Hydraulic fracturing—or fracking—has unlocked vast amounts of oil and natural gas from shale rock in the United States, and has the potential to do the same around the globe (see “Natural Gas Changes the Energy Map”). But fracking also consumes huge quantities of water, which it contaminates with a heady mix of toxic chemicals, a problem that threatens to slow this expansion.

GE says it has a technology that could help—an energy-efficient process that could cut the cost of water treatment in half. The technology could also decrease the chances of toxic waste spills.

Concerns about water pollution and other environmental issues related to fracking have led some places, including France and New York State, to block the process. As fracking increases in dry areas and places that lack adequate treatment and disposal options, pressure to block it could grow.

“Water-treatment technology is going to become more and more critical as the industry moves forward,” says Amy Myers Jaffe, executive director of energy and sustainability at the University of California at Davis, and a new member of a GE environmental advisory board. She says the continued use of fracking depends on the “industry getting its act together to do it in an environmentally sustainable way.”

Better water-treatment options could change the way oil and gas producers operate by making it economical to treat water at fracking sites instead of trucking it long distances to large water-treatment facilities or disposal wells. The technology is specifically targeted to places such as the Marcellus shale, one of the largest sources of shale gas in the U.S., where wastewater is far too salty for existing on-site treatment options (see “Can Fracking Be Cleaned Up?” and “Using Ozone to Clean Up Fracking”). 

Each fracking well can require two to five million gallons of fresh water, which is pumped underground at high pressure to fracture rock and release trapped oil and gas. Much of that water flows back out, carrying with it the toxic chemicals used to aid the fracking process, as well as toxic materials flushed from the fractured rock.

Producers currently reuse much of that water, but that involves first storing it in artificial ponds, which can leak, and then diluting it, a step that consumes millions of gallons of fresh water. Eventually they can’t reuse the water any more so they need to ship it, often over long distances, to specialized treatment and disposal locations. Transporting the wastewater is expensive, and it comes with a risk of spills. At disposal sites, the wastewater is injected deep underground in a process that can cause earthquakes.

The new technology would make it unnecessary to dilute the wastewater, or transport it for treatment or disposal. It is based on a desalination technology known as membrane distillation, which combines heat and decreased pressure to vaporize water using membranes to separate pure water vapor from salt water.

Ordinarily, membrane distillation works by applying heat to the water at one end of the process, while at the other side cooling off the water vapor to make it condense. GE has replaced the heating and cooling systems with one device, a vapor compressor borrowed from industrial refrigerators, making it more efficient. “Instead of separate heating and cooling sources, you have just one piece of equipment,” says Ajilli Hardy, an energy systems engineer at GE Research.

Based on pilot-scale tests of a machine that can process about 2,500 gallons of water per day, GE researchers say they are on track to cut the costs of treating salty fracking wastewater in half. The system needs to be scaled up for commercial use, but a full-sized system could treat about 40,000 gallons per day.

The technology won’t be useful everywhere, says Mark Boling, president of V+ Development Solutions, a division of the natural gas producer Southwestern Energy, since in some places the wastewater isn’t very salty. But it could help in places where the wastewater is too salty to be treated with existing technologies, or in dry areas such as the Eagle Ford shale deposit in Texas, he says. The technology, if it works as advertised, “would make a big difference,” he says.