Mechanisms of Heavy Oil Recovery by Low Rate Waterflooding

Mai, A. and Kantzas, A.

DOI: 10.2118/134247-PA
CIPC 2008-156; SPE 134247; CIM 2008-156 presented at the 59th Annual Technical Meeting of the Petroleum Society held in Calgary, June 17-19, 2008;
Journal of Canadian Petroleum Technology, 49(03), March 2010, Pages 44-50


At the conclusion of primary heavy oil production, significant volumes of oil still remain in the reservoir under depleted reservoir pressure. Waterfloods are often considered for additional oil recovery. It is accepted that conventional oil waterflooding theory is not applicable for heavy oil. However, there is a lack of understanding of how waterfloods should perform in these reservoirs, particularly after water breakthrough. In this study, waterfloods were performed at multiple rates in cores containing heavy oil and connate water. In some cores, oil was initially free of solution gas, and waterfloods were a primary recovery process. In other cores, waterfloods were performed after primary production. Experiments were performed in linear systems for a high-viscosity oil (11,500 mPa·s at 23°C), at different injection rates. The influence of viscous and capillary forces is studied in primary vs. secondary recovery systems. A common misconception is that capillary forces are negligible in heavy oil; however, this work shows that these forces are significant, and that water imbibition after water breakthrough can lead to improved oil recovery in both primary and secondary waterfloods.


The Canadian deposits of heavy oil and bitumen are some of the largest in the world. Recent estimates by the Alberta Energy and Utilities Board(1) suggest that this resource could exceed 270 billion m³ in Alberta alone, with a significant portion of this oil located in reservoirs where energy-intensive thermal operations will not be economic. Heavy oil is a special class of this unconventional oil, which has viscosity ranging from 50 – 50,000 mPa·s (cp) and low API gravity. Heavy oil reservoirs are often high-porosity, high-permeability, unconsolidated sand deposits. Permeability of the sand averages in the range of 3D, but oil does not flow easily because of its high viscosity(2). The oil may contain dissolved solution gas at initial conditions; thus, a fraction of the oil can be recovered through solution gas drive. Primary production can recover around 5% of the oil in place(1), leaving significant oil volumes in the reservoir for potential secondary recovery.

Waterflooding is a common technique for secondary oil recovery in conventional oil reservoirs. In heavy oil systems, the extremely high oil viscosities lead to adverse mobility ratio conditions; thus, water will tend to “finger?? through the oil, and recoveries are expected to be extremely low(3,4). Despite the poor recoveries predicted theoretically, there have been numerous reports of heavy oil waterfloods performed in the literature(5-8). All of these studies report poor sweep efficiencies and low overall recovery. However, it is significant that in all cases some oil was still recovered, despite the highly adverse mobility ratios in the waterfloods.

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