Photo Courtesy Alberta Surface Rights Group:  Blowout caused by fracking near Innisfail Alberta.

By Mark Lowey

          The hydraulic fracturing process now used to extract shale gas is very different than the ‘fracking’ done for the past six decades and has much greater environmental impacts, says a Cornell University researcher.
           There are four widespread “myths” about current ‘fracking’ technologies that industry often cites and many media outlets propagate, said Anthony Ingraffea, a professor of civil and environmental engineering at Cornell’s School of Civil and Environmental Engineering.
           The fact is that there hasn’t been sufficient time to scientifically assess the potential risks and impacts from fracking operations now occurring in western Canada and in several U.S. states with shale gas deposits, Ingraffea said in a December 2012 talk at the University of Calgary.
           “A lot of good science should have been started four years ago” to study the impacts of fracking and of increased natural gas production and use, said Ingraffea, a licensed professional engineer in the state of New York.
           “Since when does policy (to allow fracking of shale gas formations) come before scientific understanding?” he asked his Calgary audience.
           For a different view than Ingraffea’s of shale gas development and hydraulic fracturing, along with links to other information resources, see the Canadian Association of Petroleum Producers’ website (http://www.capp.ca/canadaIndustry/naturalGas/ShaleGas/Pages/default.aspx).
           Ingraffea, in a talk presented by the Department of Chemical & Petroleum Engineering in the U of Calgary’s Schulich School of Engineering, said that most of the data he’d be presenting come from industry and government regulators’ reports.
           The first commercial use of fracking occurred in 1947, he said.
           Myth No. 1 is that the hydraulic fracking of the last few years is no different than the fracking of the last six decades, he said.
           Fracking today utilizes relatively new technologies such as directional drilling, “slick water hydrofracking” (involving high volumes of fluids), multi-well pads and cluster drilling.
          A typical shale gas well requires 20 million litres of frac fluids to “prop open” the rock formation ‘joints’ and enable the gas to flow to production wells, Ingraffea said.
          Gas-producing shale formations are already heavily fractured naturally, he noted. So the industry is essentially “re-fracking” already fractured rock.
          Typically, companies use 10,000 to 20,000 horsepower to pump frac fluids into shale, which means pumping “a hell of a lot of fluid at high pressures a long way” into the reservoir – typically one to three kilometres underground.
           He showed a slide of shale gas wells drilled on the Dallas-Fort Worth airport property. The well pattern, resembling a pin cushion, includes a well pad on every two miles (3.2 km) by one mile (1.6 km) piece of land.
           The use of multi-well pads and cluster drilling started only in 2007, Ingraffea said.
          This means that the more than 75 companies that have drilled thousands of shale gas wells in Pennsylvania since 2007 all have only a few years’ experience, at best, with today’s type of fracking operation, he added.
          “It’s not the kind of fracking we’ve seen anywhere, at least for the last five years.”
          Myth No. 2 is that hydraulic fracturing and the technologies associated with it reduce surface impacts on the land compared with conventional drilling, Ingraffea said.
          How, he asked his audience, do multi-well pads and cluster drilling reduce surface impacts “in a place where it (hydraulic fracturing) has never been done before?”
          A typical multi-well pad requires, on the surface, additional infrastructure such as retention ‘ponds’ or wastewater pits for frac fluids, compressor stations and pipelines.
          Such infrastructure has been built close to rural homes in Pennsylvania, he said, showing a couple of slides with frac fluids ponds and other infrastructure located nearly within a stone’s throw of houses.
          “What was their backyard is now an industrial site,” Ingraffea said, noting that there are no required setback distances in Pennsylvania to separate homes from frac fluid wastewater pits.
          One of his slides showed a frac fluid wastewater pit that had been carved from a mountain top in a state park in Pennsylvania.
          Industry has so far drilled about 6,500 wells out of a planned 150,000 wells into the Marcellus shale gas formation underlying Pennsylvania, he said, adding “they’ve barely started yet” in terms of industrializing the area.
          Rather than reduce surface impacts, today’s 24-7 fracking operations and their use of multi-well pads and cluster drilling actually “facilitates and prolongs intensive industrialization and leaves a longer, long-term footprint” than conventional oil and gas drilling, he said. (See http://www.chesapeake.org/stac/presentations/208_Ingraffea%20Part%201.pdf).
          Myth No. 3 about fracking, Ingraffea said, is that fluid ‘migration’ – or leaks – from faulty wells is rare.
          He showed a brief video of methane gas bubbling as it escaped at a wellhead.
