Cold production of heavy and extra heavy oil is a relatively new technology; nevertheless it accounts for a considerable share of total heavy oil production, both in Canada and in Venezuela. In spite of the conspicuous exploitation of this insitu recovery process, a recognized rationale of the underlying mechanisms is still lacking.
Two main schools of thought have appeared in the last 15 years in the open literature: the first one has been focused only on the atypical PVT and flow properties of heavy oil below the bubble point (the so-called "foaminess"), while the second one has been concentrated on the peculiar rock mechanics behaviour of unconsolidated sand (sand compaction/dilation and permeability evolutions).
In this study models for both aspects were included into a new framework with the aim of better understand the relative weight of each mechanism. Results of this activity allowed to gain new insights into the involved fenomena.
Cold production with sand (CHOPS) contributes for more than half million barrels a day of Canada heavy oil production. To meet demand growth in world fuels in future years requires both the deployment of new technologies and an increase of the performance of existing technologies like cold production.
In spite of the fact that big efforts have been addressed through the modeling of cold production of foamy oils, a recognized model able to explain accurately the oil production when sand is allowed to flow is not yet available. This might be explained by the complexity of the process, that involves peculiarities on multiphase (oil/gas/water/sand) flow in porous media, phase separation kinetics (neglected in conventional reservoir modeling) in deformable unconsolidated sands (geomechanics cannot be ignored)
In this study some models already used in previous heavy oil literature studies and a recent public rheological model developed for volcano magma flow were picked up. In order to understand the coupling effects between all mechanisms the new model was solved numerically in a full coupling framework [1].
Heavy oils show good production in lab tests carried out below bubble pressure due to the high viscosity of oil that prevents gas bubbles to coalesce [2]. The use of conventional reservoir modeling simulators to explain such tests leads to rate dependant relative permeabilities. Although some authors claim that performing lab tests at different flow rates allows to scaleup to field conditions, huge draw-downs are present in the lab experiments that might seldom be realistic in the fields: scale-up will be therefore an extrapolation to very low flow rates.
On the other hand geomechanics studies (see [3] and references therein) are able to match field data production histories with porosities and permeabilities which might be not reliable. The need of the coupling of both aspects (foaminess and geomechanics) appears therefore naturally.
According to us, in fact, a synergistic effect could take place in particular conditions: if the presence of a high porosity front (sand dilatancy front) couples with the bubble point pressure advance inside the reservoir, a bigger driving force for enhanced foamy oil flow might exist.
