Alkaline Waterflooding Of Saskatchewan Heavy Oil Reservoirs- Part I: Screening Of Caustic Reagents
Authors: Chlwetelu C.I. , Neale G.H. , Hornof V. , George A.E. 
Published: March 2010

Abstract
Saskatchewan's proven reserve of heavy oil is estimated at 4 billion m3. About 20% of this reserve is recoverable by enhanced recovery processes. Thermal processes such as steam flooding and in situ combustion are the techniques most frequently used for these relatively cold reservoirs that contain very viscous oils. Since most of the oil occurs in rather thin formations, severe heat losses to adjacent rock strata would invariably reduce the effectiveness of thermal processes. On the other hand, chemical processes such as alkaline waterflooding have proved quite successful in laboratory tests. A properly formulated alkaline flood is expected to be more efficient and cost effective. A variant of the conventional alkaline flood is being proposed for these reservoirs, particularly for those that contain crudes with API gravities above 15. In this modified scheme, a hot alkaline formulation is used to reduce the oil viscosity. At the same time, the viscosity of the alkaline solution is considerably increased by the addition of thickening agents.
In this paper we present a methodology which can be used to screen several alkaline reagents to determine the type and concentration appropriate for a target reservoir. Dynamic interfacial tension data and comparative oil recovery data from linear displacement tests are discussed.

Introduction
The so-called heavy oil belt of Saskatchewan covers a wide area that stretches from Lloydminster in the north to Kindersley in the south. The estimated ultimate oil in place amounts to 4 billion m3. In a recent appraisal of this huge reserve, Reid[l] suggested that 20% of the oil in place could be recovered by using enhanced oil recovery (EOR) techniques. To date, only thermal processes which include in-situ combustion and steamflooding/stimulation are being applied to these reservoirs. However, since the density of the crude ranges from 11 to 20 °API and since the average temperature of these reservoirs is about 20 °C, the viscosity of the crude at reservoir conditions will be 1000 mPa.s or higher. Another significant characteristic of these deposits is the occurrence of the oil in zones of relatively thin sands. According to Selby et a1[2], the thinness of the formations coupled with the large depths and low permeabilities makes thermal processes unsuitable for about 50% of the heavy oil deposits of Canada, the U.S. and Venezuela.
Among the various non-thermal processes, alkaline flooding appears to be the most attractive. Alkaline reagents are abundant and quite cheap compared with conventional surfactants. Their effectiveness for the recovery of acidic crudes has in fact been known since 1927 by virtue of the work of Nutting[3] and Atkinson [4] . It is now generally accepted[5-8] that alkaline reagents react with surface active materials present in the crude resulting in the in situ formation of surfactant soap species. The adsorption of these in situ generated surfactants at the oil/water/sand interface may result in a drastic reduction of the interfacial tension and/or a change in matrix wettability. The end result is the mobilization of residual oil trapped in the fine pores of the reservoir sand.