          A 2003 article by Claudio Brufatto and others in Oilfield Review, a Schlumberger publication, reported that newly drilled wells have a five per cent failure rate and leak immediately “right out of the box,” he said. (See http://www.slb.com/~/media/Files/resources/oilfield_review/ors03/aut03/p62_76.ashx).
          “Since the earliest gas wells, uncontrolled migration of hydrocarbons to the surface has challenged the oil and gas industry,” according to the article.
          A 2009 study by Theresa Watson and Stefan Bachu, published in the Society of Petroleum Engineers Drilling & Completion journal, that examined hundreds of thousands of wells in Alberta, found that about five per cent of them were leaking, Ingraffea said.
          “Deviated” wells – those drilled with directional drilling techniques – were leaking at a much higher rate. (See http://www.ieaghg.org/docs/WBI3Presentations/SBachuTWatson.pdf).
          Ingraffea referred to data available from the state of Pennsylvania’s regulatory database, consisting of inspection reports of all wells drilled into the Marcellus shale from “day one.”
          Based on more than 16,000 inspection reports during the last four years, the data show that the leak rate for newly drilled wells is about six to seven per cent. Although inspectors’ comments reported that some companies that drilled some wells that were “leaking like a sieve,”  never received a violation, Ingraffea said. (See http://www.depreportingservices.state.pa.us/ReportServer/Pages/ReportViewer.aspx?/Oil_Gas/OG_Compliance).
          With a total of 150,000 to 200,000 wells planned to be drilled into the entire Marcellus shale in the U.S. (in Pennsylvania, West Virginia and New York), even if only five per cent of them are leaking, or 7,500 to 10,000 wells, “that’s a hell of a lot of leaking wells,” he added.
          Leaking wells have the potential to contaminate underground drinking water aquifers, and every well leaking at the surface also is emitting hydrocarbons into the atmosphere, Ingraffea said.
          The estimate of five to seven per cent of shale gas wells leaking is a conservative number, because these are only the wells that inspectors observed leaking at the wellhead, he noted. And the failure rate of wells increases as they get older.
          In addition, there have been about one dozen reported incidents in Pennsylvania of methane from leaking wells bubbling into streams and rivers.
          “Fluid migration from faulty wells is a well-known, chronic program with an expected rate of occurrence,” Ingraffea said.
          Industry could do a lot better in drilling and completing such wells in the first place, he added.
          While some companies use state-of-the-art 3D seismic technology and recycle frac fluids, some don’t.    In Pennsylvania, companies recycled only 38 per cent of frac fluids in 2011, according to the state’s regulatory data.
          Despite known gas well failure rates and documented leaks, there is no requirement for baseline information to be gathered on water wells in Pennsylvania, Ingraffea noted.
          The U.S. Environmental Protection Agency, after testing groundwater near Pavillion, Wyoming, in 2011, said that chemical contaminants found in the water were linked to hydraulic fracturing in the gas field by Calgary-based Encana Corp.
          The EPA retested the groundwater in 2012, with similar results. (For more information, including the EPA’s draft report, see http://www.epa.gov/region8/superfund/wy/pavillion/).
          However, Encana strongly denied that its operations had contaminated the groundwater.  Encana said that the EPA drilled into a natural gas reservoir, which is why the agency found methane in the groundwater, and that the EPA’s tests and the agency’s interpretation of those tests were flawed.
          In Alberta, an oil and gas regulatory committee that investigated a well blowout near Innisfail in January 2011 concluded that the blowout of frac fluids to the surface was caused by fracking a neighbouring well.
          The committee also found 21 examples of “communication” between wells in 2011 – five of which resulted in releases to the surface, according to a December 13, 2012 story in the Calgary Herald.
          In December 2012, the Energy Resources Conservation Board (ERCB) released a draft directive aimed at addressing sub-surface issues related to hydraulic fracturing, and invited comment on the directive until the end of March 2013.
          Hydraulic fracturing has been used to stimulate about 171,000 wells in Alberta since the technology was first introduced in the 1950s – 5,000 of those since 2008.
          The ERCB said its regulations strictly limit the depth of shallow fracturing, the distances to water wells and the fracture volumes that can be used, and specify the use of non-toxic fracture fluids to ensure groundwater is protected.
          The ERCB, following British Columbia’s lead, said and will post publicly available reports on the FracFocus website (http://www.fracfocus.ca/) on what chemicals have been used in fracking wells in Alberta.
          The Canadian Association of Petroleum Producers recently issued voluntary fracking guidelines for producers across Canada that recommend the use of additives with the least environmental risks, protection of groundwater and disclosure of fracking fluid additives.

Is Natural Gas a “Clean” Fossil Fuel?

          Myth No. 4 that industry often refers to is that natural gas is a “clean fossil fuel,” Ingraffea said.
