The extreme heterogeneity of carbonate reservoirs in the form of fracture corridors and super-permeability thief zones present challenges to the efficient sweep of oil in both secondary and tertiary recovery operations. In such reservoirs, conformance control is crucial to ensure injected water and any EOR chemicals optimally contact the remaining oil with minimal throughput. Foam-based conformance control is a relatively new technology especially its use for deep diversion in high-salinity and high-temperature conditions. In this work, a laboratory study was conducted to develop and evaluate a foam-based conformance control technology for application in a high-salinity and high-temperature carbonate. Foaming agents (surfactants) were first screened for their suitability with regard to reservoir temperature and salinity where properties such as foamability and foam stability were measured. The best performing surfactants were then used to study the foam-induced mobility reduction across a core composite. The experiments were conducted at reservoir conditions. Foam stability and decay were also investigated in those permeability reduction experiments. Brine and crude oil were injected after foam formation where observed pressure drops allowed quantification of foam stability and decay; hence, the sustainability of mobility reduction. Finally, the potential improvement in reservoir contact and hence oil recovery were examined by oil displacement experiments conducted in specially prepared heterogeneous composites. For the studied conditions of high salinity and high temperature, foaming agents of the amphoteric family as well as one manufacturer proprietary surfactants blend were found suitable in terms of salt tolerance and foam stability. Using the proprietary blend and without oil in core, the generated foam reduced fluids mobility by a factor of 12. The attained mobility reduction was lower in presence of oil but was still acceptable for flow diversion purposes. Using the proprietary blend and with oil in core, the generated foam reduced fluids mobility by a factor of 6 (compared to 12 without oil in core). Oil recovery improvement with foam placement was also found to be significant. These results demonstrate the potential of foams for carbonates with harsh salinity and temperature conditions.

Carbonate reservoirs’ extreme heterogeneity in the form of fracture corridors and super-permeability thief zones present challenges to the efficient sweep of oil in both secondary and tertiary recovery operations. In such reservoirs, conformance control is crucial to ensure injected water and any EOR chemicals optimally contact the remaining oil with minimal throughput. Foam-based conformance control is a relatively new technology especially its use for in-depth diversion in high salinity high temperature conditions. In this work, a laboratory study was conducted to develop and evaluate a foam-based conformance control technology for application in a high salinity and high temperature carbonate. Foaming agents were first screened for their suitability with regard to reservoir temperature and salinity where properties such as foamability and foam stability were measured. The best performing surfactants were then used to study the mobility reduction across a core composite at reservoir temperature and pressure. Foam stability and decay were also investigated in those permeability reduction experiments. Brine and crude oil were injected after foam formation and pressure drops and sustainability of mobility reduction were quantified. The improvement in reservoir contact and hence oil recovery were examined by oil displacement experiments conducted in specially prepared heterogeneous composites. For the studied conditions of high salinity and high temperature, foaming agents of the amphoteric family as well as a special blend were found suitable in terms of salt tolerance and foam stability. The mobility reduction due to foam was 12 times without oil and 6 times in the presence of oil. Oil recovery improvement with foam application was also found to be significant. These results demonstrate the potential of the identified foam system and its favorable impact on sweep efficiency despite the harsh salinity and temperature conditions of the studied carbonate reservoir.

Enhanced oil recovery applications in carbonate reservoirs present the unique challenges of high salinity and high temperature. For foam applications, foaming agents that have good stability at those harsh conditions are therefore desirable. Crude oil, especially light crude has been known to be a destabilizer for foams and therefore foaming agents need to be designed to handle reservoirs with such oil. In this work, we sought to improve our understanding of the de-foaming behavior of Arabian light crude oil on foams generated using an anionic foaming agent and an amine oxide surfactant.Potential anionic and amphoteric foaming agents dissolved in seawater were screened using the dynamic foam analyzer as well as the high temperature high pressure cell. The stability of foam in the presence and absence of crude oil was studied using both nitrogen and air. Foam decay curves were plotted as a function of time.Foam decay with time for both types of surfactant fitted a log decay curve confirming the assumption of exponential decay behavior. A semi-log plot of foam decay revealed interesting phenomena along the decay curve. Three regions were shown by the semi-log plot representing liquid drainage, drainage and coalescence and coalescence alone. In general, foam decay was faster in the presence of oil than without oil as shown by the foam half-life calculated for each case. The effect of pressure on foam stability was also investigated at a temperature of 90 o C. Generally, foam stability tended to be better at higher pressures in most cases. Foam stability parameters were also evaluated to indicate the relative stabilities of foams generated. The amine oxide, while having excellent solubility in seawater also had a longer liquid drainage section as well as a longer decay time in the presence of oil, than the anionic foaming agent. The harsh conditions of high salinity and high temperature present in carbonate reservoirs therefore favor the amphoterics as better candidates.