Methane in drinking water unrelated to fracking, study suggests by Eric Hand, March 30, 2015, news.sciencemag
Fracking doesn’t appear to be allowing methane to seriously [What’s the definition of “seriously contaminate water with methane?” Make you blow up in your home and kill all your 5 children, 3 of them, 2, just you?] contaminate drinking water in Pennsylvania, a new study finds—contrary to some earlier, much publicized research that suggested a stronger link. But the lead authors of the two bodies of research are sparring over the validity of the new results.
The new study of 11,309 drinking water wells [data collected after years of methane migration from thousands of leaking energy wells, perfs and fracs?] in northeastern Pennsylvania concludes that [after massive industry pollution] background levels of methane in the water are unrelated to the location of hundreds of oil and gas wells that tap hydraulically fractured, or fracked, rock formations. The finding suggests that fracking operations are not significantly [Chesapeake defining that?] contributing to the leakage of methane from deep rock formations, where oil and gas are extracted, up to the shallower aquifers where well water is drawn.
The result also calls into question prominent studies in 2011 and 2013 that did find a correlation in a nearby part of Pennsylvania. There, wells closer to fracking sites had higher levels of methane. Those studies, however, were based on just 60 and 141 domestic well samples, respectively.
“I would argue that [more than] 10,000 data points really tell a better story,” says hydrogeologist Donald Siegel of Syracuse University in New York, whose team published the new study online this month in Environmental Science & Technology. Chesapeake Energy Corp., which has large oil and gas stakes in Pennsylvania, supplied the researchers with the database, the largest of its kind, and also funded the work.
… But Siegel says that all of these fears are overblown. [Does he live frac’d with his loved ones? Does he have to haul water? ] His study found natural backgrounds of methane in well water, but no trend related to the proximity of 661 oil and gas wells. “We found plenty of methane—and that’s the whole point,” he says, referring to natural sources of the gas.
Siegel doesn’t deny that there have been problems with a few wells with poorly engineered steel casings or cracked and degraded cement walls designed to keep the boreholes from leaking. Such defective borehole walls can provide a conduit for the methane to move from the shale formation, more than a kilometer underground, to water wells just a hundred meters or so below the surface. But he says his study shows that it is an exceedingly rare issue. “We haven’t seen any evidence [of methane migration] other than the occasional local issue,” he says. “I think our paper, in my view [He means in Chesapeake’s view?], pretty much seals the deal.”
Siegel believes the PNAS studies, led by Robert Jackson, a hydrogeologist at Stanford University in Palo Alto, California, painted a more worrisome picture because their small sample set was skewed toward locations with known well-casing issues. “I’ve always felt that the Jackson group studies have been highly flawed,” Siegel says.
Jackson, however, contests that characterization and argues that Siegel’s larger sample size doesn’t necessarily make for a better study. He says it is unclear whether the Chesapeake samples were measured at the water well itself, or inside houses, after the water may have had time to release its methane fumes, or after it has passed through purification systems. He also points out that the water samples were collected using the “inverted bottle” technique, a method avoided by many academic labs because it can lead to lower measured values of methane in samples with the highest levels of the gas, because it allows the methane to percolate out of solution. [Ah ha! The old Alberta Model sampling methodology! Run! Run dangerous, life threatening, billion dollar liability! Run Run!] “They’ve introduced a whole series of methods that introduced noise into the data set,” Jackson says. He adds that, in a trip to Chesapeake headquarters in Oklahoma in 2011, he offered to collaborate with the company using the large data set but was rebuffed.
Bert Smith, a co-author on the new study and a former employee of Chesapeake [too funny!] who now works as a consultant, says he initially approached the U.S. Geological Survey with the company’s data set, but the agency declined. [Now why was that? Did the USGS know the data set is crooked?] He then asked Siegel to collaborate on the study.
For all their disagreements, scientists on both sides of the fracking debate agree that it is very unlikely that microfracturing of rock formation itself contributes to the vertical migration of gases. The problem, they say, is with a minority of badly cased or cemented wells—they just disagree on how often this occurs. Siegel cites a 2014 study that found that just 0.24% of the thousands of wells in northeast Pennsylvania were ever given violation notices related to the migration of methane into groundwater. But Anthony Ingraffea, a civil engineer at Cornell University who is alarmed by the risks of fracking, says those violation notices are just the tip of the iceberg. He points to a study he led, published in PNAS in 2014, which found that 9% of unconventional wells drilled in northeast Pennsylvania since 2009 already have structural integrity issues. That problem will grow, he says, as wells age, and as tens of thousands of new wells are bored. “We’re just at the beginning,” Ingraffea says.
