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Environment

Measuring Methane Lost During Fracking

University of Texas study finds low greenhouse gas emissions from hydraulic fracturing

by Jeff Johnson
September 30, 2013 | A version of this story appeared in Volume 91, Issue 39

UNDER INVESTIGATION
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Credit: iStockphoto
Independent researchers for the first time were able to take measurements at various company well sites.
Photo shows a well drilling rig working in the eastern plains of Colorado to reach the Niobrara Shale formation. Once the well is drilled and perforated, water, sand and chemicals will be injected under high pressure to fracture the shale, releasing oil and gas.
Credit: iStockphoto
Independent researchers for the first time were able to take measurements at various company well sites.

The first peer-reviewed study based on direct measurements of methane emissions at hydraulic fracturing sites finds that the amounts of methane lost during drilling and natural gas production are far lower than indicated in previous studies. Furthermore, these levels are unlikely to trigger significant greenhouse gas concerns.

The well-site-specific examination, led by researchers at the University of Texas, Austin, found methane emissions to be 0.42% of a well site’s gross natural gas production (Proc. Natl. Acad. Sci. USA 2013, DOI: 10.1073/pnas.1304880110). That figure is lower than the Environmental Protection Agency’s most recent estimate of 0.47% of production and far below National Oceanic & Atmospheric Administration research that pegged the losses at 6–12%. The levels reported by NOAA would cause significant climate-change impacts.

Methane loss is important and controversial. Methane, the primary component in natural gas, is a powerful greenhouse gas—21 times as potent as carbon dioxide at trapping radiation over 100 years and 72 times as powerful as CO2 in its first 20 years in the atmosphere.

The new study, however, is unlikely to end controversy over hydraulic fracturing, or fracking, of shale gas well sites and methane emissions lost during natural gas production. It was immediately challenged, particularly because of the small sample size—190 sites—and industry control over which sites were measured. Still, critics applauded the technical quality of the research and urged that more companies open their drill sites to independent researchers.

The methane examination comes as drilling activity explodes and both the chemical industry and electric utilities mount plans to take advantage of the new gas abundance triggered by fracking.

The UT report notes some 8,000 fracking wells were completed and began production in 2011. Some half-million natural gas wells were operating in the U.S. that year, and 36,000 fracturing operations were modified to increase production. About 30% of natural gas output is now a result of fracturing of shale formations, and this percentage is expected to exceed 50% by 2040.

The rush to gas is of great benefit to the chemical industry. As of March, nearly 100 chemical investment projects that capitalize on fracking had been announced, at a total construction cost of $71.7 billion. By 2020, the new plants are expected to have created 500,000 new jobs and be producing chemicals worth some $66.8 billion per year.

For electric utilities, natural gas is on track to replace coal as the fossil fuel of choice for electricity production. The switch is driven by natural gas’s new abundance, its declining price, and gas’s environmental advantage of producing half the CO2 emissions of coal when burned for fuel.

However, the environmental advantage for utilities disappears if more than 1% of methane is lost to the atmosphere during natural gas production, according to environmental research groups.

Although the exact amount of methane lost is critical, until this study, independent researchers were not allowed to make direct measurements at company well sites. Instead, industry brought in its own researchers, who found little loss. Recent studies by NOAA found high methane emissions but were based on air measurements taken by aircraft above production fields.

The UT study broke new ground when nine drilling companies and the Environmental Defense Fund, an environmental group, sponsored a plan in which the companies provided access to their well sites. However, the companies selected the sites and the times measurement would be taken.

Last year, David T. Allen, a UT chemical engineering professor, and his research team visited some 190 U.S. hydraulic fracturing sites that housed 489 wells.

Much of their attention focused on emissions from “well completion flowbacks,” according to the report, when millions of gallons of water, sand, and additives forced into shale return to the surface along with the flood of natural gas after shale has been fractured. This operation was widely expected to release the highest levels of methane.

The study found otherwise. But it examined only 27 flowback operations out of some 8,000 conducted annually. It acknowledged that the 27 sites use advanced equipment, so-called green completions, or flaring to eliminate methane emissions. As a result, emissions from those flowback operations were observed to be insignificant.

The much lower than expected flowback emissions, Allen says in a statement accompanying the report, show control equipment is very effective. He adds that fracturing technologies are “evolving.”

EPA has urged drillers to use such equipment, but industry has complained about the cost and availability. Beyond these 27 operations, it is unclear how many such devices are deployed in the U.S.

Allen says his team will collect additional well-specific data beginning this month and explore other equipment leaks for a future report.

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