H20 consumption for fracking exceeds industry projections Lack of reporting requirements discourages clear picture

Workers pump water from a lake to an impoundment
 for fracking in the Fayetteville Shale in Arkansas.
Photo provided by USGS 

The amount of water needed for hydraulic fracturing, like much information we wish we could count on from the industry, is not well documented and varies case by case. But as shale gas plays ramp up throughout the country, evidence suggests actual quantities tend to exceed projections.

Assessing potential for high volume hydraulic fracturing to stress local water supplies is an elusive task. Lack of centralized and uniform reporting requirements leave reporters and researchers to compile trends from piecemeal and sometimes conflicting sources and extrapolations. Last week Forrest Wilder of the Texas Observer, wrestling with this very problem, reported:

If you want to know how much crude oil was produced in Texas in March, the numbers are available to the barrel (50,087,778). If you need a monthly rig count for the Eagle Ford Shale in South Texas or the number of drilling permits issued in 2012 (4,143), the Texas Railroad Commission can provide that information. But if you want to know how much water was used to frack wells for any time period anywhere in Texas’ shale plays… Well, get out your calculator.

Wilder did just that, focusing on a three-county area—Dimmit, LaSalle and Zavala counties—in the southwestern portion of the shale play between San Antonio and Laredo. It’s a region of scarce rainfall and growing prospects of competition for water between burgeoning shale gas development and agriculture. Wilder found that, depending on the source of information, shale gas water consumption in 2012 ranged between 10,000 and 15,000 acre-feet. It’s a range that suggests, if nothing else, an astounding disconnect between industry projections and realistic values for water use. Based on the Texas Observer analysis, in 2012 shale gas developers in the three county-area used between one third and one half of what the Texas Railroad Commission -- relying on informal and unpublished industry estimates -- projected for the entire 24-county Eagle Ford Shale at its peak 10 years from now.

The Observer analysis was based on records by FrackFocus.org, a site that compiles information submitted voluntarily by “participating oil and gas companies.” In Texas, as with other places, some groundwater authorities require companies using water for fracking to obtain a permit, while others do not. Interpretation of the law “depends on which lawyer you talk to,” Slate Williams told Kate Galbraith of the Texas Tribune. Williams, general manager of the Crockett County Groundwater Conservation District in West Texas, asks drillers to report the amount of water they withdraw. “They don’t always do that, but it’s something we ask,” Williams said.

I came across similar contradictions last year raised by Lisa Wright, a fracking opponent trying to reconcile disparities between information from New York state officials and geologist Geoffrey Thyne. According to New York’s draft policy for shale gas development (the Supplemental Generic Environmental Impact Statement or SGEIS), horizontal shale wells use between 2 million and 7 million gallons each. Thyne is a researcher who worked first at the Colorado School of Mines and later at the University of Wyoming. He lost assignments with both institutions amid controversy over his critique of the industry, and figures he provided for Boulder Weekly reporter Shauna Stephenson that indicate a long gas well used between 48 million and 70 million gallons of fluid –  a calculation that was dismissed by the industry as ridiculous and misleading.

In addition to questions about consumption, Wright wondered why there was so much uncertainty about the amount of waste each well produces.  She cited a Stony Brook University study, published last year in the journal Risk Analysis, that found flowback from a given well ranges from between 10 percent and 80 percent of the volumes injected. (Fresh water that remains in the ground is removed from the eco-system – a status known as “consumptive use.” What comes out is laden with salts, unknown chemical mixtures, metals, and radium. Some of it comes from deep gas baring zones, some if it is injected with fresh water, and all of it is exempt from hazardous waste laws.)

Either end of the flowback range offered by Stony Brook study - 10 percent or 80 percent - poses problems that must be recognized and dealt with. Wells that produce little flowback consume relatively high amounts of fresh water. (They also become, in effect, disposal wells.) Those with high volumes of flowback produce corresponding amounts of polluted water. Wright raises a fair question: “With so many eyes on this issue, and with increasing drought conditions-- how can we NOT know this stuff?”

Looking for some clarity, I checked in with Tony Ingraffea, a Cornell University engineering professor and former hydraulic fracturing consultant for the industry, and Terry Engelder, a geologist and industry consultant from Penn State. Tony sees shale gas development as a net loser when ecological costs are factored, while Terry believes it’s a winner. But both agreed that reliable information on water consumption is hard to get at; that there are many variables that can be manipulated to suit interpretations; and volumes will likely tend to increase over time as technology allows for wells that extend greater distances.

A 70-million-gallon frack job (a prospect raised by Thyne) would be logistically improbable if not impossible in Pennsylvania, Engelder said. He cited an example of a frack job in Bradford County, however, that used 8 million gallons to stimulate a mile-long Chesapeake well in Bradford County, and he acknowledged that wells in the future could extend twice that far, thereby using twice the volume. Ingraffea cited some wells in Michigan extending for miles that will use as much as 23 million gallons each.

“Laterals are getting longer everywhere, because many stages are unproductive, and operators have to justify the drilling expense,” Ingraffea said. “Longer laterals, all else being equal, more frac fluid.”

When industry proponents talk about the need for water to develop shale gas, they often put fracking in the context of other ways we use water, like sprinkling lawns, gardens, or golf courses. (See David Blackman’s recent piece in Forbes as the latest example.) The irrigation comparison, however, fails to recognize that watering a lawn and fracking a gas well are two entirely different things. For starters, water on lawns and golf courses is not forever removed from the eco-system, nor is it reintroduced with an array of hazards.

The industry’s water needs are not merely a concern among liberals and greens. As reported recently by Norimitsu Onishi of the New York Times, competition for water in California is raising tensions between farmers and operators as the drilling industry pushes into fertile farm regions in pursuit of unexplored shale gas reserves. And concerns over water lead community leaders in Mora County, a small town in energy-rich New Mexico, to pass the nation’s first countywide ban on hydraulic fracturing. (Hear report by Carrie Jung of KUNM radio here.)

Engelder agreed that competition for water between agriculture and drilling in Texas and elsewhere will become more of a problem if things don’t change. “I think frackers are going to have to learn to use salt water from the Gulf of Mexico in very short order if they wish to continue,” he said. “Otherwise, get 'em all on wind from west Texas and electric vehicles…  We are going to need all the water we can get for AG.”

Areas not prone to drought also have water conflicts. Pennsylvania Governor Tom Corbett, an ardent drilling supporter and opponent of industry regulation, recently accused the Delaware River Basin Commission of hindering the economy and violating property rights by holding off shale gas development in its ecologically sensitive jurisdiction. The agency monitors the drinking-water supply of more than 15 million people, including Philadelphia and half the population of New York City, and prohibits Marcellus Shale drilling in the basin that covers parts four states - New Jersey, New York, Pennsylvania, and Delaware – as it considers policy.

 If shale gas develops along its current trajectory, the industry will need more water tomorrow than it does today. In short, we will have more wells with longer laterals tapping shale reserves extending under dozens of states, including many areas where drilling is new and unfamiliar. If the current anti-regulatory attitude persists nationwide, the public will have little control over what it cannot see coming. As the industry has fought hard to preserve federal loopholes that exempt it from Safe Drinking Water Act and hazardous waste laws, it’s a safe bet that it will not be eager to provide accessible information on its water consumption habits. It’s the kind of information that invites regional planning initiatives that pro-drillers characterize as a drag on the industry, even if they are vital to long-term community safeguards.