by Timothy Oleson Wednesday, May 14, 2014
In the Appalachian Basin, “there are hundreds of points where acid mine drainage is discharged to streams. … It’s a nuisance that affects the environment,” says Avner Vengosh, a geochemist at Duke University and a co-author of the new study, published in Environmental Science & Technology. Similarly, flowback water from shale gas operations is bad news if it’s discharged into the environment without being adequately treated, he says, because, after being injected deep underground, it returns to the surface loaded with radium, barium, strontium and other dissolved elements, which can accumulate in stream sediments.
Following up on an idea discussed within the shale gas industry in the last few years, Vengosh and his team combined varying proportions of AMD of different compositions with samples of flowback fluids provided by Pennsylvania-based Consol Energy. After mixing the fluids for 48 hours, they compared the composition of the resulting solution to the starting fluids and also analyzed solids that had formed.
In cases where the mixture was 50 percent AMD or more, the researchers found that virtually all of the barium and radium, along with roughly half the strontium, from the flowback fluid were removed from the mixed solution due to the precipitation of solid barium sulfate, or barite (into which both radium and strontium were incorporated as well). Even using just 25 percent AMD was enough to remove nearly all of the radium and more than half of the barium, they reported.
Based on geochemical modeling and preexisting knowledge of the different waters’ compositions, the results were expected for the most part, but “it’s always nice to see … real measurements that follow up the theoretical modeling,” Vengosh says. He calls the work so far “promising,” but notes that field tests are needed to see how the process would work in practice on a larger scale.
Adding AMD to fracking fluids — either within wells or externally at wastewater treatment plants — could have “multiple beneficial uses,” Vengosh says, because contaminated waters would be kept out of the environment and because AMD might be a cheap alternative to freshwater that can otherwise be used for drinking and agriculture. In Pennsylvania especially, sources of acidic runoff — largely the legacy of coal mining in the state — are often already located near shale gas wells, thus minimizing transport costs.
If the fluids were mixed at treatment plants, the radioactive solids produced would have to be stored at radioactive waste facilities, or diluted and disposed of in landfills, Vengosh notes, which could raise costs. But considering that some companies have already pursued such wastewater remediation techniques to a limited extent in the past, and that storing relatively small volumes of solid radioactive waste could be easier than dealing with untreated water, it’s a manageable issue, he says.
More so than remediation of flowback wastewater, the potential cost savings of being able to pump AMD from abandoned mine sites for use directly in nearby gas wells rather than having to bring in freshwater by the truckload to use in the wells, is the real incentive here for energy companies, says Radisav Vidic, an environmental engineer at the University of Pittsburgh who was not involved in the new study. Ninety percent of flowback water is recycled back down into the boreholes and doesn’t need treatment, he says, so companies are less concerned about removing radium and barium from this water.
But Vidic notes a sticking point for the use of AMD in fracking operations: “At the moment, oil and gas companies are comfortable fracking with maybe 100 to 200 milligrams of sulfate per liter of water” in the injected water, he says, whereas the AMD used in the experiments contained initial sulfate concentrations of about 1,000 to 5,000 milligrams per liter. Though their fears may be “unfounded” in the case of the Marcellus because of the shale’s chemistry, he says, the companies are “afraid that if you inject too much sulfate downhole, that sulfate is going to find barium and it’s going to precipitate, and that’s going to plug up the well.”
In the study, the researchers suggested that by mixing in relatively small proportions of AMD into flowback fluid — less than 50 percent — sulfate levels could be brought down to feasible levels for use in Marcellus Shale wells. And, Vengosh adds, other chemicals can be mixed in to mitigate the buildup of solids inside wells. Technically, it “can be done,” he says.
The biggest roadblock to the widespread use of AMD in Pennsylvania, both say, is the law. “What’s happening now is if you use any AMD, you declare ownership of it,” Vengosh says, meaning companies that weren’t involved in creating the acid runoff in the first place would be liable indefinitely for cleaning it up from a given source even if they were to stop using the AMD. Although there is a bill on the table — State Senate Bill 411 — to reduce companies’ liability, for now, Vidic says, the companies are worried “they’re going to be responsible for managing this water from now until eternity.”
© 2008-2021. All rights reserved. Any copying, redistribution or retransmission of any of the contents of this service without the expressed written permission of the American Geosciences Institute is expressly prohibited. Click here for all copyright requests.