The spinning drop method was used to measure the interfacial tension of Athabasca bitumen in contact with an aqueous phase (D2O); variables included temperature, salinity, alkalinity, surfactant type (TRS 10–80, Suntech 5, sodium dodecyl sulfate), surfactant concentration, isopropyl alcohol concentration, bitumen drop size and age of interface. In the absence of surfactant, the bitumen/aqueous interfacial tension decreased with increasing temperature and salinity. Bitumen drops contacting alkaline medium exhibited interfacial tension minima below a pOH of three. In the presence of surfactant, the interfacial tension behavior was often complex. The interfacial tension‐concentration plot for Suntech 5 surfactant exhibited two CMC type discontinuities. Low interfacial tension (<0.01 mN m−1) was observed only in the presence of added electrolyte. Interfacial tension values were sensitive to the age of surfactant preparation and volume ratio of the oleic‐to‐aqueous phases. The interfacial tension of the bitumen/brine‐TRS 10–80 system increased upon addition of isopropyl alcohol. An increase in temperature required an increase in salinity to maintain a constant low interfacial tension. The experimental results are discussed in terms of changes in the structure of the amphiphile at the bitumen/aqueous interface.

This paper describes a laboratory study of the factors controlling the formation and breakdown of foams in porous media at elevated temperatures. The degradation of a foam when gas injection was discontinued involved the gradual transformation of a foam with a noncondensable gas phase (gas foam) to a foam with steam as the gas phase (steam foam). The ability to prevent release of the noncondensable gas phase was strongly influenced by surfactant type and concentration. The formation of steam foams in the absence of noncondensable gas was a critical function of steam velocity and permeability. Surfactant concentration and chain length, salinity, and the presence of oil were important variables in determining mobility reduction of steam. Increased oil recovery from cores undergoing steam displacement was obtained when surfactant slugs were injected with and without noncondensable gas. The presence of a noncondensable gas led to the formation of a more effective and durable foam.

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The experimental results reported in this paper are part of a study designed to examine the benefits of using surface-active chemicals with steam-basedprocessesfor obtaining additional bitumen recovery from the oil sands. Results are included, mainly from the following three stages of the work.-1) the effect of temperature and concentration on the stability of a commercial petroleum sulfonate surfactant, 2) displacement experiments conducted in laboratory cells (0. 16 kg and 1. 6 kg oil sand capacity) at 100 OC,, 3) simulation runs carried out on the 45-cm Alberta Research Council Test Bed (75 kg oil sand capacity) at saturated steam conditions of 3.5 MPa and 250'C Measurements of bitumenlaqueous interfacial tensions and E.E. Isaacs Eddy Isaacs is an associate research officer and group leader, has been employed in engineering research and development of pilot-plant and industrial-scale process systems. His current responsibilities include experimental design, assessment and numerical modelling of in-situ recovery processes. _ Technology, May-June 1982, Montreal surfactant retention in porous media are also briefly described.Based on this work, it appears that surfactants have con-siderable potential, a two-to three-fold increase in bitumen recovery was often realized when compared to baseline ex-Periments in the absence of surfactant. Introduction Bitumen contained in oil sands has virtually no mobility at reser-voir temperatures and pressures. The primary means to reduce the viscosity and improve mobility is to provide thermal energy; bitumen undergoes a very steep reduction in viscosity with in-creasing temperature. In-situ recovery methods using steam in-jection, either in cyclic or drive processes, have been widely used(l). However, they are often inefficient and leave behind substantial amounts of oil. The use of volatile additives, such as solvents(2, 3), gases(4, 5) and combinations of gases and solvents(5), in conjunction with steam to increase bitumen recovery has been promoted. At present, the commercial feasibility of these pro-cesses cannot be estimated with certainty. Alkali additives with steam were applied in both laboratory(6) and field(7) tests with ht-tle success. The use of surfactant additives in combination with steam has also been suggested (8,9). A recent laboratory study of a surfactant-steam flood using 300API crude at 1800C showed J. P. Ranlkin Joseph P. Rankin is currently a pro-cess engineer at Nova Scotia Forest In-dustries. Previously, he was employed as a process engineer at the Oil Sands Research Department of the Alberta Research Council, where he was in-volved in the evaluation of data from oil sand simulation tests. He holds a B.Eng. (chemical) from McGill and a M.A.Sc. (chemical) from the University of NN'aterloo.