          Levels of the global warming gas carbon dioxide in Earth’s atmosphere are now at about 390 parts per million (ppm) and are increasing at two ppm per year, he noted.
          Many climate scientists say that concentrations of 450 ppm CO2 represent a “tipping point” that may be catastrophic for the planet’s climate, he said.
          So with annual increases of 2 ppm of CO2 accumulating in the atmosphere, that leaves only 30 years before concentrations reach 450 ppm. “We don’t have 100 years to fix the problem.”
          Compared with CO2, methane or natural gas is 33 times more potent a greenhouse gas in trapping heat in the atmosphere over 100 years, and 105 times more potent over 20 years, Ingraffea said.
          Natural gas systems produced about 29 per cent of total methane emissions in the U.S. in 2009, according to the U.S. Environmental Protection Agency.
          Each one per cent of leakage from a gas well over its production lifetime has the same climate impact as would happen from burning this methane twice (for example, in a gas-fired power plant), Ingraffea said.
          Methane is vented and leaked in several stages of well drilling and production, as well as during unloading of liquids and from distribution lines, he added.
          He showed a slide based on research done by geography professor Nathan Phillips at Boston University that looked at the methane flux in the atmosphere from leaking gas-distribution lines under the City of Boston. (See http://www.bu.edu/energy/research/technologies-engineered-systems/methane-emissions/).
          Phillips’s study found that up to five per cent of the total gas carried by the city’s gas-distribution system is leaking.
          The standard operating procedure in major U.S. cities is to allow for five per cent leakage of the distributed gas, Ingraffea said.
          Ingraffea and Robert Howarth, a professor of ecology and environmental biology at Cornell University, co-authored a study of the methane ‘footprint’ resulting from shale gas extraction and production.
          Their study found that shale gas’s “climate footprint” is larger than that for conventional oil and coal, because of the methane vented and leaked during shale gas extraction, production and distribution.
          “Compared to coal, the (climate) footprint of shale gas is at least 20% greater and perhaps more than twice as great on the 20-year horizon and is comparable when compared over 100 years,” their study said. (See http://www.eeb.cornell.edu/howarth/Marcellus.html).
          “It’s not like burning natural gas or producing natural gas is much cleaner” than coal or oil, Ingraffea told his Calgary audience. “It’s about the same” in terms of climate impact.
          However, separate research led by Lawrence Cathles, a professor of earth and atmospheric sciences at Cornell University, found that the Howarth-Ingraffea study relied on unrealistic assumptions of emissions and improper timing intervals to determine climate-warming potential. (See http://www.energyindepth.org/wp-content/uploads/2012/07/Cathles-Assessing-greenhouse-impact-natgas-June2012.pdf).
          Another separate report, by the U.S. Department of Energy’s National Energy Technology Laboratory, found that the global warming potential of “fugitive” methane released during the life cycle of gas from extraction to combustion is half of coal measured over both 20-year and 100-year periods. (See http://www.energyindepth.org/cornell-response-to-cornell-none-of-these-conclusions-are-warranted/).
          Ingraffea acknowledged to his Calgary audience that he and Howarth did make a lot of assumptions in their study because of a lack of reliable data available. But the science behind the study is sound, Ingraffea insisted.
          In an interview with Calgary journalist  , Andrew Nikiforuk, who wrote a series of stories for The Tyee based on Ingraffea’s research, Ingraffea said that he supports a reduction in fossil fuel usage and a moratorium on shale gas production, combined with focused investments in renewable energies, including geothermal, wind and solar. (See http://thetyeee.ca/News/2013/01/10/How-Clean-Is-Shale-Gas/). 
          At the end of 2012, the U.S. Environmental Protection Agency launched a long-term study on whether fracking pollutes groundwater. But that study’s conclusions won’t be available until 2014.
          However, a 2012 paper by Roberto Aguilera from the University of Calgary’s Schulich School of Engineering and Ronald Ripple from Curtin University in Australia, concluded that “A significant volume of data indicates that the probabilities of hydraulic fracturing fluids and/or methane contaminating groundwater through the hydraulically-created fractures are very low.”
          There is enough natural gas to supply the energy market for nearly 400 years at current rates of consumption and 110 years’ supply with a growth rate in production of 2 two cent per year, they said in their paper, presented at the SPE Canadian Unconventional Resources Conference, Oct. 30 to Nov. 1, 2012, in Calgary. (See http://www.onepetro.org/mslib/servlet/onepetropreview?id=SPE-162717-MS),
          “With appropriate regulation, this may be done safely, commercially, and in a manner that is more benign to the environment as compared with other fossil fuels,” Aguilera and Ripple said. EnviroLine