CO2‐Switchable Oil/Water Emulsion for Pipeline Transport of Heavy Oil

By mixing an aqueous solution of tertiary amine, N,N‐dimethylethanolamine (DMEA), with naphthenic acid (RCOOH) derived from heavy oil, a CO₂ switchable zwitterionic surfactant (RCOO^?DMEAH⁺) aqueous system was constructed. The CO₂ switchability of this zwitterionic surfactant was confirmed by visual inspection, pH measurements, and conductivity tests, i.e., the RCOO^?DMEAH⁺ decomposed into RCOOH, DMEAH⁺ and HCO₃^? after bubbling CO₂ through but switched back to its original state by subsequent bubbling N₂ through at 80 °C to remove the CO₂. The interfacial tension tests of heavy oil in DMEA aqueous solutions indicated that the solution containing 0.5 wt% of DMEA and 0.2 wt% of NaCl resulted in the lowest interfacial tension. The O/W emulsion formed when aqueous solutions of DMEA were used to emulsify heavy oil exhibited the best performance when the oil/water volume ratio, DMEA concentration, and NaCl concentration were 65:35, 0.5 and 0.2 wt%, respectively. The feasibility of pipeline transport of the O/W heavy oil emulsion was evaluated. The results illustrated that the demulsification of the O/W emulsion after transport could be easily realized by bubbling CO₂ through. Although demulsification efficiency still needs to be improved, the recycling of the aqueous phase after demulsification by removal of CO₂ looks promising.     

Precipitation of asphaltenes from solvent-diluted heavy oil and thermodynamic properties of solvent-diluted heavy oil solutions

Ratios of n-heptane (hep) to toluene (tol) affect the solubility of the asphaltenes in heavy oil extraction processes. Consequently phase changes and time after mixing n-heptane and heavy oil in toluene are important for understanding produced emulsions. The kinetics of phase change when n-heptane is added to toluene-diluted heavy oils, and the thermodynamic properties of partially deasphalted heavy oils were studied. The methods used were monitoring precipitation in time using light microscopy, quantitative asphaltenes analysis by near infrared spectroscopy, refractive index and densities measurements, and calculated solubility parameters of mixtures. At critical mass ratios of hep/tol from 1.37 to 2.0 in diluted heavy oil the precipitated asphaltene particles were observed under the microscope after lag times from 2 h to instantly. Lag times were longer at low initial oil concentration. The floc growth time decreased as heavy oil concentration in toluene increased. The growth patterns in time appeared as dots to beads (strings) to clusters (fractal-like flocs). Final wt% precipitated asphaltenes vs. mass fraction (hep+tol)/heavy oil followed sigmoidal relationships. Curves showing wt% soluble asphaltenes vs. mass fraction hep/tol after 24 h initially followed the same shape as time zero curves and diverged at the onset ratios of hep/tol. Slope for precipitated asphaltenes vs. solubility parameters curve showed a break at 16.4 MPa^1/2. Linear correlations were established for concentrations of soluble asphaltenes in residual oils and density, for refractive index and density and for refractive index and solubility parameter. The latter correlation was in accordance with Lorenz-Lorentz theory. These equations provided a means by which oil density, refractive index and solubility parameter can be predicted when these measurements are difficult to measure practically.     

Novel alkyl methylnaphthalene sulfonate surfactants: A good candidate for enhanced oil recovery

The surface tensions of various surfactant aqueous solution and the dynamic interfacial tensions between the Shengli oil field of China crude oil and the solution of novel surfactants, a series of single-component alkylmethylnaphthalene sulfonates (AMNS) including various the length of alkyl chains (hexyl, octyl, decyl, dodecyl and tetradecyl, developed in our laboratory), were measured. It is found that synthesized surfactants exhibited great capability and efficiency of lowering the solution surface tension. The critical micelle concentrations, CMC were: 6.1–0.018×10⁻³ mol L⁻¹, and the surface tensions at CMC, γ_CMC were: 28.27–35.06 mN m⁻¹. It is also found that the added surfactants are greatly effective in reducing the interfacial tensions and can reduce the tensions of oil–water interface to ultra-low, even 10⁻⁶ mN m⁻¹ at very low surfactant concentration without alkali. The addition of salt, sodium chloride, results in more effectiveness of surfactant in reducing interfacial tension and shows that there exist obviously both synergism and antagonism between the surfactant and inorganic salt. All of the synthesized surfactants, except for hexyl methylnaphthalene sulfonate, can reduce the interfacial tension to ultra-low at an optimum surfactant concentration and salinity. Especially Tetradec-MNS surfactant is most efficient on lowering interfacial tension between oil and water without alkaline and the other additives at a 0.002 mass% of very low surfactant concentration. Both chromatogram separation of flooding and breakage of stratum are avoided effectively, in addition to the less expensive cost for enhanced oil recovery, and therefore it is a good candidate for enhanced oil recovery.     

