Experimental Investigation on Temperature-Resistant CO2 Foam Flooding in a Heterogenous Reservoir

Gas channeling treatment is a huge challenge for oil displacement and CO2 sequestration in the practical CO2 flooding process. The foaming agents can be used in the gas flooding process, which presents good application potential for gas channeling blockage. However, high temperature can affect surfactant foaming properties. This work takes a high-temperature heterogenous sandstone oil reservoir as an example; the foaming performance of different surfactants was evaluated via foamability, thermal stability, crude oil tolerance ability, and dynamic blocking capacity. The profile control performance of the optimized foaming agent was investigated via dual-core gas flooding experiments. (1) The results show that QPJ-c featured good foaming stability, which made it present the largest foam comprehensive index, although its foaming volume was slightly lower than that of QPJ-b. Its foaming volume retention rate was 83.2%, and its half-life retention rate remained 88.9% after 30 days aging at a temperature of 110 °C. (2) The foam resistance factor increased from 7 to 17 when the core permeability increased from 2 mD to 20 mD. This indicated that the high-permeability zone could be preferentially blocked by foam during the foam injection. (3) The dual-core flooding experiments verified that the fractional flow of the high-permeability core severely decreased due to the blockage of foam. The incremental oil recovery of the low-permeability core was 27.1% when the permeability ratio was 5. It increased to 40% when the permeability ratio was increased to 10. (4) Our work indicates that temperature-resistant CO2 foam could be a good candidate for profile control during CO2 flooding in the target reservoir.