In situ formation of foamy oils under solution gas drive has been proposed as one of the possible mechanisms responsible for high primary production rate from some heavy oil reservoirs. Maini et al. (1993) reported some results from steady-state tests of two methane-saturated heavy oils flowing through a sand pack. They concluded that there was no evidence of the presence of nucleated gas bubbles enhancing the mobility of the heavy oil; rather the oil mobility being decreased due to gas entrapment.
This paper is the re-interpretation of their test results through matching both the oil production and the pressure distribution data with a foamy oil viscosity model. It is found that entrapment of gas bubbles in oil would reduce the oil mobility; however, the nucleation of gas bubbles at the grain surface would enhance the mobility. The mobility of the heavy oil increases proportionally with the nucleation rate; but decreases with foam quality following Roscoe's viscosity model (1952). A new mobility correlation with the nucleation rate and the foam quality is proposed. With the new correlation, we succeeded in matching both the production rates and the pressure profiles. The mobility enhancement due to the bubble nucleation can be explained by gas lubrication effects.
Anomalously high primary production rates have been experienced by some solution gas drive heavy oil reservoirs in Alberta and Saskatchewan (Smith, 1986; Loughead and Saltuklaroglu, 1992; Yeung and Adamson, 1994; Sametz and Luhowy, 1994). The performances of these reservoirs could not be predicted by a Darcy flow model with measured reservoirs and fluid properties. To match field performance, the mobilities of oil and gas had to be greatly increased and decreased, respectively, and trapped gas saturations as high as 35% needed (Smith, 1986; Loughead and Saltuklaroglu, 1992). Based on the numerical simulations of single-phase radial flow to a well, the primary production rate behaviour resembles a dilatant non-Newtonian fluid flow (Poon and Kisman, 1992).
To explain the high primary production rates and recovery factors in heavy oil reservoirs, a number of potential mechanisms have been proposed (Smith, 1986; Dusseault and Rothernberg, 1988; Loughead and Saltuklaroglu, 1992; Maini et al., 1993; Kraus et al., 1993; Leung et al., 1995). One of the possible causes for the anomalous behaviour is the in situ formation of bubbly (or foamy) oil due to entrapment of a large number of microbubbles nucleated during pressure drawdown (Ward et al., 1982). Evidence of formation of foamy oils was observed in both well head samples and laboratory tests (Smith, 1986; Maini et a!., 1993). The in situ formation of foamy oil can greatly alter the flow behaviors of oil and gas in a reservoir by (i) enhancing oil mobility with gas bubble nucleation; (ii) preventing rapid depletion of reservoir energy through retardation of free gas flow; and (iii) changing oil properties due to gas bubble dispersion.
