Research Shows Boosts to EOR from Supercritical CO2 Foam

Like getting the last bit of ketchup from a nearly empty bottle with a few drops of water or a knife, innovative EOR techniques have included injecting gas, water or alternating the two to get more oil from existing wells.

Each has its flaws.

“Gas can cut across to the producing zone and you start producing it too quickly, or because the oil and the gas have such different viscosity, the gas will kind of finger through the oil and create a super highway and go straight to the other side,” said Angel Wileman, thermofluids manager at the Southwest Research Institute (SwRI). “The gravity does make the gas go to the top and the oil kind of stays down at the bottom. This works, but it has poor sweep efficiency.”

The water alternating gas method—injecting water followed by gas—has improved sweep efficiency but the presence of water reduces the ability of gas to separate into layers, impacting oil displacement. Surfactant alternating gas flooding has proven to be more effective at sweeping oil from reservoirs to boost production. Still, it is can have stability issues under HP/HT conditions.

However, combining water, gas and surfactant—the same cleansing agent that causes foamy shampoo by reducing the surface tension of water—to create foam-entrapped supercritical CO₂ (sCO₂) could prove to be a winning combination if certain conditions and foam quality are ideal, according to Wileman.

Researchers say they have found a way to squeeze more oil from reservoirs and to keep sequestered carbon from migrating to the surface using sCO₂ foam injection.

Applying principles from traditional CO₂-EOR methods, researchers from SwRI and the University of Texas at Austin say CO₂ in its supercritical state—displaying gas-like viscosity and liquid-like density—impact mobility and storage behavior.

“We wanted to look at what is the best foam that you can make so that you can improve the sweep efficiency and get the best enhanced oil recovery,” Wileman, the project’s co-principal investigator, said during the recently held Carbon Capture Technology Expo in Houston. “The best foam has a high stability. It has ideal viscosity.”

The insight was shared amid ongoing efforts to increase oil production from existing wells, instead of drilling new ones, to meet global energy needs and help mitigate climate change by using captured CO₂ underground.

Foam chemistry

The three-part research study in a lab included developing the foam formula, flowing the CO₂ through a fractured granite core (done by UT Austin) and flowing the foam through a heterogenous sand pack (by SwRI). The intent was to imitate subsurface formations the foams would encounter in oil fields.

“Before you can make a foam, you actually have to get the chemistry right for the liquid side of it,” she said, adding the aqueous foam used had a combination of surfactants and salt to make it stable when introduced to the CO₂.

“We were specifically investigating the effect of flow rate, flow direction … whether you go up or down through the sand pack, whether we pre-generated the foam and then the temperature effect,” she said.

As explained by SwRI, sCO₂ foams exhibit a behavior known as shear thinning, meaning their viscosity decreases under higher shear rates. This allows the foam to more easily flow through high-permeability zones while limiting flow into low-permeability regions. “As a result, they improve sweep efficiency for oil recovery and help reduce the risk of CO₂ migration by limiting channeling and preferential flow through fractures.”

Among the study’s significant findings was that foam viscosity increased up to a certain pressure point then dropped, Wileman said, giving researchers insight into foams’ behavior underground.

The findings

A foam quality of zero means it’s 100% liquid. When the gas content is less than 40%, discrete bubbles form but they don’t touch, Wileman said. As the gas amount rises in the foam, it takes on more of a honeycomb-type structure. “Ultra-dry foam, which is 90% to 95% [gas], can be a very strong foam, and you can see those bonds make more of a polygon versus a circle,” she said, “and that’s where we want to be because we want to use less water for this application and we’re looking for high strength.”

When the foam reaches 97% gas, it begins to break down and lose its structure and stability.

In addition to identifying the ideal gas-to-liquid ratio, researchers determined the higher the viscosity the better the foam is at sweeping the oil from one side of the formation to the other.

“When we increased our velocity, the flow with the foam, the viscosity did increase and we think that’s because it was kind of regenerating the foam as it was going through the sand pack,” she said. The flow direction didn’t make much of a difference.

“When you’re going to pre-generate foam, create it on the top surface and push it downhole for EOR, you need some really expensive equipment and it is a multi-phase process,” Wileman added. “It’s complex. You need high pressure and so there’s benefit here, but there’s not enough of a viscosity increase to warrant getting that extra equipment.”

Researchers also found that higher temperature broke down the foam faster, reducing its viscosity. “The wells that we’re operating in for EOR are in the 150 [C] range. So that’s something to consider.”

Key takeaways: Foam quality matters. When using sCO₂ foam for EOR, the “sweet spot” is at 95%. Higher flow rates are better for viscosity, but higher temperatures break down foam faster.

“These laboratory experiments are crucial for understanding the behavior of sCO₂ foams under various conditions before attempting field applications,” SwRI’s Raouf Tajik, who oversaw the laboratory testing, said in a news release. “By collaborating and comparing different testing methods and scales, we aim to develop a comprehensive understanding of the utility of sCO₂ foams while addressing the challenges associated with their field use.”