Role of Asphaltenes in Foamy Oil Flow

Abstract

Abstract It has been suggested in several studies that there may be a link between the presence of high asphaltenes content and the foam-ability of oil. However, a systematic examination of the impact of asphaltenes on the performance of solution gas drive, in connection with foamy oil flow, has not been reported. This paper presents an experimental study that addresses this issue. The objective of this work was to examine whether or not the presence of asphaltenes has a strong influence on the performance of foamy solution gas drive. To this end, parallel solution gas drive experiments were conducted using a heavy crude oil from the Lloydminster area and a deasphalted version of the same oil. To eliminate the influence of oil viscosity, the viscosity of the crude oil was reduced to the same level as that of the deasphalted oil by diluting it with a 50–50 mixture of heptanes and toluene. The experiments were carried out in a visual sandpack that permits observation of bubble formation in the sand. The results show that the presence of asphaltenes significantly promotes foamy oil flow. Introduction Noticeable progress in understanding the high efficiency of solution gas drive in heavy oil reservoirs has been made in recent years. However, basic mechanisms and reservoir engineering parameters are still being evaluated(1). Some authors attribute the high efficiency of solution gas drive in heavy oil reservoirs to foam, and the term foamy oil is used to describe the process. The question of how the foam forms and how it helps in improving the production performance remains to be fully answered. In order to explain this high primary production, two main mechanisms have been proposed(1, 2). The first is the increase of the drainage radius of the well by the formation of high permeability channels, called wormholes(3). The second mechanism is the low gas mobility in heavy oil leading to gas retention that helps in maintaining high pressures in the reservoirs. Low gas mobility is explained by the high oil viscosity and its foamy nature. Smith(4) was the first to propose a model in which the gas flow was in the form of micro bubbles dispersed in the oil phase. Subsequently, Maini et al.(5) experimentally observed this dispersed gas phase and called it Foamy Oil. This leads to the discussion of how the foam is formed and its nature, stability and movement in the formation rock. Although the foamy oil flow occurs in all viscous oil systems, irrespective of whether or not the oil contains asphaltenes, it has been suggested that asphaltenes enhance foaminess. Claridge and Prats(6) proposed that bubble stability is related to the asphaltenes adsorption at the gas-oil interface, which protects bubbles against coalescence. However, experimental results on the effect of asphaltenes are conflicting. In micromodel experiments, Bora et al.(7) observed that asphaltenes lower coalescence rates. Tang and Firoozabadi(8) did not observe any differences in comparing crude oil and silicon oil with similar viscosity. Other authors have suggested that foaming and surface properties of crude oils change with the asphaltenes concentration(9–12).