Salt-Induced Constructions of Gemini-like Surfactants at the Interface and Their Effects on the Interfacial Tension of a Water/Model Oil System

It is an urgent issue to enhance oil recovery for unconventional reservoirs with high salinity. Focused on this topic, salt addition is a powerful tool to motivate the surfactant assembly at the water/oil interface and improve the interfacial activity. We used a cationic surfactant cetyltrimethylammonium bromide (CTAB) and an anionic salt dicarboxylic acid sodium (CnDNa) to construct gemini-like surfactants at the interface and evaluated their ability to reduce the interfacial tension (IFT) between model oil (toluene and n-decane, v:v = 1:1) and water. Interestingly, the fabrication of a (CTAB)₂/C4DNa gemini-like surfactant was hardly achieved at the fresh water/model oil interface, but accomplished at the brine/model oil interface. At a high NaCl concentration (100,000 mg L⁻¹), the IFT value is reduced to 10⁻³ mN m⁻¹ order of magnitude, which is generally desired in practical applications. The control experiments displacing the surfactant type and the spacer length further confirmed the NaCl effects on the interfacial assembly.     

Evaluation of aqueous chemical systems for heavy oil recovery processes

The effects of temperature and certain chemical additives on the interfacial tension behaviour of a heavy oil (from Lloydminster, Alberta) with petroleum sulphonate surfactant solutions and alkaline solutions are investigated experimentally. Corresponding data for a light Canadian oil are included for comparison purposes. It is concluded that alkaline solutions are effective only in the recovery of heavy oils, while petroleum sulphonate surfactants are effective only for light oils. The effect of temperature on the minimum attainable interfacial tension is marginal in all cases. However, for alkaline solutions, temperature has a significant effect on the rate of rise of interfacial tension with time after attainment of the minimum value.     

Application of HIGEE process intensification technology in synthesis of petroleum sulfonate surfactant

Petroleum sulfonate (PS) surfactant used for enhanced oil recovery was synthesized by dilute liquid sulfur trioxide and petroleum fraction (PF) of Shengli crude oil as raw materials with the application of HIGEE process intensification technology. The effects of various experimental conditions on the content of active matter and unsulfonated oil were investigated. The optimum conditions were selected as solvent/oil mass ratio 0.5, SO₃/oil mass ratio 0.525, reaction temperature 30 °C, rotating speed 1200 rpm, circulation ratio 4, reaction time 15 min and aging time 50 min under which the active matter content was up to 45.3 wt.% and the oil/water interfacial tension was as low as 4.5 × 10⁻³ mN/m. The higher product quality and higher process efficiency of this new technology is proven by a comparison with traditional STR process.     

Superior enhancement of imbibition recovery by novel surfactant mixtures with a large hydrophobic group combined with nanosilica

Low interfacial tension (IFT) drainage and imbibition are effective methods for improving oil recovery from reservoirs that have low levels of oil or are tight (i.e., exhibit low oil permeability). It is critical to prepare a high efficient imbibition formula. In this work, a novel 2,4,6-tris(1-phenylethyl)phenoxy polyoxyethylene ether hydroxypropyl sodium sulfonate (TPHS) surfactant was synthesized and evaluated for imbibition. Its structure was confirmed by Fourier transform infrared spectroscopy and the interfacial tension (IFT) of the crude oil/0.07% TPHS solution was 0.276 mN/m. When 0.1 wt% TPHS was mixed with 0.2 wt% alpha olefin sulfonate (AOS), the IFT was lowered to 6 × 10⁻² mN/m. The synergy between nanoparticles (NPs) and TPHS/AOS mixed surfactant was studied by IFT, contact angle on sandstone substrates, zeta potential, and spreading dynamics through microscopic methods. The results show that the surfactant likely adsorbs to the NP surface and that NP addition can help the surfactant desorb crude oil from the glass surface. With the addition of 0.05 wt% SiO₂ NPs (SNPs), the imbibition oil recovery rate increased dramatically from 0.32%/h to 0.87%/h. The spontaneous imbibition recovery increased by 4.47% for original oil in place (OOIP). Compared to flooding by TPHS/AOS surfactant solutions, the oil recovery of forced imbibition in the sand-pack increased by 12.7% OOIP, and the water breakthrough time was delayed by 0.13 pore volumes (PV) when 0.05% SNPs were added. This paper paves the way for enhanced oil recovery in low-permeability sandstone reservoirs using novel TPHS/AOS surfactants and SNPs.     

