Which One Is More Important in Chemical Flooding for Enhanced Court Heavy Oil Recovery, Lowering Interfacial Tension or Reducing Water Mobility?

Abstract

A total of 33 sandpack flood tests were carried out to investigate the effects of interfacial tension (IFT) and water-phase viscosity on enhanced heavy oil recovery by chemical flooding. The amount of oil recovered by alkaline-only flooding increased sharply with the NaOH concentration in the range of 0.3-0.5 wt %. The oil recovery only varied slightly with the changing alkaline concentration outside the range. The coexistence of the surfactant and NaOH reduced the IFT between the oil and aqueous phase to an ultralow level. However, the amount of oil recovered by alkaline/surfactant flooding only increased slightly with an increasing NaOH concentration up to a threshold value of 0.5 wt %. Beyond this threshold value, the recovery efficiency stopped increasing with the alkaline concentration and its value was lower than that of the alkaline-only displacing process. The addition of a polymer improved the tertiary oil recovery by increasing the viscosity of the water phase, although it also increased the IFT slightly. The combination of alkaline with polymer was more effective than polymer only upon enhancing the tertiary oil recovery. Comparing the results of tertiary oil recovery shows that the tertiary oil recovery of Court oil is correlated better with water-phase viscosity than IFT; i.e., increasing the viscosity of the water phase is more effective than lowering IFT in improving the tertiary oil recovery.

Stability Proxies for Water-in-Oil Emulsions and Implications in Aqueous-based Enhanced Oil Recovery

“…Recovery in chemical flooding of heavy-oil reservoirs have been shown to depend on flow rate, and consequently on the shear rate [5][6][7][8][9][10]. This is consistent with capillary number dependencies associated with emulsion flow [11].…”

“…The issue of mobility ratio or control arises because viscous water has much lower viscosity than heavy oil and consequently the displacement front develops fingers and oil recovery is generally poor. Alkali-surfactant (AS) flooding has been shown to be a potential viable technology for EOR in heavy-oil reservoirs [5][6][7][8][9][10]. However, in the absence of a thickening agent such as polymers, the increase in water saturation as water displaces oil only worsens the mobility control issue.…”

“…They determined that pH affected emulsion stability in a significant way. These authors attribute this result to increased charge densities at high pH (10)(11)(12) by polarization of the polar groups, consequently destroying mechanical properties of the interfacial film. Lower pH results (neutral to acidic) hints on the effect of acidic components of the oils.…”

Assessment of Polyacrylamide Based Co-Polymers Enhanced by Functional Group Modifications with Regards to Salinity and Hardness

“…A common problem in this process is the unstable displacement because the viscosity of injected water is often much lower than the reservoir oil, which causes water to overrun. Addition of polymer to the injected water, called polymer flooding, can successfully alleviate this problem by increasing the viscosity of displacing water, which results in a more favorable oil displacement [1][2][3][4]. This viscosity enhancement makes the front more stable, thus enabling it to push the oil towards production well in a piston-like manner [5].…”

A new method for evaluating the injection effect of chemical flooding

“…Chemical flooding, a rapidly developed tertiary oil recovery technique, is applied successfully and widely both in the Daqing Oilfield and the Shengli Oilfield (Zhang et al 2010;Hou et al 2011Hou et al , 2013Shaker Shiran and Skauge 2013;Dag and Ingun 2014). Polymer flooding and surfactant-polymer flooding (SP flooding) are considered two of the most mature chemical methods (Chang et al 2006;Vargo et al 2000;Li et al 2012;Delamaide et al 2014;Sheng et al 2015).…”