Bitumen froth generated from water-based extraction of Alberta oil sands typically consists of 60 wt % bitumen, 30 wt % water, and 10 wt % mineral solids. The froth has to be cleaned by removing the mineral solids and water before it can be upgraded or sold directly to the market. Currently, naphthenic or paraffinic froth treatment processes (NFT or PFT) are used to lower the viscosity of the bitumen froth to facilitate the removal of water and mineral solids. PFT generates a much cleaner bitumen product than NFT through asphaltene precipitation. To induce asphaltene precipitation, the required amount of paraffinic solvent is much higher than that of the naphtha solvent in the NFT process. This increases process complexity and costs in the subsequent solvent recovery process. In this study, the injection of carbon dioxide (CO2) was investigated to assist the PFT process to lower the solvent dosage. It was found that the injection of CO2 to dry bitumen–heptane mixtures helped promote asphaltene precipitation when the solvent-to-bitumen ratio was above the onset of asphaltene precipitation. Under moderate CO2 pressure (1.7 MPa) and temperature (21–90 °C), the heptane dosage could be reduced by 54.9% while maintaining the same degree of asphaltene precipitation from the dry bitumen. When the solvent-to-bitumen ratio was below the onset, injection of CO2 under the tested temperature and pressure did not cause asphaltene precipitation.

Gas-based enhanced oil recovery (EOR) processes rely on the injection of gases, such as carbon dioxide, nitrogen, and natural gas, into heavy oil reservoirs to reduce native oil viscosity. Although these processes are very promising, they face the problem of limited and costly gas supply. This paper investigates the conditions, specifically of temperature variation, under which freely available air at low temperatures and low pressures and in a non-reactive environment may be used for EOR. To that end, experiments are carried out by injecting air into a lab-scale heavy oil reservoir at different pressures (0.169, 0.286, 0.403, and 0.514 MPa absolute) and temperatures in the range of 25−90 °C. Reservoirs of four different permeabilities (40, 87, 204, and 427 darcy) are used in experiments, which demonstrate heavy oil recovery of up to 58.2% original oil in place (OOIP) with constant temperature air injection. When air is injected with a periodic temperature variation between 75 and 90 °C that has an average of 78 °C, the recovery is found to increase to 69.1% OOIP. This is an improvement of 18.6% over that using constant temperature air injection at the maximum temperature of 90 °C.

In this study, the effect of carbon dioxide in assisting paraffinic bitumen froth treatment was investigated. The work was divided into two parts, the effect of water addition on CO 2 -assisted asphaltene precipitation from a dry and clean bitumen sample by n -heptane and the effect of CO 2 injection to a mixture of n -heptane and a commercial bitumen froth sample. It was found that water addition to the dry and clean bitumen improved the beneficial effect of CO 2 on promoting asphaltene precipitation by n -heptane, where asphaltene precipitation increased by 2.5 percentage points (or 19%) with the presence of water and CO 2 . The asphaltene precipitation enhancement may be due to chemical reactions between injected CO 2 and water in the formation of carbonic acid in the aqueous phase, which destabilized asphaltene. On the other hand, no improvement was detected under the control tests (N 2 ). Similar results were observed in the case of CO 2 injection to paraffinic solvent ( n -heptane) treatment of the commercial bitumen froth sample. The results indicated that when the commercial bitumen froth sample was mixed with n -heptane at a solvent/bitumen ratio of 1.08, the injection of 1.7 MPa CO 2 increased the amount of precipitated asphaltene from 10.0 ± 0.1% (without CO 2 ) to 15.2 ± 0.2% (with 1.7 MPa CO 2 ) at 90 °C, indicating a potential reduction of solvent usage by about 66%.

Research Article Recovery of Zn(II) and Ni(II) Binary from Wastewater Using Integrated Biosorption and ElectrodepositionThe present study aimed to obtain best operational conditions for biosorption of Zn(II) and Ni(II) binary metal solution in a fixed bed packed with wheat straw as biosorbent. The effects of bed depths, liquid flow rates and mixture metal concentrations on biosorption service time were investigated. The results showed that breakthrough service time of the biosorption columns (C b ¼ 2 mg/L Zn and Ni) increased with increasing bed depth, while decreased with increasing influent concentrations and flow rates, as expected. This paper further extended the study to investigate the competition of Zn(II) and Ni(II) binary in solution by performing biosorption tests at varied ratio of the metal concentrations. For biomass regeneration, the effect of desorbing agents (hydrochloric acid, nitric acid and sulphuric acid), their concentrations (0.1-0.5 mol/L) and flow rates (0.05-0.1 L/min) on recovery of Zn(II) and Ni(II) binary mixture was investigated. The best performance in desorption of Zn(II) and Ni(II) binary solutions were 0.1 mol/L H 2 SO 4 and a 0.05 L/min inlet flow rate. Moreover, after five sorption/desorption cycles, the biosorbent still maintained its high adsorption capability. Electrodeposition was also used to recover metal ions from concentrated Zn (II) and Ni(II) binary solutions (about 340 mg/L) from the desorption step. It was found that the electrodeposition could reduce the metal concentrations down to wastewater discharge limit of 2 mg/L Zn and Ni ions.

Gas-based enhanced oil recovery (EOR) processes rely on the injection of gases such as carbon dioxide, nitrogen, and natural gas into heavy oil reservoirs to reduce inherent oil viscosity. Although these processes are very promising, they face the problem of limited and costly gas supply. This study investigates the conditions, specifically temperature variation, under which freely available air at low temperatures, low pressures, and non-reactive environments for heavy oil recovery. To that end, preliminary experiments are carried out to demonstrate the possibility of beneficial effects of air temperature variation with time. Furthermore, this research aims to utilize the theory of optimal control to determine optimal air temperature versus time function to maximize the heavy oil recovery. For this purpose, the conditions necessary for optimal control are derived and utilized in a computational algorithm. The preliminary experiments are executed by injecting air into a lab-scale heavy oil reservoir at different pressures (0.169-0.514 MPa absolute) and temperatures in the range of 25-90oC. Reservoirs of four different permeabilities (40-427 Darcy) are used in experiments. When air is injected with a periodic temperature variation between 90oC and 75oC that has an average of 78oC, the recovery is increased from 58.2% to 69.1% of the original-oil-in-place (OOIP) in comparison to that using constant temperature air injection at the maximum temperature of 90oC. That is a considerable improvement of oil recovery by 18.6%. Furthermore, utilizing optimal control the optimal interfacial temperature versus time (control policy) is determined between 90oC and 82oC, which registers 20.66% increase in the oil recovery in comparison to that at the constant temperature of 90oC. The accuracy of optimal control is experimentally validated. The results show that the average relative difference between the predicted heavy oil recovery and the experimental value is a low value of 1.82%.