Adjusting the saline levels of fracking fluid may help drillers get more oil out of the ground on their first production round, a presenter said on June 11 at the Unconventional Resources Technology Conference (URTeC) in Houston.
Drillers know they’re leaving plenty behind. The first production round of most shale wells typically extracts about 10% of what’s there, according to the Department of Energy.
“We’re leaving 90% of the resource behind and that narrows our window economically,” Geoffrey Thyne, CTO at ESal (Engineered Salinity), said at URTeC. “We can’t make as much oil out of shale as we want. And more importantly, we put this huge investment capital investment in the ground.”
ESal, based in Laramie, Wyoming, has found that wettability can make a difference by enabling oil to flow more easily. ESal’s data came from four plays—the San Andres and Wolfcamp formations in the Permian Basin, the Bakken in North Dakota and Vaca Muerta in Argentina.
The science-book definition of wettability is the ability of a liquid to maintain contact with a solid surface. For a driller, the wettability level affects the oil recovery. When water flows more easily, oil flows less easily, and vice versa.
“If you have a field that is at neutral wettability, you get a lot more oil,” Thyne said. “The best drainage in the rock is at neutral wettability,” where oil and water flow equally well.
Changing the wettability also changes the permeability.
"Permeability is about pore throats, not pores,” Thyne said. “That’s the choke point. If your pore throat is lined with water for an oil droplet moving through that pore throat, it’s smaller than the physical dimensions because you can’t push the water clinging by capillary forces out of the way.”
Shale has smaller pore throats than sandstone or limestone, so the recoveries from shale are less.
“The smaller the pore throats, the greater this effect,” he said. “Our limitation on recovery is trying to push the oil through these water-wet pore throats.”
It was a surprise to learn that wettability is not fixed in a reservoir, Thyne said.
“It can change with salinity,” he said. “And what do we do when we frack a reservoir? When we complete that reservoir, we stick a new fluid in and we change, potentially, the wettability.”
ESal got to run a side-by-side test when two companies in New Mexico asked for help because they were getting too much water and not enough oil from their wells. The first drilled 10 wells using fresh water in its completion fluid; the second switched to using produced water in its completion fluid. The produced water increased the salinity in the reservoir with impressive results.
"We don’t have enough data yet to really get an EUR and see if this is going to hold up, but anybody who doesn’t want 20% more oil at IP 90, raise your hand,” Thyne said. “And let’s not even talk about the money you save by using produced water as your frac.”
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Every reservoir is different. In the Bakken, using fresh water improves the return because of the nature of the rock in that play. The Wolfcamp’s mix of carbonate and quartz calls for a different strategy. In the Vaca Muerta, the lesson was to cut back on surfactants.
The cost of the fluid adjustment is $1 to $4 per incremental barrel produced, Thyne said. It’s cheaper to mix fluids than to treat them to reach an optimal salinity.
“Wettability matters in shale or any reservoir,” Thyne said. “The bottom line is you get an engineering solution. It’s another tool in the toolbox.”