interfaces between aqueous surfactant solutions and asphaltenes dissolved in toluene and heptane-toluene mixtures. Compressibility, crumpling film ratio and surface pressure were determined from the surface pressure isotherms. The stability of water-in-oil emulsions was determined for the same systems based on the proportion of unresolved emulsified water after repeated treatment involving heating at 60°C and centrifugation. Experimental variables included concentration of asphaltenes (5 and 10 kg/m(3)), concentration and type of surfactant (Aerosol OT, nonylphenol ethoxylates, polypropylene oxide block-copolymer, dodecylbenzene sulfonic acids, dodecylbenzene sulfonic acid-polymer blend, diisopropyl naphthalene sulfonic acid, and sodium naphthenate) and aging time (from 10 min to 4 h). Additives were found to have two opposing effects on film properties and emulsion stability: (1) decreasing or eliminating the crumpling ratio which destabilized emulsions and (2) decreasing interfacial tension which enhanced emulsion stability. A stability parameter was defined to include both the crumpling ratio and interfacial tension and provided a consistent correlation for the percent residual emulsified water.

Phase Behaviour and Physical Property Measurements for VAPEX Solvents: Part II. Propane, Carbon Dioxide and Athabasca Bitumen

The solubility of pure carbon dioxide in Athabasca bitumen was measured and compared with the literature data. Multiple liquid phases were observed at carbon dioxide contents above approximately 12 wt%. A correlation based on Henrys law was found to fit the saturation pressures at carbon dioxide contents below 12 wt%. The saturation pressure and solubility of carbon dioxide and propane in Athabasca bitumen, as well as the liquid phase densities and viscosities, were measured for three ternary mixtures at temperatures from 10 to 25°C. Two liquid phases (carbon dioxide-rich and bitumen-rich) were observed at 13 wt% carbon dioxide and 19 wt% propane. Only liquid and vapour-liquid regions were observed for the other two mixtures (13.5 wt% propane and 11.0 wt% carbon dioxide; 24.0 wt% propane and 6.2 wt% carbon dioxide). The saturation pressures for the latter mixtures were predicted using the correlation for the carbon dioxide partial pressure and a previously developed correlation for the propane partial pressure. The mixture viscosities were predicted with the Lobe mixing rule.

Asphaltene Self‐Association

Recent characterizations of asphaltene structures suggest that asphaltene monomers may consist of several small polynuclear aromatic clusters linked by alkyl chains and containing a variety of heteroatoms. This structure lends itself to the view that asphaltenes self‐associate in a manner analogous to oligimerization rather than simple stacking. If asphaltenes are assumed to be oligimers, some of the interesting features of asphaltene behavior can be explained in a self‐consistent approach, including: measured changes of asphaltene molar mass in different solvents and at different temperatures; the precipitation of asphaltenes from alkane‐diluted heavy oils; and the interfacial behavior of asphaltenes. Recent work in these areas indicates that asphaltene monomers are in the order of 1000 to 2000 g/mol and that self‐associated asphaltenes consist of two to six monomers per aggregate on average. #This paper was originally prepared for the cancelled Petroleum Science and Technology Encyclopedia.

Characterization and Interfacial Behavior of Oil Sands Solids Implicated in Emulsion Stability

Abstract Model water‐in‐hydrocarbon emulsions were used to assess the configuration of oil sands solids in the interfacial region. The model emulsions consisted of toluene, heptane, and water as well as asphaltenes and solids separated from Athabasca bitumen. A combination of emulsion gravimetric measurements, water drop size measurements, and geometrical considerations was employed to determine the fractional area of the interface occupied by solids and asphaltenes. The probable size and shape of the solid particles adsorbed on the interface was also determined with the assistance of SEM and TEM images and further solids characterizations were made with XRD and particle size distributions. The solids that adsorb at the oil–water interface appear to be clay platelets varying from less than 100 nm up to 500 nm in lateral extent. The fractional interfacial area occupied by the solids increases monotonically with increasing concentration of solids in the bulk solution. At the maximum solids concentration considered, 2.8 and 1.9 kg/m3 asphaltenes, 50% of the interfacial area was occupied by solids. The solids appear to adsorb on the interface as individual particles lying flat on the interface. The average thickness of the solids layer is 8 nm. It is speculated that solids adsorbed at the interface prevent bridging between adjacent water droplets, while particles trapped in the continuous phase increase emulsion stability by preventing close contact amongst water droplets.

