THANK YOU to Drs Prodanović, Nguyen, and Johnston for an informative webinar. You can watch the webinar recording and download the presentation slides by using the links below:
Join CPGE for a free webinar for a discussion on the latest developments in subsurface foam applications. Dr. Nguyen will present his current research on advanced gas and chemical enhanced oil recovery methods in hydrocarbon formations with low permeability under hassle conditions (i.e. high salinity and high temperature), thermal and solvent based recovery of heavy oil and oil shale, improved production of unconventional resources, and engineering of complex fluids (foam, emulsion, polymer gel, nanoparticle dispersion) for near wellbore conformance and far-field fluid mobility control. Dr. Maša Prodanović and Dr. Keith Johnston will discuss the recent advances in foam subsurface applications. Please contact Krystal Boulanger at firstname.lastname@example.org for more information.
*registration is only mandatory for those seeking CEUs. A link to the webinar will be on the CPGE website on the morning of May 12th.
"Foam in Enhanced Oil Recovery applications" – Quoc Nguyen
CO2 flooding is one of the most important methods for enhancing oil recovery (EOR). The number of CO2 injection projects, particularly for carbonate reservoirs, has continuously increased with the importance of CO2 capture, storage and utilization. However, an unfavorable mobility ratio, reservoir heterogeneity and gravity segregation can reduce the macroscopic sweep efficiency. In-situ foaming of injected CO2 is the mobility control technique that has been successfully applied in oil reservoirs to improve sweep efficiency. A dispersion of CO2 into a surfactant solution has an apparent viscosity several orders of magnitude greater than the viscosity of either phase in the dispersion. In addition, substantial gas trapping in foam can further reduce gas relative permeability as a unique rheological characteristic of dispersed flow in porous media.
While conventional foaming surfactants only traverse the reservoir in the aqueous phase, we have developed a novel foam process in which the surfactant can partition between the CO2 and the aqueous phases. This process exhibits several advantages over conventional foam, of which lower surfactant adsorption, more in-depth robust foam, and higher injectivity are the most important. In the past decade, great efforts have been made to obtain low toxicity and low cost CO2-soluble surfactants, non-fluorinated surfactants being of the most interest. The surfactant partition between CO2 and water phases was much more sensitive to surfactant structure than temperature and pressure. An increase in surfactant partition coefficient lowered the rate of foam propagation. Field-scale foam simulations indicate that foam performance and surfactant transport are constrained by surfactant partition coefficient. Our findings enable us to tailor properties of CO2 soluble surfactants (i.e. partition coefficient) to a wide range of reservoir conditions and optimal injection strategies.
"Development of Ultra-Dry Foams: Towards Water-less Hydraulic Fracturing" – Maša Prodanović and Keith Johnston
CO2/water and N2/water foams are of interest for mobility control in CO2 EOR and as energized fracture fluids, or hybrid processes that combine aspects of both processes. In fracturing applications, it would be desirable to lower the water level as much as possible to minimize the production of wastewater and formation damage. However, it is challenging to stabilize ultra dry foams with extremely high internal phase gas fraction given the high capillary pressure and the rapid drainage rate of the lamellae between the gas bubbles.
We recently demonstrated that ultra-dry CO2-in-water foams may be stabilized with surfactants that form viscoelastic wormlike micelles in the aqueous phase. These wormlike micelles are formed by tuning the surfactant packing parameter with electrolytes or a second oppositely-charged surfactant to stabilize ultradry CO2-in-water foams with foam qualities as high as 0.98 and apparent viscosities more than 100 cP. They are salinity and high temperature tolerant (tested up to 90 degrees Celsius), and can carry sand at high pressure, room temperature (as tested in a sapphire cell). Limited numerical tests in a fracturing application show less leak-off and easier clean-up for these fracturing fluids. Finally, environmentally friendly surfactant options are available resulting in comparable foam properties.