A unique approach to monitoring groundwater supplies near Ohio fracking sites

This image shows a drilling rig in Carroll County, Ohio. -  Amy Townsend-Small
This image shows a drilling rig in Carroll County, Ohio. – Amy Townsend-Small

A University of Cincinnati research project is taking a groundbreaking approach to monitoring groundwater resources near fracking sites in Ohio. Claire Botner, a UC graduate student in geology, will outline the project at The Geological Society of America’s Annual Meeting & Exposition. The meeting takes place Oct. 19-22, in Vancouver.

Botner’s research is part of UC Groundwater Research of Ohio (GRO), a collaborative research project out of UC to examine the effects of fracking (hydraulic fracturing) on groundwater in the Utica Shale region of eastern Ohio. First launched in Carroll County in 2012, the GRO team of researchers is examining methane levels and origins of methane in private wells and springs before, during and after the onset of fracking. The team travels to the region to take water samples four times a year.

Amy Townsend-Small, the lead researcher for GRO and a UC assistant professor of geology, says the UC study is unique in comparison with studies on water wells in other shale-rich areas of the U.S. where fracking is taking place – such as the Marcellus Shale region of Pennsylvania.

Townsend-Small says water samples finding natural gas-derived methane in wells near Pennsylvania fracking sites were taken only after fracking had occurred, so methane levels in those wells were not documented prior to or during fracking in Pennsylvania.

Hydraulic fracturing, or fracking, involves using millions of gallons of water mixed with sand and chemicals to break up organic-rich shale to release natural gas resources.

Proponents say the practice promises a future in lower energy prices, an increase in domestic jobs and less dependence on foreign oil from unstable overseas governments.

Opponents raise concerns about increasing methane gas levels (a powerful greenhouse gas) and other contamination involving the spillover of fracking wastewater in the groundwater of shale-rich regions.

“The only way people with private groundwater will know whether or not their water is affected by fracking is through regular monitoring,” says Townsend-Small.

The Ohio samples are being analyzed by UC researchers for concentrations of methane as well as other hydrocarbons and salt, which is pulled up in the fracking water mixture from the shales. The shales are ancient ocean sediments.

Botner’s study involves testing on 22 private wells in Carroll County between November 2012 and last May. The first fracking permits were issued in the region in 2011. So far, results indicate that any methane readings in groundwater wells came from organic matter. In less than a handful of cases, the natural methane levels were relatively high, above 10 milligrams per liter. However, most of the wells carried low levels of methane.

The UC sampling has now been expanded into Columbiana, Harrison, Stark and Belmont counties in Ohio. Researchers then review data on private drinking water wells with the homeowners. “We’re working on interacting with these communities and educating them about fracking as well as gathering scientific data, which is lacking on a very sensitive issue,” says Botner. “It can also be reassuring to receive data on their water supplies from an objective, university resource.”

The team also is seeking additional funding to begin monitoring groundwater wells near wastewater injection wells, where fracking brine is deposited after the wells are drilled.


Funding for Botner’s research to be presented at the GSA meeting is supported by a grant from the Missouri-based Deer Creek Foundation.

Botner is among UC graduate students and faculty who are presenting more than two dozen research papers, PowerPoint presentations or poster exhibitions at the GSA meeting. The meeting draws geoscientists from around the world representing more than 40 different disciplines.

UC’s nationally ranked Department of Geology conducts field research around the world in areas spanning paleontology, Quaternary geology, geomorphology, sedimentology, stratigraphy, tectonics, environmental geology and biogeochemistry.

The Geological Society of America, founded in 1888, is a scientific society with more than 26,500 members from academia, government and industry in more than 100 countries. Through its meetings, publications and programs, GSA enhances the professional growth of its members and promotes the geosciences in the service of humankind.

Contaminated water in 2 states linked to faulty shale gas wells

Faulty well integrity, not hydraulic fracturing deep underground, is the primary cause of drinking water contamination from shale gas extraction in parts of Pennsylvania and Texas, according to a new study by researchers from five universities.

