Improved Recovery Potential in Mature Heavy Oil Fields by Alkali-Surfactant Flooding

ABSTRACT

Many reservoirs in Canada are too small or thin for energy-intensive thermal EOR operations. The reservoirs may also be disturbed during primary production, generating low-resistance flow-pathways between injectors and producers, thus injected fluids will follow these pathways and not contact additional oil. In these conditions, alkali-surfactant injection has considerable potential as a technique for additional non-thermal recovery of heavy oil.

During unstable displacement of heavy oil by water, water breakthrough occurs early, and subsequent water injection will channel mostly through the water fingers and bypass significant volumes of continuous oil. It has been shown in other works that alkali and/or surfactant injection can lead to improved heavy oil recovery compared to waterflooding, but researchers have proposed different reasons for this response. This work summarizes the mechanisms that are responsible for improved heavy oil recovery and presents the results of 30 laboratory core floods investigating alkali-surfactant injection into sandpacks containing heavy oil (viscosity 11,500 mPa·s at 23°C).

By injecting less than 1% of alkali-surfactant (AS) solution with water, a combination of oil-in-water (O/W) and water-inoil (W/O) emulsions will form in the water channels, effectively blocking them off. Further injected solution will therefore contact fresh regions of the core. It is shown that this design of AS injection in heavy oil leads to improved sweep efficiency of the flood. This corresponds to lower apparent relative permeability values to the aqueous phase, and a discussion is provided regarding how AS floods can be controlled and optimized.

In any heavy oil reservoir that is considered a viable candidate for waterflooding, AS flooding can also potentially be applied. The significance of this work is that it describes the mechanisms responsible for the improved oil recovery, which allows for optimized design of chemical flooding conditions. This study demonstrates how a small amount of chemical injected along with water can lead to dramatic improvements in the recovery from previously flooded heavy oil fields.

Introduction
With approximately 270 billion m3 of oil in place1, the heavy oil and bitumen in Alberta constitute one of the largest resource bases in the world. The estimated proved reservoirs2 are approximated at around 28 billion m³. This represents an overall recovery factor of around 10%, but with advances in technology and changing economic conditions of high oil prices, this number may increase in future years.

Heavy oil is defined as having viscosity values in the range of 50 – 50,000 mPa·s, and densities similar to that of water. This special class of unconventional oil has some limited mobility under reservoir temperature and pressure. The oil may contain some solution gas, so initial production can be achieved through solution gas drive. The estimated resource base of this more mobile oil is around 5.7 billion m³ in Alberta alone, and accounts for 70% of all the current active development areas in the province1. Other significant heavy oil deposits are also found in Saskatchewan, as well as countries such as Venezuela, China and Albania. Under primary production the recovery of oil is only expected to be around 5%1, thus there is tremendous potential for further recovery of this oil.

A full version of this paper is available on OnePetro Online.