Improved Bitumen Recovery Using Urea Solutions

Abstract

This work presents experimental and simulation studies to design and optimize urea solutions to improve bitumen recovery. Initially, the solubility of ammonia in Athabasca bitumen was measured at vapor-liquid equilibrium (VLE) condition at different temperatures and pressures ranging from 348 to 463 K (75 to 190 ℃) and 1 to 4 MPa, respectively. The liquid phase density of ammonia-saturated bitumen was measured. The experimental solubility and density data were modeled using the Peng-Robinson equation of state (PR-EoS) by tuning the binary interaction coefficient and volume shift parameters of ammonia, respectively. The modeling results revealed that PR-EoS gives an acceptable prediction of ammonia solubility in bitumen and density of ammonia saturated-bitumen. Additionally, 1-D sand pack flooding experiments were conducted to recover heated bitumen at 423 K and 3.447 MPa pore pressure by injecting two different concentrations of urea solutions (5 and 10 wt %) at 1 cm3/min injection rate. Another flooding experiment was conducted by flooding sand pack with fresh water at the same flooding condition to be used as a baseline of urea solution flooding experiments. Supplementary experiments such as interfacial tension (IFT) measurements, emulsion viscosity measurements, total acid number (TAN) measurements, and Fourier-transform infrared (FTIR) measurements were conducted to prove the generation of in situ surfactants through the flooding process. The results of these flooding experiments (at 423 K) showed that flooding with urea solutions improves the oil recovery efficiency, highlighting the synergy between the reduction in viscosity of bitumen and the generation of in situ surfactants. Besides the reduction in viscosity of bitumen resulting from the heat, the generated in situ surfactants emulsify the oleic phase leading to the generation of W/O emulsion at the displacement front. This emulsion makes the displacement front more stable due to the attenuation of the viscous fingering. The supplementary experiments confirmed the generation of in situ surfactants, as evidenced by the reduction in the interfacial tension and total acid number measurements, and confirmed the results with FTIR analysis. Along with flooding experiments, a fine grid numerical simulation was conducted to model the experimental oil recovery data to obtain relative permeability curves through history matching technique. The history matching results revealed the efficiency of urea solutions to change the rock wettability toward more water-wet and suppress viscous fingering phenomenon. After confirming the mechanism of urea solutions in recovering bitumen, several 1-D sand pack flooding experiments were conducted by injecting hot urea solutions into cold sand packs at room temperature to optimize the injection rate, injection temperature, and urea solution concentration. Three injection rates (4, 8, and 12 cm3/min), four injection temperatures (453, 473, 493, and 513 K), and three urea solution concentrations (5, 10, and 15 wt %) were investigated in these flooding experiments. The flooding experiments of cold sand packs revealed an optimum flow rate that leads to more efficient displacement of oil by urea solutions. The optimum flow rate is attributed to the balance between the retention time and heat delivered to the oil sands through the flooding process. The results show higher oil recovery at higher concentrations of urea. Furthermore, the results reveal that while higher injection temperature accelerates the oil recovery initially, it reduces the ultimate oil recovery.