Stability Improvement of CO2 Foam for Enhanced Oil Recovery Applications Using Nanoparticles and Viscoelastic Surfactants
- Ahmed Farid Ibrahim (Texas A&M University) | Hisham Nasr-El-Din (Texas A&M University)
- Document ID
- Society of Petroleum Engineers
- SPE Trinidad and Tobago Section Energy Resources Conference, 25-26 June, Port of Spain, Trinidad and Tobago
- Publication Date
- Document Type
- Conference Paper
- 2018. Society of Petroleum Engineers
- 5.4.1 Waterflooding, 5.4 Improved and Enhanced Recovery, 2.4 Hydraulic Fracturing, 1.6 Drilling Operations, 5 Reservoir Desciption & Dynamics, 5.4 Improved and Enhanced Recovery, 5.7 Reserves Evaluation, 5.7.2 Recovery Factors, 5.5.2 Core Analysis, 1.6.9 Coring, Fishing, 1.8 Formation Damage, 2.5.2 Fracturing Materials (Fluids, Proppant), 2 Well completion
- EOR, Nanoparticles, VES, CO2 Foam
- 4 in the last 30 days
- 148 since 2007
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CO2-enhanced oil recovery (EOR) was started in 1950. Low sweep efficiency and early breakthrough issues were associated with the CO2-EOR system. Foam-EOR was introduced to improve the sweep efficiency instead of polymers to avoid formation damage caused by polymers. Foam stability reduces in high-salinity environments, high-temperature formations (>212°F), and in contact with crude oil. The present study the using of nanoparticles and viscoelastic surfactants (VES) to improve foam mobility control for EOR application.
This paper study the CO2-foam stability with using alpha olefin sulfonate (AOS) as a foaming agent and the change on the mobility-reduction factor (MRF) for different foam solutions by adding nanoparticles and VES. To achieve this objective, foam-stability for different solutions was measured at 77 and 150°F using high-pressure view chamber (HPVC). Interfacial tension measurements were conducted to investigate the destabilizing effect of crude oil on the different foam systems. Coreflood experiments were conducted using Buff Berea sandstone cores at 150°F, saturated initially with a dead-crude oil. The CO2 foam was injected with 80% quality as tertiary recovery mode. The oil recovery and the pressure drop across the core were measured for the different foam solutions.
Adding silica nanoparticles (0.1 wt%) of size 140 nm and viscoelastic cocamidopropyl betaine surfactant (cocobetaine VES) (0.4 wt%) to the AOS (0.5 wt%) solution improves both foam stability and MRF. In contact with crude oil, unstable oil-in-water emulsion formed inside the foam lamella that decreased foam stability. A weak foam was formed for AOS solution, but the foam stability increased by adding nanoparticles and VES. The interfacial tension measurements revealed positive values for the spreading and the bridging coefficients. Hence, the crude oil spread over the gas-water interface, and lamella films were unstable due to the bridging of oil droplets. The oil recovery from the conventional waterflooding (as a secondary recovery before foam injection) was 48% of the original oil-in-place. From the series coreflood experiments, AOS was not able to enhance the oil recovery. However, more oil was recovered in the presence of nanoparticles (12 %) and VES (18%).
Nanoparticles and VES were able to improve the foam stability for AOS solution. Adding nanoparticles is highly recommended for EOR applications, particularly at high temperatures.
|File Size||1 MB||Number of Pages||17|
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