UVA professor proposes resourceful approach to reducing emission - Beckley, Bluefield & Lewisburg News, Weather, Sports

UVA professor proposes resourceful approach to reducing emissions

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  • Many WV coal counties losing revenue

    Many WV coal counties losing revenue

    Monday, August 8 2016 10:15 AM EDT2016-08-08 14:15:05 GMT

    As Appalachian coal production continues its drastic decline, West Virginia’s coal-producing counties are  not only losing people as lifelong residents are forced to flee their homes in order to find work, but in many cases, they’re also relinquishing millions of dollars from their budgets.

    As Appalachian coal production continues its drastic decline, West Virginia’s coal-producing counties are  not only losing people as lifelong residents are forced to flee their homes in order to find work, but in many cases, they’re also relinquishing millions of dollars from their budgets.

The push to cut greenhouse gas emissions from fossil fuel-fired power plants, which are a major source of man-made carbon dioxide emissions, has been rapidly growing stronger over the last several years, and companies throughout the power sector have been scrambling to come up with a solution.

But Andres Clarens, an assistant professor in the Department of Civil and Environmental Engineering at the University of Virginia, has proposed a new approach to an existing question of how to cut down on emissions.

In an attempt to comply with various environmental standards, many power companies are employing carbon dioxide capture and sequestration, or CCS, which can reduce carbon dioxide emissions by 80-90 percent, according to the Environmental Protection Agency.

As the name suggests, CCS is the process of trapping carbon dioxide from coal- and gas-fired power plants and large industrial sources before it is released into the atmosphere, transporting it to storage sites and depositing it somewhere for long-term storage. Commonly, the captured carbon dioxide is placed deep underground in saline aquifers, unmineable coal seams or depleted oil and gas reservoirs; and in some cases, companies are using the captured carbon dioxide in enhanced oil recovery, in which case it is forced into a well as an attempt to push more oil and gas out of the wells. According to the EPA’s Greenhouse Gas Reporting Program, CCS technology is currently in use at more than 120 facilities in the United States.

Clarens’ approach makes use of carbon capture, but aims to take advantage of the hydraulic fracturing, or fracking, boom that has been sweeping the nation in the shale gas industry.

In his report, coauthored by graduate student Zhiyuan Tao, Clarens outlined a CCS method in which companies capture carbon dioxide from power plants and transport it back to depleted shale gas wells that have been hydraulically fractured.

“We’re producing all of these oil and gas out of these shales,” he said, adding that the process begged the question, “Would we be able to take CO2 and pump CO2 in there and store it in the well?”

So, that’s what he set out to answer.

To write the report, which was published in the American Chemical Society’s Environmental Science and Technology journal in August 2013, the team used historical and projected methane production data, as well as published data and models that have estimated the carbon dioxide capacity of shale formations. The team then applied its model to the Marcellus shale play in Pennsylvania, which they concluded could store roughly 50 percent of the U.S. carbon dioxide emissions produced from stationary sources between 2018 and 2030.

The main argument against this method is that carbon capture technology is expensive to implement at large industrial sources. According to a 2008 report published by Greenpeace.org, CCS uses between 10 percent and 40 percent of the energy produced by a power station, which could lead to a doubling of plant costs and an electricity price increase between 21 percent and 91 percent.

But Clarens defended his case, stating that while CCS could be expensive to implement, his method of storage should be cheaper than most others.

“The (shale) wells are already there, and drilling and fracking a well costs $3 million to $4 million,” he said. “From an infrastructure standpoint, we’ve got the pipelines, we’ve got the wells. If you use the same wells, the cost is lower than pumping CO2 into a saline aquifer.”

Additionally, Clarens said the shale beds have the potential to be more stable storage units, because pumping carbon dioxide into saline aquifers creates pressure underground, which can cause the CO2 to “squirt” into the ground.

“After fracturing, you would put CO2 back in there and it might not make it move,” he said. “It might not create the same drivers to squirt out somewhere else.

“The idea is that it would be more stable down there.”

Despite his confidence in the method, Clarens said it is still very much in the research stage.

Since the report was published, Clarens has given several lectures at various colleges and has been working to further the process by conducting follow-up research in collaboration with the U.S. Department of Energy’s National Energy Technology Laboratory in Morgantown.

Dan Soeder, a research scientist in NETL’s Office of Research and Development, is one of the researchers working with Clarens’ method.

The current issue, Soeder said, is trying to figure out how much space is available in shale formations for carbon dioxide storage when the natural gas, which is mostly methane, is removed.

“When you take natural gas out, you drop the pressure under the rock,” Soeder said. “We don’t fully understand how that will behave and if we can get that permeability back.”

Soeder said that one of the assumptions in carbon storage is that at least as much CO2 will fit back into the rock as the amount of methane they took out, but with little knowledge on the behavioral and physical differences between traditional gas wells and shale wells, researchers are still basing information on models and existing methods of storage to try to figure out the plausibility of Clarens’ plan.

One major issue standing in the way of experimentation is the fact that there are no depleted shale gas wells yet, delaying the method’s implementation for about another decade.

“We’re a good few years out because there aren’t any depleted fractured wells,” Clarens said. “We didn’t really start fracking wells until like five years ago in a big way, and wells last 10-15 years.”

But to Clarens, the timeline isn’t an obstacle, but rather it’s just a part of the plan.

“In some ways, the timing is kind of good.”

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