By Smithsonian, an Energy Realities Partner
Coal mine methane could soon transform from problematic waste to valuable fuel.
In a Colorado valley where miners have harvested coal for more than a century, a second fuel—methane—escapes from the thick black seams of the Elk Creek mine. A system of boreholes and pipes around the mine funnels methane-rich gas to a modified truck engine. Using a trio of one-megawatt generators, the engine converts this methane to electricity for the local power grid.
Elk Creek is the first methane-to-energy project at a coal mine west of the Mississippi and the largest of its kind nationwide. But coal mines like Elk Creek contribute about 10 percent of methane emissions nationally and 6 percent of methane emissions worldwide, and they continue to release methane long after mining operations have ended. The gas also seeps from swamps, industrial flues, landfills, cattle farms and natural gas operations.
In fact, so much methane enters Earth’s atmosphere each year that globally it is the second largest contributor to climate change after carbon dioxide. Methane dissipates more quickly than carbon, but its strength as a greenhouse gas over a 100-year period is more than 20 times that of CO2.
Burning methane can generate energy or useful heat while lessening its climate impact—essentially reducing the gas to a weaker brew of water and carbon dioxide. At Elk Creek, burning just over 670,000 cubic feet of methane per day—roughly 16 percent of the mine’s total methane emissions—in an internal combustion engine is expected to generate 24 gigawatt hours annually. That’s enough electricity to power roughly 2,000 homes.
By stopping methane from entering the atmosphere, the project will prevent emissions equivalent to more than 96,500 metric tons of CO2 annually over the next 15 years, according to estimates from its main funder, Aspen Skiing Company. That is about 10 days’ worth of carbon emissions from a typical coal-fired power plant—not enough to make a meaningful dent in global emissions of greenhouse gases, but an important step toward transforming methane from a problematic waste to a valuable fuel.
A combination of policy changes, creative new partnerships and technology innovation now means Elk Creek could be leading a much larger wave of similar projects harvesting methane from coal mines.
Historically, the owners of mines like Elk Creek in the U.S. have had little incentive to make use of methane. The gas sells for such low prices these days relative to other fuels that it would take many years to recoup the cost of installing the systems necessary to harvest it. As a result, mine owners simply allow the gas to enter the earth’s atmosphere.
And until recently, technology has limited mine operators to harnessing energy only from coal mine emissions with relatively high concentrations of methane. At concentrations above 80 percent, methane can be injected into natural gas pipelines or converted into liquefied natural gas for vehicles. At concentrations around 20 to 40 percent, the gas can fuel power generation as it does at Elk Creek, or industrial boilers that generate steam or hot water. According to a United Nations’ report, most medium- and high-quality methane is used to generate either power or a combination of power and useful heat. This methane is typically collected into boreholes drilled around the site before actual mining begins.
Much of the methane coming out of coal mine shafts, however, is in low concentrations, mixed together with nitrogen, oxygen and other contaminants. This is because operators typically use ventilation systems to dilute any methane leaking into mine shafts with fresh air for worker safety: at 5 to 15 percent concentration in air, methane is explosive, and concentrations below 1 percent are required for healthy breathing.
Once methane becomes mixed with other gases in ventilation systems, it becomes difficult to use as fuel because the mixture won’t burn and methane is tricky to filter out.
Due in part to these challenges, methane-laced ventilated air is typically released to the atmosphere, as it is at Elk Creek. Only about 20 of the more than 500 active underground coal mines nationwide have installed any type of system for capturing methane or converting it to electricity. And of those 20 mines, most are simply taking methane collected in drainage holes and injecting it into nearby natural gas pipelines for use by homes and businesses.
Partners for a New Approach
In western states like Colorado, coal mines are often located far from natural gas pipelines, so harnessing even high-quality methane from these sites demands a different approach. Elk Creek is unusual among U.S. coal mines in that it is burning methane to generate electricity on-site and sending that electricity to the local power grid.
Similar methane-to-energy technology has been installed at mines in Europe, Australia, China and other countries for decades. But those projects have benefited from tax incentives and other forms of public support, as well as costlier natural gas and electricity—which allows them to sell methane competitively at higher prices. Elk Creek offers a model for harnessing this waste through private partnerships in a time and place where electricity from natural gas is relatively cheap.
Tom Vessels, president of Denver, Colorado-based energy developer Vessels Coal and Gas, began seeking partners and financiers for a coal mine methane-to-energy project in 2005 after touring a number of mines using the technology in Germany. Most U.S. companies he approached were unfamiliar with the technology, Vessels says, and reluctant to invest as a result. True, it had not been done in the U.S., he says. “But we’re checking that box now.”
