In this work we implement a dynamic gas-oil interface tracking algorithm for the mobilization of bubbles under intense pressure gradients, to improve the simulation of solution gas drive for heavy oil in the framework of a pre-existing pore-scale network simulator. The model is used to characterize both the stationary capillary controlled growth of bubbles characteristic of slow depletion rates (far wellbore region) and the flow phenomena in the near wellbore region: in this case it is shown how viscous forces lead to an increased persistence of small bubbles for a longer time, creating an effect similar to what described as foamy oil.
The study has identified three different regimes of bubble growth, depending upon capillary number and depletion rate, and these regimes appear to cover the entire range of phenomena observed experimentally. These three regimes are:
the conventional capillary-controlled growth pattern at low capillary numbers,
viscous biased growth at intermediate capillary numbers, and
bubble mobilization and break up leading to foamy behaviour at the highest capillary numbers and depletion rates.
A predictive methodology for the associated continuum-scale constitutive relationships, such as relative permeabilities, is also proposed for each of the three depressurisation regimes.
In solution gas drive, bubbles nucleate and grow within saturated oil when the reservoir pressure is lowered below the bubble point. A period of internal gas-phase expansion maintains reservoir pressure, driving oil to the wellbore region. After some time, continued pressure reduction leads to the formation of a connected gas phase that is capable of being produced along with the oleic phase: consequently, the total produced gas-oil ratio (or GOR) in the well begins to increase. In general, once the connected gas phase develops, oil production begins to decrease.
This general description can be inadequate in the context of heavy oils where additional characteristics, such as foamy oil, and atypically high recoveries are observed. Indeed, recoveries of up to 20% of initial oil in place have been estimated for some heavy oil reservoirs(1) It is thought that the formation of foamy oil, where small bubbles tend to remain dispersed in oil and flow with it, is a key factor in explaining the high recoveries. However, foamy oil is not pervasive – it is observed in some experiments(2,3,4,5,6,7) but not in others(8,9,10,11) and seems to depend upon the particular rock-fluid system and depletion parameters characterizing the experiment. High depletion rates in particular tend to produce high pressure gradients and this appears to play a major role in determining whether or not foamy oil is formed(4,5,7,12,13) as small bubbles are more easily mobilized at high rates. Akin and Kovscek(6), by simulating near-wellbore conditions, found that very high pressure gradients could develop: in this way viscous forces can greatly exceed the capillary forces associated with the system, leading to mobilization of individual gas bubbles.
However, other factors must be taken into account.