Research on Oleic Acid Amide Betaine Used in Surfactant-Polymer Compound Flooding for Ordinary Heavy Oil

In view of the low recovery rate associated with water flooding, as well as the scaling problems caused by traditional alkali-surfactant-polymer flooding, the feasibility of using a betaine surfactant with high interfacial activity for chemical flooding of ordinary heavy oil was investigated. Aqueous solutions of oleic acid amide betaine (OAAB) with the mass concentration of 0.01% can reduce the oil–water interfacial tension to the ultralow level (10⁻³ mN m⁻¹), making it suitable for chemical flooding. To solve the problem of high adsorption onto sandstone, static adsorption tests and dynamic adsorption tests were carried out. The results show that the weakly alkaline lignin can significantly reduce the adsorption quantity of OAAB by more than 40%, based on which, a compound-flooding system of 0.1% partially hydrolyzed polyacrylamide (HPAM) + 0.1% OAAB +0.75% lignin was constructed. Compared with water flooding, the ultimate rate was enhanced by 20.4%, resulting in a final recovery rate of 53.9%. The study of oil displacement mechanism shows that the excellent ability to reduce the oil–water interfacial tension of OAAB can emulsify heavy oil to small droplets easily, exhibiting better capacity in oil displacement efficiency. The polymer can increase the viscosity of the aqueous phase, reduce the mobility ratio of water to oil, weaken the fingering effect, and improve the sweep efficiency. Lignin can not only reduce the adsorption quantity of betaine surfactant, but also promote the adsorption of OAAB onto the oil–water interface, leading to enhance the emulsification performance of OAAB and maintain the oil displacement efficiency effectively. Therefore, the surfactant-polymer flooding system based on the betaine surfactant can be developed into an economically and technically feasible flooding technology suitable for ordinary heavy oil reservoirs.     

Interfacial tension and the behavior of microemulsions and macroemulsions of water and carbon dioxide with a branched hydrocarbon nonionic surfactant

Measurements of interfacial tensions for 2-ethyl-hexanol-(propylene oxide)∼_4.5-(ethylene oxide)∼₈ (2EH-PO_4.5-EO₈) at the planar water-CO₂ interface and the surfactant distribution coefficient are utilized to explain microemulsion and macroemulsion phase behavior from 24 to 60 °C and 6.9 to 27.6 MPa. A CO₂ captive bubble technique has been developed to measure the interfacial tension γ at a known surfactant concentration in the aqueous phase, with rapid equilibration at the water-CO₂ interface. The surface pressure (γ_o − γ) decreases modestly with density at constant temperature as CO₂ solvates the surfactant tails more effectively, but changes little with temperature at constant density. The area per surfactant at the CO₂-water interface determined from the Gibbs adsorption equation decreases from 250 A²/molecule at 24 °C and 6.9 MPa, to 200 A²/molecule at 27.6 MPa. It was approximately twofold larger than that at the water-air interface, given the much smaller γ_o driving force for surfactant adsorption. For systems with added NaCl, γ decreases with salinity at low CO₂ densities as the surfactant partitions from water towards the W-C interface. At high densities, salt drives the surfactant from the W-C interface to CO₂ and raises γ. Compared with most hydrocarbon surfactants, this dual tail surfactant is unusually CO₂-philic in that it partitions primarily into the CO₂ phase versus the water phase at CO₂ densities above 0.8 g/ml, and produces γ values below 1 mN/m. With this small γ, a middle phase microemulsion and a C/W microemulsion were formed at low temperatures and high CO₂ densities, whereas macroemulsions were formed at other conditions.     

