Transient Foaming Behavior of CO2-soluble, Viscoelastic Surfactant in Microfluidic Model, Sand Pack and Limestone Core

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Aqueous foam has been demonstrated through laboratory and field experiments as an effective conformance control technique for gas enhanced oil recovery and carbon sequestration. The use of polymer as an additive to an aqueous foam is a common practice to increase the viscosity of the foam liquid phase. This viscosification improves foam performance by increasing the foam apparent viscosity and reducing the rate of foam bubble coalescence. This study explores the use of worm-like micelle (WLM) an alternative viscosifying agent to polymer. We utilized a cationic, amine-based surfactant; whose, micelle transforms from spherical conformation to WLM at elevated salinity. Another distinguishing feature of this surfactant is its ability to dissolve in supercritical carbon dioxide (CO2). Delivery of surfactant in the foam gaseous phase may alleviate injectivity issue around the injection well, typically associated with high viscosity polymer-surfactant solution. Additional potential advantages of WLM over polymer include reversible shear degradation and resistance to extreme temperature and salinity. Our study investigates how the presence of WLM structures affect the transient foam behavior in microfluidic porous media model, sand pack, and limestone core. In these porous media, we performed co-injection floods with two liquid phase salinities: low salinity (15 wt. % NaCl) associated with spherical-shaped micelle and high salinity (20 wt. % NaCl) associated with WLM. In the microfluidic model, we performed co-injection floods with constant pressure gradient and constant liquid injection rate. It was found that foam in the higher salinity case reached a higher apparent viscosity value after 30 total injected pore volumes. Microscope image analysis revealed that foam in the lower salinity case, in fact, developed earlier and possessed finer texture. However, the higher salinity case exhibited larger saturation of trapped gas. In the sand pack, we performed co-injection floods at 50% injection quality at 40C. The surfactant was injected in the CO2 phase. We observed strong foam generation both in the lower and higher salinity cases with foam apparent viscosity of at least 500 cp. However, in comparison to the low salinity cases, the high salinity foam flood associated with presence of WLM led to better foam performance. We observed earlier onset of strong foam propagation; as well as, higher apparent viscosity buildup rate. In the limestone core, we performed co-injection floods at 50% injection quality at 120C. At higher temperature, pressure required to dissolve the surfactant increases. Thus, the surfactant was injected in the aqueous phase due to pressure limitation of the experimental setup. We did not observe strong foam generation in the lower salinity case. In the higher salinity case, we observed foam generation that reached 90 cp after 5 total injected pore volumes. Better foam performance at higher salinity in microfluidic model, sand pack, and limestone core may be attributed in large part to the presence of WLM structures; which, may have led to in-situ viscosification of foam liquid phase and an increase in disjoining pressure between foam films.

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Journal: TechConnect Briefs
Volume: 2, Materials for Energy, Efficiency and Sustainability: TechConnect Briefs 2018
Published: May 13, 2018
Pages: 93 - 96
Industry sectors: Advanced Materials & Manufacturing | Energy & Sustainability
Topics: Materials for Oil & Gas
ISBN: 978-0-9975117-9-6