This paper is a study of a novel recovery process for stratified reservoirs with large permeability contrasts. A slug of foaming surfactant is injected alternately with gas, thus by analogy with WAG making this a SAG injection process. A combined ex-perimental and numerical evaluation demonstrating effective diversion by foam and significant recovery potential over WAG of the method is reported.

An experiment with the new process was performed in a visual 2-D porous medium flow model approximately scaled to the conditions of a North Sea reservoir that is characterized by high permeability contrast and limited interlayer communication. The experiment showed poor performance of conventional WAG, which swept mainly the high-permeable layer. Placement of a surfactant slug and later foam generation in the swept layer was successfully demonstrated and gave efficient injectant diversion into the other layers, resulting in complete sweep of the reservoir model by continued WAG.

History matching of the experiment was performed using a reservoir simulator in-corporating an empirical foam model and a reservoir description corresponding to the three layers of the physical model. Successful matching was obtained of WAG injection before and after foam treatment and the simulator captured the characteristic features of the foam process, including surfactant slug placement, foam generation, and injectant diversion. It was also found to allow some flexibility in process modelling by means of the available model parameters, primarily those for surfactant transport and loss, foam mobility reduction, and relative permeabilities.

In summary the results of this paper show experimentally and by simulation on the same system that SAG injection as implemented here is superior to WAG injection and that the rich observations made in the experiment can be matched with reasonable accuracy using a commercial simulator with only empirical parameters.

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