Use of mixed surfactants to improve the transient interfacial tension behaviour of heavy oil/alkaline systems

The objective of this study was to identify suitable combinations of additives to aqueous alkaline formulations for the potential recovery of Saskatchewan heavy crude oil. A previously developed strategy was applied to screen various additive combinations consisting of three commercial petroleum sulfonate surfactants and two commercial lignosulfonate surfactants. The selection of the additives was based on a large number of physical and interfacial property measurements in conjunction with phase stability tests at different temperatures. The resulting ternary formulations, labelled here as Mixed-Surfactant-Enhanced Alkaline (MSEA) systems, were very successful in reversing the trend of increasing interfacial tension with time that characterizes additive-free alkaline/crude oil systems. This success came at the expense of initial IFT values that were considerably higher than those exhibited by the corresponding additive-free alkaline solutions. However, at higher temperatures (65 °C), these ternary MSEA formulations were capable of generating very low IFT values against the crude oil (in the range of 5 × 10^?2 to 10^?1 mN/m), which suggests that they could be suitable candidates for commercial exploitation of heavy oil recovery processes.     

Synthesis of Didodecylmethylcarboxyl Betaine and Its Application in Surfactant–Polymer Flooding

Enhanced crude oil recovery by chemical flooding has been a main measure for postponing the overall decline of crude oil output in China, and surfactant-polymer (SP) flooding may replace alkali-surfactant-polymer flooding in the future for avoiding the undesired effects of using alkali. In this paper the synthesis of a surfactant with a large hydrophobe, didodecylmethylcarboxyl betaine (diC₁₂B), and its adaptability in SP flooding were investigated. The results show that diC₁₂B can be synthesized by reaction of didodecylmethyl amine, a product commercially available, with chloroacetic acid in the presence of NaOH, with a resulting yield as high as 80?wt% under appropriate conditions. With double dodecyl chain diC₁₂B is highly surface active as displayed by its low CMC, 3.7?×?10^?6?mol?L^?1, low ??_CMC, 27?mNm^?1, as well as high adsorption and small cross section area (??0.25?nm²) at both air/water and oil/water interfaces at 25?°C. By mixing with conventional hydrophilic surfactants diC₁₂B can be well dissolved in Daqing connate water and reduce the Daqing crude oil/connate water interfacial tension to about 10^?3?mN?m^?1 at 45?°C in a wide total surfactant concentration range, from 0.01 to 0.5 wt%. And a tertiary oil recovery, 18?±?1.5?% OOIP, can been achieved by SP flooding using natural cores without adding any alkaline agent or neutral electrolyte. DiC₁₂B seems thus to be a good surfactant for enhanced oil recovery by SP flooding.     

Behaviour of heavy metals in the partial oxidation of heavy fuel oil

The behaviour of heavy metals in the partial oxidation of heavy fuel oils under a pressure of up to 100 bar (10 MPa) has been investigated. The tests were carried out in a 5 MW HP POX (High Pressure Partial Oxidation) test plant, that is operated by the IEC (Department of Energy Process Engineering and Chemical Engineering, TU Bergakademie Freiberg) in cooperation with Lurgi GmbH. In several test campaigns preheated oil with a viscosity of up to 300 cSt (= 300 mm²/s) at the burner inlet has been gasified. The heavy metals nickel Ni, iron Fe and vanadium V occur in heavy residual oils in considerable concentration and may seriously impact the gasification itself and the synthesis gas conditioning and usage. While iron is largely recovered in the gasification residue, the recovery rates of nickel and vanadium depend on the process conditions. Volatile nickel compounds were detected in the raw synthesis gas. It was found that an incomplete carbon conversion enables the capture of nickel Ni and vanadium V in the solid residue phase and can thus mitigate the problem of volatile metal compounds in the raw synthesis gas.     

Synthesis of <Emphasis Type="Italic">N</Emphasis>-(3-Oxapropanoxyl)dodecanamide and its Application in Surfactant-Polymer Flooding

Alkali-surfactant-polymer (ASP) flooding has been considered to be one of the useful tertiary oil recovery techniques. However, field tests in China have revealed that serious side effects may occur due to using alkali. Thus alkali-free SP flooding is more favorable in China. Unfortunately, surfactants effective in ASP flooding are usually ineffective in the absence of alkali and new surfactants need to be designed. In this paper N-(3-Oxapropanoxyl)dodecanamide as a pure compound and a mixture of homologues with narrow EO number distribution, synthesized by the reaction of lauroyl chloride with diglycolamine and addition of one ethylene oxide to coconut monoethanolamide respectively, are examined for their adaptability in SP flooding. It is found that, when mixed with betaines, both products can reduce Daqing crude oil/connate water interfacial tension to a magnitude of 10⁻³–10⁻⁴ mNm⁻¹ at 45 °C in a wide surfactant concentration range, 0.01–0.5 wt%, and oil displacement tests using natural cores indicates that a tertiary oil recovery of 18.6 ± 0.4% OOIP can be achieved by SP flooding with the N-(3-Oxapropanoxyl)dodecanamide as the main surfactant without adding any alkaline agent and neutral electrolyte. N-(3-Oxapropanoxyl)dodecanamide, as a nonionic surfactant without a cloud point and producible industrially from renewable materials, is an ideal surfactant for SP flooding in the absence of an alkaline agent.     

