Technology innovations have led to an explosion of oil and gas production in the Bakken shale and across the United States. The combination of horizontal drilling and hydraulic fracturing are making previously unattainable petroleum reserves accessible and economical.
Yet as one natural resource proliferates, another begins to feel the strain. Oil and gas production, in particular hydraulic fracturing, uses large volumes of fresh water. Fracking, as hydraulic fracturing is often called, is the process of injecting a mixture of water and chemicals at high pressures to create fissures in rock formations, allowing trapped oil and gas to escape. Thus, the fracking process both requires a significant amount of water going in and results in a large volume of water flowing back out of the well, presenting the twin challenges of finding enough water for injection and treating or disposing the flowback water after fracking.
Each fracking event requires approximately 2 million gallons of water, placing substantial short-term demand on local rivers, aquifers and water treatment facilities. Water prices in North Dakota range between 50 cents to 85 cents per barrel – a barrel equates to approximately 31.5 gallons of water. Options for managing flowback water include disposing of it in pits or diluting the produced water with fresh water and recycling it for use in another fracking operation.
Just as with petroleum production, water in the oilfields is on the cusp of a technological revolution. Investors and innovators have recognized the challenges created by high energy demand and limited water resources, and are increasingly bringing to market new solutions to treat, reuse and recycle water resulting from fracking operations.
In March 2012, Halliburton announced it had commercialized technology to recycle flowback water, reducing water costs by $400,000 per well in the Bakken. The technology allows companies to use less fresh water while reducing contaminants that can harm well efficiency. Other companies are investing in processes to remove contaminants from flowback water or are exploring the purification and use of produced water from other industrial processes. Some of these technologies are in the earliest stages of development or deployment, but signal a new future for resource use in the Bakken.
GE: Imagining a Better Oil Patch
Eight years ago, industrial giant GE acquired a small technology company that specialized in zero liquid discharge technology, a method of treating wastewater that results in no liquid discharge. Because of that acquisition, GE Water now offers a suite of technologies for treating, recycling and reusing produced water in the oil field. In a state like Montana, where water is scarce and disposal options are limited, the ability to efficiently and effectively reuse water from fracking operations is vital.
“In Montana, the lack of ability to dispose of large volumes of water has really gotten the attention,” said Bill Heins, general manager of GE’s thermal business line. “If you’re able to come up with a system where you need much less freshwater, that’s going to help not only public perception, but helps the producers as well, because you don’t have to fight over freshwater use.”
GE is currently deploying what is known as evaporative treatment options in Pennsylvania’s Marcellus Shale and throughout Texas, and is in talks with four potential clients in the Bakken region to bring its technology to the area. Assuming those talks move forward, GE systems could be operational by 2015.
An evaporative system operates on a simple principle: heat produced water until it evaporates, leaving behind all the solids like salt and minerals, and then condense the water back into a liquid for reuse. Heins says this process results in 98 percent to 99 percent water recovery, with only a small portion lost in the treatment process.
“Basically you are recovering all that water so you don’t have any wastewater to dispose of,” he said.
For the oil field, GE has developed three distinct evaporative options: a small, mobile evaporator which can process up to 50 gallons per minute and is typically used for oil field operations where equipment can be moved from one well pad to another; a fixed produced water treatment facility, which typically processes about 500 gal/minute and is used for sites with concentrated number of wells in one area, central facility; and finally a crystallization system, which recovers nearly all the water, crystallizes all the salts, and then offers two produces: reusable water and road salt.
In the Bakken, particularly on the Montana side, flowback water from hydraulic fracturing has a high saline content – as much as six or seven times sea water, according to Heins. Accordingly, a crystallization system has significant potential benefit for the region. That also means that the technology has to be modified and designed specifically to handle the unique composition of water produced from Bakken operations.
Heins notes that produced water disposal costs can run as high as $2-$3/barrel, making treatment options that allow large volumes of water to be reused economic for oil and gas regions.
“With a crystallizer you are really minimizing that cost because you are recovering and reusing the water,” he said.
Winner Water: Delivering Industrial Synergies
John Ontiveros, CEO of Winner Water Services, has a very different vision for water treatment and reuse in petroleum production. Rather than recycling flowback water for reinjection during a fracking operation, Ontiveros is looking to treat water from related industrial production and deliver it to water-hungry oil fields.
“The oil and gas industry uses a lot of fresh water,” said Ontiveros. “That’s starting to put a real strain on water sources.”
Winner Water’s treatment system uses liquid ion exchange technology, a water treatment process that uses an organic extractant to attract minerals and salt in wastewater, resulting in a cleaner water output. The process recovers about 95 percent of the water that goes through the system. Winner Water’s process also uses no heat or pressure, so it works at ambient conditions without extra energy inputs.
Currently, Winner Water is developing a treatment system that would take acid mine drainage water from Pennsylvania’s coal mines, treat it, and deliver it to nearby fracking operations in the Marcellus shale. In 2008, Winner Water tested a demonstration-scale facility, treating more than a million gallons of water in three months to near potable standards.
The company is in the process of designing and fabricating a small commercial-scale facility for the same site, scaling from 30 gallons/minute tested to 100 gallons/minute for the new plant. Winner Water partnered with Battelle to develop and test the technology. Ontiveros believes that having a larger plant in place will help industry embrace the technology.
“This will allow us to establish our business, demonstrate our technology, show that it works, and show that we meet the requirements of the oil and gas industry,” he said. “What we’re finding out is that each company has its own requirements. Obviously, they’d like to have it like fresh water. We are pretty close to fresh water.”
Winner Water’s process results in treated water with less than 1 part per million (ppm) of iron and 100 ppm of sulfate, resulting in a higher quality product than the common solution of simply diluting and reusing flowback water.
Currently, Winner Water is focused on deploying its system in the Pennsylvania area, where acid runoff presents a serious environmental hazard and water prices of $12-$16/thousand gallons make new technology cost-competitive. However, Ontiveros notes that his technology has multiple uses and has been tested in environments as varied as Norwegian copper mines and U.S. agricultural sites where runoff is common, such as large-scale feeding operations. He notes that Montana has similar industrial synergies and a growing demand for water in energy production.
“If there is an opportunity, we would love to go to Montana,” he said.