Estimation of SARA Fraction Properties With the SRK EOS

One approach to modelling asphaltene solubility is regular solution theory. The key parameters for this approach are the molar volume and solubility parameters of each constituent. However, these parameters are largely unknown for crude oils. Some authors have used cubic equations of state (CEOS) to estimate the solubility parameters and molar volumes of solvents and C 7 + fractions, but CEOS have yet to be applied in this way to asphaltenes due to their high molar mass and unknown critical properties. In this work, a modified Soave-Redlich-Kwong EOS with the Peneloux correction is used to estimate the molar volumes and solubility parameter of the four solubility classes (saturates, aromatics, resins, and asphaltenes) of bitumens. The EOS is modified for the asphaltenes, which are assumed to be polymeric-like compounds consisting of aggregates of monodisperse asphaltene monomers. Correlations are developed for the critical properties and acentric factor of each solubility class. The EOS-predicted properties are tested against density measurements of SARA fractions from several bitumens. The predicted parameters are used to determine the onset of asphaltene precipitation from bitumen upon the addition of heptane and the predictions are compared with measured onsets.

Temperature Effects From the Conditioning and Flotation of Bitumen From Oil Sands in Terms of Oil Recovery and Physical Properties

Batch extraction tests show that, for Athabasca oil sands, the water-based conditioning/flotation process can be adjusted from 80 to 50 °C conditions without substantial changes in optimal process aid addition level or primary oil recovery obtained. When the process temperature is further reduced to 25 °C however, an order of magnitude reduction in primary oil recovery is obtained, suggesting that one or more key process variables have undergone a substantial change. Our studies with process additives suggest that several key physical properties undergo major changes, including bitumen viscosity, interfacial tension, and interfacial charge. If these are addressed then comparable optimum primary oil recoveries can be achieved under all of 25, 50, or 80 °C conditions. This is a significant result in terms of identifying the key mechanism(s) by which good primary froth recovery can be achieved. It is shown that the interfacial property changes in particular are consistent with the expected thermodynamic conditions necessary for efficient bitumen separation and flotation.

Spectrophotometric Measurement of Asphaltene Concentration

Abstract Typically, when ultraviolet and visible absorbance of asphaltenes is employed to measure asphaltene concentration, linear calibrations of absorbance vs. asphaltene concentration are prepared from a sample of asphaltenes in a given solvent. This calibration is shown to be sensitive to: (a) the inorganic solids content of the asphaltenes; (b) physical–chemical differences between asphaltenes from different sources or extracted with different methods; and (c) selective adsorption of asphaltenes on liquid–liquid or solid–liquid interfaces. Calibration constants were determined at wavelengths of 288 and 800 nm for samples of Athabasca and Cold Lake asphaltenes obtained using different extraction methods, from precipitation experiments, and from adsorption experiments on water-in-hydrocarbon emulsions and on powdered metals. It was found that the inorganic solids content did not affect absorbance but the asphaltene concentrations must be corrected to a solids-free basis for accurate results. Calibration constants were found to correlate to the average associated molar masses of the asphaltenes. Therefore, any change in molar mass of asphaltenes during the course of an experiment may change the calibration constant. Partial precipitation and the selective adsorption of asphaltenes can lead to a change in the molar mass of asphaltenes left in solution. The corresponding change in the calibration constants can lead to errors of 5–25% in the estimated concentration.

The Effect of Oil Sands Bitumen Extraction Conditions on Froth Treatment Performance

The Canadian oil industry is producing about 1 million barrels of bitumen and synthetic crude oil per day from oil sands and the production is expected to rise to 2 million barrels per day by 2012(1). Currently, both in situ and surface mining operations contribute almost equally to the total production. However, the production of synthetic crude from surface-mined oil sands is expected to take the lead in the next decade(2). Expansions of existing oil sand facilities are already underway and the addition of new facilities are planned within the next decade. There are two main stages to oil sand processing: extraction and froth treatment. The most common extraction process is hot water bitumen extraction. The oil sand is conditioned with hot water, either in a process vessel (conditioning drum) usually with NaOH added, or more recently in a pipeline (hydrotransport) usually with a smaller amount of NaOH added. During conditioning, the slurry is aerated and, ideally, the bitumen separates from the sand, and attaches to and spreads on the air bubbles. Water is added to the slurry, which is subsequently sent to a separation vessel. The bitumen-coated air bubbles are carried upwards to form a froth that is rich in bitumen. The froth also contains free water, emulsified water, and suspended solids(3, 4). The froth is collected in two stages yielding a primary and a secondary froth. For high-quality oil sands, a typical primary froth composition is approximately 66 Abstract