Parallel-core flow tests were conducted with two undamaged core plugs having widely contrasting permeabilities. Tests showed that essentially no diversion of liquid to the low-permeability core would be realized following injection of a foam slug, unless specific permeability conditions were met. Tests also indicated that gas trapping during liquid injection following a foam slug is much more efficient in low-permeability cores than in high-permeability cores. Trapping of foam caused the total mobility (λt) in the low-permeability core to remain low during liquid injection, while λt in the high-permeability core increased greatly. In one test, this effect caused complete shutoff of liquid flow to the low-permeability core after a small foam slug was injected.
In other tests, a small foam slug was followed by injections of unfoamed acid into a damaged and an undamaged sandstone core. The results indicate that the combined effect of the foam slug and acid was extremely effective in diverting acid flow from the undamaged core to the damaged core. Long core plugs of similar permeability were used. A thin, low-permeability core wafer was placed at the core face of one of the plugs to simulate near-wellbore damage. This thin damage layer caused highly uneven liquid flow to the two cores before foam slug injection. The acid diverted to the damaged core caused a rapid increase in the permeability of the damaged zone. Sustained diversion of liquid flow to the damaged core was then maintained. Injection of a second foam slug caused the liquid flow distribution to the cores to nearly equalize, since trapped gas reduced liquid mobility in both cores. The liquid flow distribution then diverged as mobility in the cores increased at unequal rates.
The bottomhole pressure (BHP) response from a matrix acidizing treatment using foam slugs for diversion illustrates the agreement of field results with laboratory results.