The objective of this study was to identify suitable combinations of additives to aqueous alkaline formulations for the potential recovery of Saskatchewan heavy crude oil. A previously developed strategy was applied to screen various additive combinations consisting of three commercial petroleum sulfonate surfactants and two commercial lignosulfonate surfactants. The selection of the additives was based on a large number of physical and interfacial property measurements in conjunction with phase stability tests at different temperatures. The resulting ternary formulations, labelled here as Mixed‐Surfactant‐Enhanced Alkaline (MSEA) systems, were very successful in reversing the trend of increasing interfacial tension with time that characterizes additive‐free alkaline/crude oil systems. This success came at the expense of initial IFT values that were considerably higher than those exhibited by the corresponding additive‐free alkaline solutions. However, at higher temperatures (65 °C), these ternary MSEA formulations were capable of generating very low IFT values against the crude oil (in the range of 5 × 10−2 to 10−1 mN/m), which suggests that they could be suitable candidates for commercial exploitation of heavy oil recovery processes.

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This paper reviews the potential importance of aqueous lignosulfonate solutions in the recovery of petroleum from existing partially depleted oil fields. The surfactant qualities of lignosulfonates are described and their ability to interact synergistically with petroleum sulfonate surfactants (which are currently popular in the industry) to produce ultra-low interfacial tensions with crude oil is discussed. The phase behaviour characteristics and oil recovery efficacies of these mixed surfactant systems are also examined.

The feasibility of employing various alkaline agents (sodium hydroxide, sodium metasilicate and sodium orthosilicate) to enhance the recovery of a specific Saskatchewan heavy oil from the Kindersley region has been investigated. The dynamic interfacial tension behaviors of solutions of these alkalis in contact with the crude oil were measured for a range of concentrations and temperatures, and the most interfacially active formulations were then tested for their oil recovery efficacies by conducting oil displacement experiments in unconsolidated linear sand packs at 25 °C and 65 °C. The most promising of the three alkalis tested was found to be sodium hydroxide, which was capable of producing very significant enhancements in oil recovery relative to that obtained with pure waterflooding. 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 some 4 × 109 m3. In a recent appraisal of this huge reserve, Reid(1) suggested that 20% of the oil in place could be recovered by using enhanced oil recovery techniques. To date, only thermal processes such as 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 of the order of 1000 mPa.s or higher. Another significant characteristic of these deposits is the occurrence of the oil in relatively thin zones. According to Selby et al.(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. Amongst 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 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 generated surfactants at the oil/water/sand interfaces often results in a drastic reduction of the interfacial tension and/or in a change in matrix wettability. The end result is the mobilization of residual oil trapped in the fine pores of the reservoir sand. Selby et al.(2) listed 15 recent field alkaline flood tests in Canada and the U.S. However, only one of those tests was considered successful, while the majority were abandoned. One reason for this dismal performance is the inadequate understanding of the complex interactions that occur between alkaline reagents, crude oil, formation water and matrix minerals. Even basic oil-water interfacial tension (IFT) behavior becomes very complex when dealing with crude oil/caustic systems. Several researchers(9,10) have reported variations in IFT of one or more orders of magnitude when crude oil was contacted with caustic solutions for contact times ranging between 10 and 60 minutes.

This paper describes the mechanisms and a quantative analysis of the interaction between a multicomponent acid mixture with a spectrum of caustic solutions. A physico-chemical model of the acidic oil /caustic system has been proposed which demonstrates the effect on dynamic interfacial tension (IFT) of variations in caustic concentration as well as changes in the initial composition and ionization properties of the constituent acids of the oleic phase. The model relies on the Langmuirian theory of interfacial sorption kinetics in addition to the Nernstian theory of convective diffusion. Pertinent kinetic and mass transfer parameters for all contributing surface-active species were determined from a recently proposed single-component dynamic model (Chiwetelu et al., 1988a). The validity of this multicomponent dynamic model was confirmed by the close agreement between predicted IFT and experimental data for a binary carboxylic acid system in contact with a broad range of caustic concentrations.