HOUSTON — Hydraulic fracturing is competing for water in some of the driest regions of the U.S., including the Eagle Ford Shale in South Texas, according to a research paper released today by the nonprofit Ceres.
The report said that the Eagle Ford had the highest water use of any region in the country — 19.2 billion gallons — in an 18-month period and faces some of the biggest water challenges of any shale field in North America. South Texas operators used an average of 4.5 million gallons to fracture each well, according to the report.
It found that 98 percent of the Eagle Ford wells were in areas of medium or high water stress, with 28 percent in areas of high or extreme water stress.
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Ceres also found that 70 percent of the wells in the Permian Basin in West Texas are in areas of extreme water stress — and water use in both that field and the Eagle Ford is expected to double in the next decade.
But the water stress isn’t limited to Texas.
More than 55 percent of the wells fractured during an 18-month period in North America were in areas experiencing drought.
“This model cannot continue indefinitely,” said Monika Freyman, report author and senior manager in the Ceres water program. “The financial community needs to be aware of these potentially material risks.”
Not only do companies and investors need to be concerned about water sourcing, but on whether operators can maintain enough goodwill in communities — the social license to operate, she said.
Ceres, an investor group that focuses on sustainability issues, looked at water-use data from 39,294 oil and shale gas wells that was reported to FracFocus.org from January 2011 through May 2013 and overlaid it with water stress indicator maps developed by the World Resources Institute.
“Water use for hydraulic fracturing can be a small percentage statewide, 1 or 2 percent,” Freyman said. But “the local use at the county level can be very large, sometimes equivalent to all the water use by all of the residents. It can be very stressful if you look at that scale.”
Ceres looked at eight key shale energy regions, including in Texas, Colorado, North Dakota, California, Pennsylvania and Western Canada. And it considered water use by 250 shale energy operators and service providers to identify the companies most exposed to water risks, as well as counties most at risk.
Water always has been needed for oil and gas drilling, but not in this quantity.
Hydraulic fracturing pumps a mix of water and chemicals at high pressure to break the shale. Then sand is added to the fluid in increasing amounts to hold open the fissures, letting oil and gas flow up the well to the surface.
Amanda Brock, CEO of Houston-based Water Standard, a water treatment firm, called the energy industry a “new user in an already stressed system.”
“Texas is ground zero in the debate,” Brock said. “If we keep on the growth curve we are on in the dry Eagle Ford, in 2015 it will be the largest stand-alone energy project in the world.”
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Oil and gas companies have to get rid of water that returns after hydraulic fracturing, called flowback water, and the water that comes out the rock itself — production water.
While recycling and reuse are on the increase, often the wastewater gets trucked to a disposal well, where it’s pumped underground far below freshwater aquifers.
“Recycling is something we could advocate for,” Freyman said. “It’s not the silver bullet.”
Water recycling is on the increase in the Northeast — a region with more abundant rainfall than Texas — because there’s a lack of deep well injection sites in that region. But recycling isn’t the norm in Texas, and Ceres advocates moving away from disposal wells.
“It drives the economic model away from recycling,” Freyman said. “It also works against maintaining the social license to operate. There’s growing concerns around the risks of deep well injection sites.”
Steven Heim, managing director and director of ESG research and shareholder engagement at Boston Common Asset Management, said the industry is doing a lot of work to reduce the use of freshwater resources, but that it’s hard to come by anything but anecdotal evidence. “Investors are not getting enough information from companies to assess their risks,” Heim said.
He said that in Horn River Basin of Canada, Encana Corp. and Apache Corp. have a joint water treatment plant for brackish water, which they use as a prime source for fracturing.
Apache Corp. also has been able to eliminate freshwater use in some of its Permian Basin operations.
“Apache is recycling significant quantities of water,” Brock said. “If Apache can do this, how can we persuade other operators to do the same?”
A recent Express-News investigation found that hydraulic fracturing used more than 14 billion gallons of water in the Eagle Ford in 2012. That number far outpaced estimates of what water use in the Eagle Ford might have peaked at some time in the next decade.
A widely cited University of Texas at Austin study, funded by the oil and gas industry, had predicted hydraulic fracturing in the Eagle Ford would use a maximum of around 35,000 acre-feet of water annually.
But the newspaper looked at more than 23,000 Texas wells drilled from 2011 to 2013, including more than 6,100 in the Eagle Ford, and found that the oil field already was swallowing more water than peak forecasts predicted.
Operators reported using around 43,770 acre-feet in 2012 in 3,522 Eagle Ford wells, the approximate annual usage for 153,000 San Antonio households.
In the Winter Garden region, dozens of artesian springs once flowed and inspired lush community names such as Artesia Wells, Carrizo Springs and Big Wells. But the water table already has been dropping for the last 100 years because of agricultural use.
And fracturing in Dimmit, La Salle and Zavala counties, which make up the Wintergarden water conservation district, takes more water than the average Eagle Ford well — around 5.6 million gallons per well in 2013, up from 5.5 million gallons in 2012, according to the newspaper’s analysis.
Water use is a complex issue. Irrigation takes the lion’s share of the state’s water — about 61 percent of the state’s water demand, according to the Texas Water Development Board, followed by municipal use. By comparison, water use for mining operations, including hydraulic fracturing, is a small slice of the state’s water use — around 1 percent, less than is used to keep yards green.
But the Ceres report notes that water use and sourcing are local issues, and the water use for fracturing in some areas is like the straw that broke the camel’s back.
“Agriculture hands down wins in water use across the country,” Freyman said. “It’s not like shale energy development and hydraulic fracturing are causing everything. They’re the latest party to come to the table.”
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