Dynamic displacement experiments, simulating temperature and pressure conditions of an oil-bearing formation during primary production stage, were carried out to investigate the processes of asphaltene-induced precipitation and deposition during pressure depletion on a core sample and their effects on the absolute permeability. A representative monophasic-bottom-hole fluid sample and one core of consolidated Bedford limestone were used in coreflood tests. To identify the pressure and temperature conditions at which the asphaltene will begin to precipitate, as well as the bubble-point pressures of the reservoir fluid sample, the light-scattering technique solid detection system (SDS) using a variable volume, visual P V T cell was used. The coreflood test results indicated that the in situ asphaltene precipitation and deposition on porous medium damage absolute permeability and reduce effective porosity as reservoir fluid pressure is reduced until a point near bubble-point pressure. Core impairment, resulting from asphaltene deposition, was found to cause a 24% and 20% loss of initial oil permeability and effective porosity, respectively. A mathematical model, based on the transport of stable particulate suspensions in porous media, for asphaltene deposition was developed and validated directly with experimental results obtained in this investigation, as well as those found in the literature. On the basis of the developed mathematical model, two distinct mechanisms were identified as a consequence of the deposition process, namely, asphaltene adsorption and trapping. The porous medium was represented as a network of sites and bonds, with pore bodies identified as sites and pore throats as bonds. A satisfactory qualitative agreement was observed with the experimental results.

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As an alternative to solvent addition to the steam-assisted gravity drainage process for bitumen recovery, coinjection of biodiesel with steam as a surfactant additive to reduce bitumen–water interfacial tension was considered. The density and viscosity of bitumen and bitumen–pentane mixtures up to 15 % pentane concentrations by mass were measured at a 1 MPa pressure and up to 448 K temperature. The interfacial tension between bitumen, bitumen–pentane mixtures up to 15 % pentane concentrations, bitumen–biodiesel mixtures up to 0.3 % and water, and process water was also measured at a 1 MPa pressure and up to 423 K temperature. Laboratory tests showed that the density of bitumen–pentane mixtures decreased linearly with an increase in pentane content, and their viscosity decreased exponentially with the increase in temperature. A decrease in bitumen viscosity with an increase in pentane content was dramatic at low temperatures and became less sensitive at temperatures above 373 K. Interfacial tension measurements suggest that asphaltic acids naturally occurring in bitumen act as surfactants. The decay in interfacial tension with time is attributed to the diffusion of surfactant species in a bitumen droplet. The increase in interfacial tension of bitumen–pentane mixtures and water with an increase in pentane content and temperature needs further attention because of its commercial application.

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Short-hydrophobe surfactants based on cosolvent species have been studied as novel surfactants for enhanced oil recovery. The objective of this research is to investigate such simple surfactants as a sole additive that enhances the efficiency of oil displacement by creating low-tension polymer (LTP) fronts. This paper presents the potential enhancement of oil displacement efficiency by LTP flooding based on comprehensive experimental data, such as interfacial tensions (IFTs), surfactant partition coefficients, surfactant adsorption in a sandpack, polymer/LTP rheology, and sandpack flooding results. The optimal LTP identified was composed of 0.5 wt % 2-ethylhexanol-7PO-15EO in partially hydrolyzed polyacrylamide polymer solution, which reduced the IFT with heavy oil from 15.8 to 0.025 dyn/cm, without creating microemulsions. The surfactant adsorption in the sandpack was only 0.055 mg-surfactant/g-sand. Sandpack flooding results show that the LTP flooding achieved an incremental oil recovery in comparison to straight-polymer flooding. The oil recovery at 1 pore-volume injected (PVI) was 47% original-oil-in-place (OOIP) for the polymer flooding, 63% for the smaller LTP slugs (0.5 wt % surfactant for 0.1 PVI and 0.1 wt % surfactant for 0.5 PVI), and 70% for the larger LTP slug (0.5 wt % surfactant for 0.5 PVI). Fractional flow theory was applied to confirm that the IFT reduction by 3 orders of magnitude was conducive to a lowered residual oil saturation in LTP flooding, leading to a delayed polymer breakthrough and an increased oil cut thereafter in comparison to polymer flooding.