Numerical Modeling of Unstable Waterfloods and Tertiary Polymer Floods for Viscous Oils
- Adam Wilson (JPT Special Publications Editor)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- July 2017
- Document Type
- Journal Paper
- 53 - 55
- 2017. Society of Petroleum Engineers
- 1 in the last 30 days
- 71 since 2007
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This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 182638, “Numerical Modeling of Unstable Waterfloods and Tertiary Polymer Floods For Highly Viscous Oils,” by R. de Loubens, SPE, G. Vaillant, M. Regaieg, J. Yang, A. Moncorgé, SPE, C. Fabbri, and G. Darche, SPE, Total, prepared for the 2017 SPE Reservoir Simulation Conference, Montgomery, Texas, USA, 20–22 February. The paper has not been peer reviewed.
The saturation distribution after unstable waterflooding for highly viscous oil may have a decisive effect on the efficiency of tertiary polymer flooding, in particular because of hysteresis effects associated with oil banking. This paper addresses the challenges in modeling highly unstable waterflooding, using both a conventional Darcy-type simulator and an adaptive dynamic prenetwork model, by comparing the simulated results with experimental data including saturation maps. It also highlights the important role of relative permeability hysteresis in the tertiary recovery of viscous oils by polymer injection.
Waterflooding into viscous oils can lead to severe viscous fingering of the injected water—a well-known type of instability in porous-media flow that is intrinsically related to the viscosity contrast between the displaced fluid (oil) and the displacing fluid (water). A direct consequence of this phenomenon is a significant bypassing of the oil in place and a low recovery factor, as observed at both laboratory scale and field scale. Viscous instabilities between two immiscible fluids are dependent not only on the viscosity ratio but also on the capillary number and rock wettability. In particular, experimental studies have shown that the effect of viscous fingering strongly increases when the displacing fluid gets less wetting than the displaced fluid (i.e., when going from imbibition to drainage). In order to reduce or eliminate hydrodynamic instabilities, polymer flooding can be implemented as a secondary or tertiary recovery mechanism.
This work considers three waterflood and tertiary-polymer-flood experiments conducted on Bentheimer sandstone slabs with heavy oils with viscosity of approximately 2,000 and 7,000 cp, under nonwater-wet conditions. These experiments belong to a series of heavy-oil- displacement experiments whose objective was to investigate the effect on oil recovery of various parameters, such as oil viscosity, slab length, and injection pattern. Besides standard measurements of fluid production and differential pressures, an X-ray scanner was used to visualize the spatial distribution of the fluids as a function of time.
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