Alkali Surfactant Polymer (ASP) flooding has traditionally been considered in tertiary mode, i.e., after a reservoir has been sufficiently water flooded. In screening studies experiments are usually conducted under two-phase flow conditions, i.e., in the absence of a gas phase in the rock.
In practice, oil reservoirs might contain some gas. In areas in the world, where gas flaring is not allowed and an infrastructure for gas transportation is not present, re-injection of produced gas is a common practice. Moreover, when the reservoir is depressurized below bubble point a gas phase will be created.
To the best of our knowledge, there are no data in the literature concerning the influence of in-situ gas phase (continuous or trapped) on the performance of ASP floods. The main objective of this paper is to evaluate how the presence of a free (non-dissolved) gas phase affects ASP flood performance. To this end, several experiments were carried out to evaluate different conditions, where free gas was present, either flowing or trapped.
We found that the ultimate residual oil saturation in most experiments is similar to the case without gas. When free gas is present in the porous medium, the oil-bank production occurs earlier, because a large fraction of the gas remains trapped and therefore the "effective?? pore volume for liquid flow is reduced. When the gas and the ASP solution are co-injected, the oil is mostly produced in emulsion form as gas enhances mixing of the in-situ fluids. Trapped gas could lead to an efficient oil recovery, depending on the amount of trapped gas: the lower the trapped gas saturation the better the oil recovery.
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