When some heavy-oil reservoirs are produced using solution gas drive, they show: (1) higher than expected production rates, (2) low produced gas-oil ratio, and (3) relatively high recovery. The reasons for this behavior are not clear. A series of X-ray computerized-tomography (CT)-monitored, heavy-oil pressure depletion experiments were carried out to examine the core-scale phenomena using high pressure/high temperature equipment. Viscous white mineral oil (mu = 220 cp at 20 degreesC) and 9degrees API heavy crude oil from the Hamaca region of the Orinoco Belt, Venezuela, were used. A transparent cell attached to the outlet of the sand pack allowed monitoring of bubble size and shape as bubbles exited the sand pack. Conventional solution-gas-drive behavior was observed in the experiments conducted with the mineral oil: large regions of pore space within the core became saturated with a continuous gas phase and ample gas mobilization was witnessed. In the heavy-crude-oil experiment, however, it was inferred that gas bubbles were of slightly greater size than pore dimensions. The fraction of gas mobilized was not large. The difference in behavior between mineral oil and crude oil results suggests an effect due to large oil-phase viscosity, relatively rapid depletion rate, and possibly the high asphaltene content of Hamaca crude oil. Critical gas saturation was gauged as the saturation at which mobile gas was first observed regardless of whether the gas was continuous. For both experiments, the critical gas saturation was observed to be around 3% to 4%. (C) 2002 Elsevier Science B.V. All rights reserved.