How the Influence of Different Salts on Interfacial Properties of Surfactant–Oil–Water Systems at Optimum Formulation Matches the Hofmeister Series Ranking

In this work, we present the effects of salts on sodium dodecyl benzene sulfonate micellization and on the interfacial performance of a sodium dodecyl benzene sulfonate–heptane–brine system at optimum formulation, i.e., hydrophilic–lipophilic deviation (HLD) = 0. In order to do that, interfacial tension and dilational interfacial rheology properties of surfactant–heptane–water systems at optimum formulation are measured using an interfacial spinning drop tensiometer with an oscillating velocity, which can accurately measure interfacial rheology properties at both low and ultralow interfacial tensions. The brines used contain one of the following salts: MgCl₂, CaCl₂, NaCl, NH₄Cl, NaNO₃, CH₃COONa, or Na₂SO₄. We performed a one-dimensional salinity scan with each of these salts to achieve an optimum formulation. In relation to the Hofmeister series, we found that, at optimum formulation, systems with chaotropic ions (NH₄⁺, NO₃⁻) present interfaces with ultralow interfacial tensions, very low dilational modulus, and a low phase angle, whereas kosmotropic ions (Mg²⁺, Ca²⁺, SO₄⁻²) generate high interfacial tension and high rigidity monolayers. Intermediate ions in the Hofmeister series (Na⁺, CH₃COO⁻, Cl⁻) present interfaces with intermediate properties. Furthermore, according to the Hofmeister series, interfaces can be respectively ordered from higher to lower rigidity for surfactant counterions Mg²⁺ > Ca²⁺ > Na⁺ > NH₄⁺ and coions SO₄²⁻ > CH₃COO^– > Cl⁻ > NO₃⁻, which correspond to a salting-out (highest rigidity) and salting-in (lowest rigidity) effect. We observed that counterions have a more significant effect on surfactant–oil–water system properties than those that act as coions.     

Progress in research of sulfobetaine surfactants used in tertiary oil recovery

The synthesis of sulfobetaine surfactants and their application in tertiary oil recovery (TOR) are summarized in this paper. The synthesis of sulfobetaine surfactants was classified into three categories of single hydrophobic chain sulfobetaine surfactants, double hydrophobic chain sulfobetaine surfactants and Gemini sulfobetaine surfactants for review. Their application in TOR was classified into surfactant flooding, microemulsion flooding, surfactant/polymer (SP) flooding and foam flooding for review. The sulfonated betaine surfactants have good temperature resistance and salt tolerance, low critical micelle concentration (cmc) and surface tension corresponding to critical micelle concentration (γ_cmc), good foaming properties and wettability, low absorption, ultralow interfacial tension of oil/water, and excellent compatibility with other surfactants and polymers. Sulfobetaine surfactants with ethoxyl structures, hydroxyl and unsaturated bonds, and Gemini sulfobetaine surfactants will become an important direction for tertiary oil recovery because they have better interfacial activity in high-temperature (≥90°C) and high-salinity (≥10⁴ mg/L) reservoirs. Some problems existing in the synthesis and practical application were also reviewed.     

The effect of mixed surfactants on enhancing oil recovery

Micelles composed of mixed surfactants with different structures (mixed micelles) are of great theoretical and industrial interest. This work pertains tomaximizing interfacial tension (IFT) reduction via surfactant pairs. In this respect, four types of fatty acid amides based on lauric, myristic, palmitic, and stearic acids were blended with dodecyl benzene sulfonic acid at a molar ratio of 4∶1 and designated as A₁, A₂, A₃, and A₄, respectively. The IFT was measured for each blend at different concentrations using Badri crude oil. The most potent formula (A₄) was evaluated for using in enhanced oil recovery (EOR). The IFT was tested in the presence of different electrolyte concentrations with different crude oils at different temperatures. Finally several runs were devoted to study the displacement of Badri crude oil by A₄ surfactant solution using different slug sizes of 10, 20, and 40% of pore volume (PV). The study reveled that Badri crude oil gave ultra-low IFT at lowest surfactant concentration and 0.5% of NaCl. The recovery factor at a slug size of 20% PV was 83% of original oil in place compared with 59% in case of conventional water flood.     