Siegel says he plans to publish three more studies using the Chesapeake data. One will examine the connections between background methane and the hydrogeological setting, and another will look at other chemical constituents in ground water. A third will take a focused look at how methane levels vary over time in 12 homes in which water wells were instrumented and monitored around the clock for 1 to 2 years. [Emphasis added]
[Refer also to:
An Alberta government lawyer argued in court this week that Jessica Ernst’s lawsuit on hydraulic fracturing and groundwater contamination should be struck down on the grounds that it would open a floodgate of litigation against the province.
“There could be millions or billions of dollars worth of damages,” argued Crown counsel Neil Boyle.
New research is raising concern about tens of thousands of dormant Alberta oil wells that don’t meet even minimum safety standards.
The Alberta Energy Regulator has begun a program that it says will result in all wells meeting those minimums within five years. [How many aquifers, municipal drinking water supplies and private water wells will be contaminated by then?]
But critics say those standards amount to little more than a locked gate and a few signs. They want firm timelines to force companies to clean up old well sites — some of which have been sitting unused for decades — before the liability winds up with taxpayers. [Too late!] “Unless timely action is taken to ensure that oil companies deal with their liabilities while they still have the financial capability to do so, the reality will be that either the taxpayer is going to be on the hook or the landowner will be stuck with the problem,” said Keith Wilson, a lawyer who has represented hundreds of landowners against the energy industry.
Since 2007, inactive wells in Alberta must be fenced, locked, signed and tested to ensure they don’t leak. For most “suspended” wells, no cleanup is required. But in the report, Barry Robinson of the environmental law group Ecojustice points to recent figures from the regulator that acknowledge 37,000 inactive wells in Alberta don’t meet those minimum standards. Of those, at least 3,300 also have wellbore integrity problems.
Alberta has 80,000 inactive wells in total, a number that is increasing as the pace of abandonment outstrips that of reclamation. [And how Albertans vote]
Worse, said Robinson, regulations designed to allow operators to bring wells into and out of production as markets require are being used to mothball wells for years and even decades without having to spend the money to clean them up. [Best in the world!]
“They can keep the well inactive as long as they want. The longer a well sits inactive the more the likelihood that you could have some sort of wellbore issue. “Some of these wells have sat for 15 or 20 years.”
Besides the environmental risk, the suspended wells are also a risk for landowners. “The banks want protection that you’re not going to get nailed with a million-dollar cleanup when you buy a property,” said Don Bester of the Alberta Surface Rights Association, which advocates for landowners. “Same as the seller — he has to do an environmental assessment to provide to the buyer.
“If I’ve got a contaminated site on my place, where do you think the buyers are going to run to? Completely away.”
Under the regulator’s new program, operators have to bring [only] 20 per cent of their non-compliant wells up to snuff annually. Many of those wells are non-compliant because the operator hasn’t done the paperwork, said David Hardie, the regulator’s senior adviser on closure and liabilities. … The program is to be strongly enforced by inspectors in the field. But it won’t move wells along from suspended to abandoned to fully reclaimed.
“It’s not within the AER’s regulatory authority to create timelines for that,” [Of course not! CAPP and companies would never allow it!] said Anita Lewis, also a closure and liabilities adviser. “That actually falls under government policy perspective.”
Alberta Environment spokesman Jason Maloney said the government will consider such timelines as part of policy reviews planned in 2015. “We’re working with stakeholders,” he said. “That will be explored.”
Discussions will include industry, non-governmental groups, academics, First Nations and municipalities, he said. [Why exclude landowners? Because they bear the liability, fumes and explosive risks?]
Other jurisdictions force operators to clean up a well after a certain period of inactivity, said Robinson. In Colorado, a well can only be suspended for a maximum of six months. After that, an operator must explain why an extension is necessary. Unless special circumstances apply, a well must be fully remediated with 18 months after becoming inactive. Colorado’s ratio of active to inactive wells is 18 to one. In Alberta, the ratio is three to one.
Wilson said Alberta’s current rules only postpone the inevitable — perhaps until it’s too late.
“You have to clean these wells up while the cash is available in the oil companies to do so,” he said. “If they pay out all of their value in dividends and disposing of assets to shareholders without first cleaning up their liabilities, then who’s going to be left to deal with the liability?” [Emphasis added]