by Sue Smith-Heavenrich
When you talk about hydraulic fracturing, you’re not just talking about “fracking,” says Tony Ingraffea. You’re not just talking about Marcellus shale, either, he told nearly 400 people in Cortland recently. Ingraffea should know.
Not only is he the Dwight C. Baum Professor of Engineering at Cornell University’s School of Civil and Environmental Engineering, but he also directs the Cornell Fracture Group. And he received his doctorate in rock fracturing.
Earlier in his career, Ingraffea conducted research in aerospace engineering. “Now, 30 years later,” he jokes, “I’m back to looking at fractures in rocks.” Over the past year Ingraffea has visited a number of communities to share his knowledge about geology, fractures and engineering aspects of gas wells.
Unconventional wells are nothing like earlier gas wells in New York, Ingraffea says. He estimates that there are about 50,000conventional wells in the state, each drilled with one well to the pad, each using about 80,000 gallons of fluids to fracture rock and release gas trapped in the formation.
Unconventional wells in Pennsylvania currently have 8 wells per pad, Ingraffea says, with each of those wells up to 10 frack-stages in length. That means that a single well pad will use about 44 million gallons of fracking fluid.
When you consider a single well, this doesn’t seem like so much. But, Ingraffea says, according to Pennsylvania State University geologist Terry Engelder, there will likely be 36,000 to 78,000 wells drilled in the Marcellus shale. “And that’s not including Utica and other shale formations,” Ingraffea notes.
With up to 10 fracks per well, that’s 360,000 to 780,000 frack stages. Each of those frack stages uses close to 500,000 gallons of fluid, Ingraffea said. “The first 1,000 gas wells unconventionally developed in New York will use more frack fluid, and produce more waste, than all the gas wells ever drilled in the state.”
This is a scale at least two magnitudes larger than we have ever experienced, Ingraffea explains. “And right now we have no regulations guiding shale gas development.”
New York’s Department of Environmental Conservation isn’t the only agency seeking to guide development of “fracking”—the U.S. Environmental Protection Agency (EPA) has also embarked on a review of the process. And it has asked him to help provide answers at a technical workshop.
The workshop, he says, provided the perfect opportunity to point out the gaps in knowledge that the EPA should address in its fracking study.
The EPA should require the gas industry to produce data on the number of cement jobs in high-volume slickwater fracked wells that fail, Ingraffea says. “That goes right to the point of risk.” Cement failure has been a chronic problem, and the industry is not sharing the failure numbers with regulatory agencies.
“It’s a complex job in horizontal wells, many with horizontal bores running up to three miles long,” Ingraffea points out. Those bores are fracked in 500-foot sections. “Each time you re-pressurize the well bore for a frack job, it puts the cement at risk,” says Ingraffea. The industry already knows frequently stressed cement has a higher failure rate.
Ingraffea would like to see regulations require cement logs. After completing a cement job, drillers lower a device into the well bore that sends images of the cement. That way drillers should catch tiny cracks that might allow gas migration, Ingraffea explains. “But it doesn’t take much dis-bonding between the cement and the casing to provide a pathway for methane molecules.”
Tens of thousands of slickwater hydraulically fractured wells have been drilled into Barnett shale and Fayetteville shale and now Marcellus shale, Ingraffea pointed out. The EPA needs to demand data on cement reliability of these wells, not vertical wells drilled a decade or more ago.
Ingraffea also wants the EPA to get clear data on the cumulative impact of intensive drilling on other wells nearby. Pennsylvania drillers estimate that they’ll be putting in 8 to 12 wells on a pad, with the vertical well bores spaced about 20 feet apart. “What happens to the first well when the second is drilled?” asks Ingraffea. “Do the vibrations damage the cement?”
The problem with articles in professional journals is that they always focus on impacts to a single well. “But we’re talking about unconventional drilling in shale,” Ingraffea said. “We have a four-dimensional problem.” That fourth dimension is timing.
Already, drillers in British Columbia have reported that wells drilled as far as 350 feet from each other can send lateral fractures into neighboring wells. Ingraffea wants to know whether waiting a year or two between drilling wells on the same pad will affect casing integrity.
Another problem is aging. Over the years cement shrinks and cracks, and casings corrode, says Ingraffea. This raises a number of questions about well integrity during re-fracking.
As for frack fluid migration, Ingraffea wants the EPA to ask the gas industry for their best computer models that show how long it takes for fracking fluids to migrate upwards. “We’re not going to have a single well,” he said. “EPA needs a realistic model that gauges cumulative impact. If they’re not looking at it that way, then they’re missing the point.”
Sue Smith-Heavenrich is a freelance writer and member of the Society of Environmental Journalists. She lives in Candor and posts short articles on drilling news at http://marcelluseffect.blogspot.com.