The scientists from Duke, Ohio State, Stanford, Dartmouth and the University of Rochester
published their peer-reviewed study Sept. 15 in the Proceedings of the National Academy of Sciences. Using noble gas and hydrocarbon tracers, they analyzed the gas content of more than 130 drinking water wells in the two states.

“We found eight clusters of wells — seven in Pennsylvania and one in Texas — with contamination, including increased levels of natural gas from the Marcellus shale in Pennsylvania and from shallower, intermediate layers in both states,” said Thomas H. Darrah, assistant professor of earth science at Ohio State, who led the study while he was a research scientist at Duke.

“Our data clearly show that the contamination in these clusters stems from well-integrity problems such as poor casing and cementing,” Darrah said.

“These results appear to rule out the possibility that methane has migrated up into drinking water aquifers because of horizontal drilling or hydraulic fracturing, as some people feared,” said Avner Vengosh, professor of geochemistry and water quality at Duke.

In four of the affected clusters, the team’s noble gas analysis shows that methane from drill sites escaped into drinking water wells from shallower depths through faulty or insufficient rings of cement surrounding a gas well’s shaft. In three clusters, the tests suggest the methane leaked through faulty well casings. In one cluster, it was linked to an underground well failure.

“People’s water has been harmed by drilling,” said Robert B. Jackson, professor of environmental and earth sciences at Stanford and Duke. “In Texas, we even saw two homes go from clean to contaminated after our sampling began.”

“The good news is that most of the issues we have identified can potentially be avoided by future improvements in well integrity,” Darrah stressed.

Using both noble gas and hydrocarbon tracers — a novel combination that enabled the researchers to identify and distinguish between the signatures of naturally occurring methane and stray gas contamination from shale gas drill sites — the team analyzed gas content in 113 drinking-water wells and one natural methane seep overlying the Marcellus shale in Pennsylvania, and in 20 wells overlying the Barnett shale in Texas. Sampling was conducted in 2012 and 2013. Sampling sites included wells where contamination had been debated previously; wells known to have naturally high level of methane and salts, which tend to co-occur in areas overlying shale gas deposits; and wells located both within and beyond a one-kilometer distance from drill sites.

Noble gases such as helium, neon or argon are useful for tracing fugitive methane because although they mix with natural gas and can be transported with it, they are inert and are not altered by microbial activity or oxidation. By measuring changes in ratios in these tag-along noble gases, researchers can determine the source of fugitive methane and the mechanism by which it was transported into drinking water aquifers — whether it migrated there as a free gas or was dissolved in water.

“This is the first study to provide a comprehensive analysis of noble gases and their isotopes in groundwater near shale gas wells,” said Darrah, who is continuing the analysis in his lab at Ohio State. “Using these tracers, combined with the isotopic and chemical fingerprints of hydrocarbons in the water and its salt content, we can pinpoint the sources and pathways of methane contamination, and determine if it is natural or not.”

Gas leaks from faulty wells linked to contamination in some groundwater

A study has pinpointed the likely source of most natural gas contamination in drinking-water wells associated with hydraulic fracturing, and it’s not the source many people may have feared.

What’s more, the problem may be fixable: improved construction standards for cement well linings and casings at hydraulic fracturing sites.

A team led by a researcher at The Ohio State University and composed of researchers at Duke, Stanford, Dartmouth, and the University of Rochester devised a new method of geochemical forensics to trace how methane migrates under the earth. The study identified eight clusters of contaminated drinking-water wells in Pennsylvania and Texas.

Most important among their findings, published this week in the Proceedings of the National Academy of Sciences, is that neither horizontal drilling nor hydraulic fracturing of shale deposits seems to have caused any of the natural gas contamination.

“There is no question that in many instances elevated levels of natural gas are naturally occurring, but in a subset of cases, there is also clear evidence that there were human causes for the contamination,” said study leader Thomas Darrah, assistant professor of earth sciences at Ohio State. “However our data suggests that where contamination occurs, it was caused by poor casing and cementing in the wells,” Darrah said.

