The problem of low productivity natural gas reservoirs that are positioned over active aquifers is addressed. The principles of co-current and counter-current imbibition as used in fractured oil reservoirs are adopted for application in natural gas formations. Experiments were performed on core samplesfrom Western Canada and on Berea sandstone. The tests involved both co-current and counter-current primary and spontaneous imbibition. The production of gas was measured through weight increases in the core samples. Long term effects of the imbibition process were also observed. Furthermore, visualization experiments using glass micromodels were performed.
The results to date indicate that the imbibition process in natural gas reservoirs is also direction oriented. Large amounts ofothenvise producible gas will be trapped because of the elimination of accessible pathways from the fast advancing water. The potential of gas migration through these pathways is addressed. Moreover, the productivity increase of such wells is discussed. It is concluded that alternative methods for the recovery of these reservoirs must be sought.
The topic of water imbibition in fractured reservoirs has been studied for over forty years. Aronofsky et. al. I used an exponential type of formula to correlate oil recovery data from fractured reservoirs. The equation used is as follows: Equation (1) (Available in full paper)
In the figures of the Aronofsky et al.1 paper, one can see that the mean water rise as a function of time reaches a first plateau where the oil recovery slows down after an accelerated period. This is followed by a second stage of water saturation process to higher saturation values. This trend appears as though the imbibition process slows down before it starts up again. Gupta and Civan2 extended this work to include contact angle effects.
Iffly et al. 3 have performed a large number of laboratory tests on fluids and porous media taken from a field exploited by ELF to ascertain the waterflood efficiency in a fissured oil-field. Their results demonstrated the interactions between connate water, injected brine, oil and rock at any time during imbibition. They found that increasing carbonate content and organic matter in the sands decreases the recovery of oil. They further found that gravity was a very important factor in the onset of imbibition. They postulated that the recovery evolution with time is a function of too many parameters to be described by a simple law. Fissure size and initial saturation were not found to drastically affect oil recovery within the limits of their study.
Hammon and Vidal4 studied the effects of the height and the boundary conditions of water-imbibing samples on oil recovery curves versus time. They found that conventional two-phase flow equations describe the relevant mechanisms. Also, the imbibition capillary pressure curves of small samples could be used confidently for scale-up. The fracture spacing and the geometry of the fissure network have a strong influence on the oil recovery rate. Ultimate oil recovery appears to be independent of the boundary conditions for water-wet rocks.
