Significance of Foamy-oil Behaviour In Primary Production of Heavy Oils

Abstract

Abstract This paper examines the effects of in situ formation of a non-aqueous foam on flow of oil-gas mixtures in porous media. A laboratory technique to investigate the role of foamy-oil behaviour in solution gas drive is described and experimental verification of the in situ formation of non-aqueous foams under solution gas drive condition is presented. The experimental results show that the in situ formation of non-aqueous foam retards the formation of a continuous gas phase and dramatically increases the apparent trapped gas saturation. This provides the natural pressure maintenance mechanism and leads to recovery of a much higher fraction of the Original oil in place under solution gas drive. Introduction Several heavy-oil reservoirs in Alberta and Saskatchewan, show "foamy-oil" behaviour in wellhead samples produced under solution gas drive. The oil is produced in the form of an oil-continuous foam which has the appearance of chocolate mousse and contains a high volume fraction of gas. This foam can be quite stale and may persist for several hours in open-vessels. The field production data from these reservoirs suggests that the production mechanisms are complex and may be quite different from those encountered in conventional solutions-gas driven reservoirs. Several of these reservoirs show anomalously high production. Both the rate of production and the total recovery under solution Gas drive are much higher than what would be expected from measured oil parameters. History matching primary production For these wells often requires unrealistic adjustment of measured parameters, such as increasing the absolute permeability by an order of magnitude. In a recent publication, Longhead and Satroklaroglu(1) have described the unusual primary production behaviour of Celtic Field reporting that the rate of production in some wells is more than ten times the calculated pseudo-steady state oil flow rate under radial flow conditions. To obtain a satisfactory history match of the primary production behaviour, they had to assume very unusual reservoir properties. These included not only an artificially high absolute permeability but also a trapped gas saturation of 35% and an unusual oil relative permeability curve. These high productivity wells produce from unconsolidated sands, and a large volume of sand is produced with the oil. Generally any attempt to stop sand production results in drastically reduced production. Another part of this puzzle is that several of these wells, which are prolific in primary production, show very poor response to steam stimulation. Several possible causes of this anomalous production behaviour have been suggested and are being investigated. These include formation of worm holes around the well which increase the effective well radius(2). Sand dilation due to removal of substantial volumes of sand with the oil, resulting in increased absolute permeability appears to be another mechanism(1). The enhancement of oil mobility by nucleation of a large number of microbubbles has been suggested as another possibility(3, 4). Another possible cause of the anomalous behaviour is the in situ formation of an oil-continuous foam. It is likely that several of these mechanisms might be involved in varying degrees in different reservoirs.