Polymer foam controls CO₂ flow in lab rock cores

Inside a laboratory system built to mimic a reservoir, researchers pushed polymer-reinforced CO₂ foam through sandstone cores at 90 bar and 40°C. The formulation, called CO₂ PEF, showed a mobility reduction factor up to seven times higher than conventional foam, according to the study led by Jorge Rodrigo Lliguizaca-Davila of ESPOL and published in Geoenergy Science and Engineering.

The problem is simple to see in porous rock: CO₂ has low density and high mobility, so it can rush through the channels offering the least resistance. Parts of the reservoir may then remain untouched, while gas accumulates at the top. Foam is used to slow that movement; the added HPAM polymer is intended to make the foam more stable and extend its effect underground.

The experiments found that the polymer-reinforced foam increased the system's apparent viscosity and resisted flow more strongly than the conventional formulation. In long sandstone cores, it created greater resistance near the entry zones, a pattern consistent with polymer retention and partial blocking of preferential channels. Even after the chemical injection stopped, resistance stayed high while pure CO₂ continued to flow.

So what changes in practice? If the behavior holds in oil-bearing reservoirs, operators could steer CO₂ through more of the rock instead of allowing early gas channeling. That could improve contact with residual oil while increasing the share of injected gas retained in geological formations—linking enhanced oil recovery with underground CO₂ storage.

The boundary is clear. The tests were conducted under laboratory conditions and did not include oil, so their direct effect on oil recovery remains to be measured. Field application will also depend on each reservoir's salinity, temperature, heterogeneity, mineralogy and injectivity; no field-scale deployment is established by this study.