Steam flooding in heavy-oil sands has been well characterized over last decades as a mature technology, and while steam has been injected into light-oil, low-permeability sands almost as long, the mechanisms and effectiveness of this process are much less understood because of the complexities of flow in these sands and high pressure steam injection. This paper examines thermal recovery in such reservoir using both physical and numerical simulation and also describes the performance of pilot test in Daqing oil field.

In regard to recovery mechanisms, wettability alteration, interfacial tension and threshold pressure gradient decline contribute to higher oil displacement and swept efficiency. Vaporization, viscosity reduction, thermal expansion and relative permeability variation accounts for over three quarters of incremental recovery in steam flooding. As a consequence of high-pressure steam flooding five fluid banks form: steam bank, distillate bank, hot water bank, condensate bank and cold water bank, in which steam bank is much smaller than high temperature region. Hence, it is substantially different from shallow heavy-oil situation where both of them are almost similar in size.

This paper details a pilot test in a low-permeability reservoir with depth of 800m, an average permeability around 8 md and a typical porosity of 16%, oil viscosity roughly of 40mpa.s. Waterflood began in 1990 and suffered from low injectivity, poor sweep, and injector-to-producer linkage. These factors tended to degrade waterdlood's effectiveness. An attempt of steamlfood has been used to enhance recovery since 2005. The pilot test shows promising results. The response to steam injection is prompt and significant. The injectivity is doubled and productivity is almost tripled. The oil-steam-ratio is around 0.3. The incremental recovery is predicted to be over 10%. And now, field operator is considering expanding the pilot program to a much larger region.

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