Enhanced oil recovery from high‐salinity reservoirs by cationic gemini surfactants

In order to enhance oil recovery from high‐salinity reservoirs, a series of cationic gemini surfactants with different hydrophobic tails were synthesized. The surfactants were characterized by elemental analysis, infrared spectroscopy, mass spectrometry, and ¹H‐NMR. According to the requirements of surfactants used in enhanced oil recovery technology, physicochemical properties including surface tension, critical micelle concentration (CMC), contact angle, oil/water interfacial tension, and compatibility with formation water were fully studied. All cationic gemini surfactants have significant impact on the wettability of the oil‐wet surface, and the contact angle decreased remarkably from 98° to 33° after adding the gemini surfactant BA‐14. Under the condition of solution salinity of 65,430 mg/L, the cationic gemini surfactant BA‐14 reduces the interfacial tension to 10^?3 mN/m. Other related tests, including salt tolerance, adsorption, and flooding experiments, have been done. The concentration of 0.1% BA‐14 remains transparent with 120 g/L salinity at 50 °C. The adsorption capacity of BA‐14 is 6.3–11.5 mg/g. The gemini surfactant BA‐14 can improve the oil displacement efficiency by 11.09%. © 2017 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2018 , 135, 46086.     

Investigating the effect of nano-silica on efficiency of the foam in enhanced oil recovery

Due to the vast production of crude oil and consequent pressure drops through the reservoirs, secondary and tertiary oil recovery processes are highly necessary to recover the trapped oil. Among the different tertiary oil recovery processes, foam injection is one of the most newly proposed methods. In this regard, in the current investigation, foam solution is prepared using formation brine, C₁₉TAB surfactant and air concomitant with nano-silica (SiO₂) as foam stabilizer and mobility controller. The measurements revealed that using the surfactant-nano SiO₂ foam solution not only leads to formation of stable foam, but also can reduce the interfacial tension mostly considered as an effective parameter for higher oil recovery. Finally, the results demonstrate that there is a good chance of reducing the mobility ratio from 1.12 for formation brine and reservoir oil to 0.845 for foam solution prepared by nanoparticles.     

Comparison of product selectivity during hydroprocessing of bitumen derived gas oil in the presence of NiMo/Al2O3 catalyst containing boron and phosphorus

A detailed experimental study was performed in a trickle-bed reactor using bitumen derived gas oil. The objective of this work was to compare the activity of NiMo/Al₂O₃ catalyst containing boron or phosphorus for the hydrotreating and mild hydrocracking of bitumen derived gas oil. Experiments were performed at the temperature and LHSV of 340-420 °C and 0.5-2 h⁻¹, respectively, using NiMo/Al₂O₃ catalysts containing 1.7 wt% boron or 2.7 wt% phosphorus. In the temperature range of 340-390 °C, higher nitrogen conversion was observed from boron containing catalyst than that from phosphorus containing catalyst whereas in the same temperature range, phosphorus containing catalyst gave higher relative removal of sulfur than boron containing catalyst. Phosphorus containing catalyst showed excellent hydrocracking and mild hydrocracking activities at all operating conditions. Higher naphtha yield and selectivity were obtained using phosphorus containing catalyst at all operating conditions. Maximum gasoline selectivity of ∼45 wt% was obtained at the temperature, pressure, and LHSV of 400 °C, 9.4 MPa and 0.5 h⁻¹, respectively, using catalyst containing 2.7 wt% phosphorus.     

Interfacial tension behavior and ESR properties of asphaltenes derived from heavy oil

Asphaltenes extracted from Lloydminster heavy oil (from Saskatchewan, Canada) were separated by sequential elution solvent chromatography (SESC) using ten different organic solvents. The fractions so obtained were dissolved in toluene and then examined for their interfacial tension (IFT) behavior against 0.1 wt.% sodium hydroxide solution. It was found that only about 40% (by weight) of the original asphaltenes contained species which were capable of lowering IFT against the alkaline solution. Multi-functional phenolic and other polar compounds were considered to be the components most likely responsible for the observed interfacial activity. Electron spin resonance measurements showed that the individual fractions contained varying concentrations of free radicals and VO²⁺ ions. However, no direct correlation between the content of either of these two species and the interfacial tension could be detected.