In 2012, Vessels secured $5.4 million in funding from Aspen Skiing Company, a high-end resort corporation aiming to generate cleaner energy and counterbalance the emissions associated with its own electricity use. Holy Cross Energy, a rural electricity cooperative, signed on to pay slightly above market rates for electricity from the project in exchange for a 15-year contract and a new, cleaner source of electricity.
Finally, Elk Creek owner Oxbow Mining, led by energy magnate William Koch, agreed to let Vessels install equipment at its mine in exchange for a small cut of annual power sales. Most of the revenue from Holy Cross—about $650,000 per year, or about 12 percent of ASC’s original investment—will go to the resort company.
Policies on the Horizon
The project began feeding electricity to the power grid last year for distribution throughout western Colorado. Several months later, Colorado passed a new law that requires large rural electric co-ops, and the utilities that serve them, to get 20 percent of their energy from renewable sources by 2020—doubling a requirement set in 2004.
The law recognizes methane alongside continually replenished resources like wind and solar as a renewable resource, a policy strongly opposed by some environmental groups and green energy advocates. Jeremy Nichols, director of climate and energy programs for the non-profit environmental advocacy group WildEarth Guardians, says classifying methane “is not the purpose of a renewable energy standard.” But using methane for energy, he says, beats the status quo of venting it to the atmosphere. “At end of the day,” he says, “it’s making the best of a bad thing.” And over time, experts say bringing methane under the new mandate could increase demand among Colorado utilities for electricity from projects like Elk Creek.
Change is afoot at the federal level, too. President Obama has directed federal agencies to “develop a comprehensive methane strategy” and the Environmental Protection Agency has identified around 50 U.S. coal mines that show promise for capturing waste methane and burning it or converting it to electricity.
Methane energy proponents are hopeful that a forthcoming vote in California will ultimately make the technology more profitable coast to coast. The state’s air regulators are slated to vote soon on a proposal to reward methane abatement projects under its cap-and-trade program, which is designed to help the state reduce its greenhouse gas emissions to 1990 levels by the year 2020. If approved, the protocol would allow coal mine operators and methane emitters nationwide to earn credits for reducing their emissions. California polluters expecting to exceed the state’s maximum emission allowance could then purchase these credits as a way to negate their overage.
“You need a very good price on carbon to make [methane mitigation] viable,” says Clark Talkington, a senior consultant with Advanced Resources International, which develops energy and carbon sequestration projects. “I know there are several projects sitting on the sidelines, so if California comes through, it would definitely drive those forward.”
At Elk Creek, for example, 84 percent of methane captured from the mine—enough to generate $1 million worth of electricity—is simply burned because Holy Cross lacks the budget and desire to purchase more energy from the project, and no other customers have been found. “We definitely have our eye on another project,” says ASC’s Schendler. “But the barrier is getting a power purchase agreement from another utility that is at an acceptable price.” ASC would lose money on the project if it sold electricity at the typical wholesale rate of 3.5 cents per kilowatt hour.
Innovation in the Works
Beyond policy, innovative techniques are making it possible to scavenge methane from very dilute sources, such as the ventilated air in mine shafts, and use it as fuel for generators. At a large coal mine in China’s Henan Province, ventilated air with methane concentrations as low 0.3 percent is used to heat water for mine facilities. The system loops ventilated coal mine air through chambers that increase its temperature until methane molecules break down into carbon dioxide and water, and the heat from this reaction is captured.
In Australia, a coal plant owned by BHP Billiton combines ventilated air methane with highly concentrated methane that has been drained into boreholes drilled near the mine before mining begins. Mixed together, methane from the vents and the drains can be burned as fuel. This system generates heat to produce steam, which in turn runs a small power plant producing an average of 10 gigawatt hours per year.
Other scientists are looking to develop better filters for separating the methane in ventilated air from unneeded gases like carbon dioxide and nitrogen. Scientists with the University of California, Berkeley and the Lawrence Livermore National Laboratory, for example, have looked at a highly sorbent material marked by nano-scale pores called nanoporous zeolites. The group has used computer models to test nearly 100,000 different zeolite structures, says Amitesh Maiti, a materials physicist at the Lawrence Livermore lab.
At this point, the research remains in early stages. “The material might not be as pure in real life as we see in these models,” Maiti says. Yet if a nanoporous zeolite or other material can be developed that readily captures methane molecules, it could dramatically reduce the cost of generating electricity from the highly diluted waste methane of coal mines. In the process, it could make this source of methane too valuable as a fuel to carry on its previous mantle as a harmful, nuisance waste to be thrown away.
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This article is also published on the Energy Realities website.