Summary
This study probes experimentally the mechanisms of heavy-oil solution gas
drive through a series of depletion experiments employing two heavy crude oils
and two viscous mineral oils. Mineral oils were chosen with viscosity similar
to crude oil at reservoir temperature. A specially designed aluminum coreholder
allows visualization of gas phase evolution during depletion using X-ray
computed tomography (CT). In addition, a visualization cell was installed at
the outlet of the sandpack to monitor the flowing-gas-bubble behavior vs.
pressure. Bubble behavior observed at the outlet corroborates CT measurements
of in-situ gas saturation vs. pressure. Both depletion rate and oil composition
affect the size of mobile bubbles. At a high depletion rate (0.035 PV/hr), a
foam-like flow of relatively small pore-sized bubbles dominates the gas and oil
production of both crude oils. Conversely, at a low depletion rate (0.0030
PV/hr), foam-like flow is not observed in the less viscous crude oil; however,
foam-like flow behavior is still found for the more viscous crude oil. No
foam-like flow is observed for the mineral oils. In-situ imaging shows that the
gas saturation distribution along the sandpack is not uniform. As the pattern
of produced gas switches from dispersed bubbles to free gas flow, the
distribution of gas saturation becomes even more heterogeneous. This indicates
that a combination of pore restrictions and gravity forces significantly
affects free gas flow. Additionally, results show that solution-gas drive is
effective even at reservoir temperatures as great as 80°C. Oil recovery ranges
from 12 to 30% OOIP; the higher the depletion rate, the greater the recovery
rate.
Introduction
Solution gas drive has shown unexpectedly high recovery efficiency in some
heavy-oil reservoirs. The mechanisms, however, that have been proposed are
speculative, sometimes contradictory, and do not explain fully the origin of
high primary oil recovery and slow decline in reservoir pressure. Smith (1988)
first identified this effect. He hypothesized that gas bubbles smaller than
pore constrictions are liberated from the oil, but are not able to form a
continuous gas phase and flow freely. Instead, the gas bubbles exist in a
dispersed state in the oil and only flow with the oil phase. Smith stated that
oil viscosity is reduced significantly, resulting in high recovery performance.
Later, many researchers focused on so-called foamy-oil behavior. Claridge and
Prats (1995) hypothesized that heavy-oil components (such as asphaltenes)
concentrate at the interfaces between oil and gas bubbles, thereby preventing
bubbles from coalescing into a continuous gas phase. Bubbles are assumed to be
smaller than pore dimensions. Claridge and Prats stated that the concentration
of heavy-oil components at the interfaces results in a reduction of the
viscosity of the remaining oil. Bora et al. (2000) discussed the flow behavior
of solution gas drive in heavy oils. Based on their studies, they found that
dispersed gas bubbles do not coalesce rapidly in heavy oil, especially at high
depletion rate. They stated that the main feature of the gas/oil dispersion is
a reduced viscosity compared to the original oil. Models to explain the
experimental results were also established (Sheng et al. 1994, 1996, 1999,
1995).
© 2006. Society of Petroleum Engineers
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History
- Original manuscript received:
4 February 2004
- Revised manuscript received:
1 June 2005
- Manuscript approved:
5 September 2005
- Version of record:
20 March 2006
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