In hydraulic fracturing, water is pumped underground to break up shale at a depth far below the water table, he explained. The long vertical pipes that carry the resulting gas upward are encircled in cement to keep the natural gas from leaking out along the well. The study suggests that natural gas that has leaked into aquifers is the result of failures in the cement used in the well.

“Many of the leaks probably occur when natural gas travels up the outside of the borehole, potentially even thousands of feet, and is released directly into drinking-water aquifers” said Robert Poreda, professor of geochemistry at the University of Rochester.

“These results appear to rule out the migration of methane up into drinking water aquifers from depth because of horizontal drilling or hydraulic fracturing, as some people feared,” said Avner Vengosh, professor of geochemistry and water quality at Duke.

“This is relatively good news because it means that most of the issues we have identified can potentially be avoided by future improvements in well integrity,” Darrah said.

“In some cases homeowner’s water has been harmed by drilling,” said Robert B. Jackson, professor of environmental and earth sciences at Stanford and Duke. “In Texas, we even saw two homes go from clean to contaminated after our sampling began.”

The method that the researchers used to track the source of methane contamination relies on the basic physics of the noble gases (which happen to leak out along with the methane). Noble gases such as helium and neon are so called because they don’t react much with other chemicals, although they mix with natural gas and can be transported with it.

That means that when they are released underground, they can flow long distances without getting waylaid by microbial activity or chemical reactions along the way. The only important variable is the atomic mass, which determines how the ratios of noble gases change as they tag along with migrating natural gas. These properties allow the researchers to determine the source of fugitive methane and the mechanism by which it was transported into drinking water aquifers.

The researchers were able to distinguish between the signatures of naturally occurring methane and stray gas contamination from shale gas drill sites overlying the Marcellus shale in Pennsylvania and the Barnett shale in Texas.

The researchers sampled water from the sites in 2012 and 2013. Sampling sites included wells where contamination had been debated previously; wells known to have naturally high level of methane and salts, which tend to co-occur in areas overlying shale gas deposits; and wells located both within and beyond a one-kilometer distance from drill sites.

As hydraulic fracturing starts to develop around the globe, including countries South Africa, Argentina, China, Poland, Scotland, and Ireland, Darrah and his colleagues are continuing their work in the United States and internationally. And, since the method that the researchers employed relies on the basic physics of the noble gases, it can be employed anywhere. Their hope is that their findings can help highlight the necessity to improve well integrity.

The bend in the Appalachian mountain chain is finally explained

A dense, underground block of volcanic rock (shown in red) helped shape the well-known bend in the Appalachian mountain range. -  Graphic by Michael Osadciw/University of Rochester.
A dense, underground block of volcanic rock (shown in red) helped shape the well-known bend in the Appalachian mountain range. – Graphic by Michael Osadciw/University of Rochester.

The 1500 mile Appalachian mountain chain runs along a nearly straight line from Alabama to Newfoundland-except for a curious bend in Pennsylvania and New York State. Researchers from the College of New Jersey and the University of Rochester now know what caused that bend-a dense, underground block of rigid, volcanic rock forced the chain to shift eastward as it was forming millions of years ago.

According to Cindy Ebinger, a professor of earth and environmental sciences at the University of Rochester, scientists had previously known about the volcanic rock structure under the Appalachians. “What we didn’t understand was the size of the structure or its implications for mountain-building processes,” she said.

The findings have been published in the journal Earth and Planetary Science Letters.

When the North American and African continental plates collided more than 300 million years ago, the North American plate began folding and thrusting upwards as it was pushed westward into the dense underground rock structure-in what is now the northeastern United States. The dense rock created a barricade, forcing the Appalachian mountain range to spring up with its characteristic bend.

The research team-which also included Margaret Benoit, an associate professor of physics at the College of New Jersey, and graduate student Melanie Crampton at the College of New Jersey-studied data collected by the Earthscope project, which is funded by the National Science Foundation. Earthscope makes use of 136 GPS receivers and an array of 400 portable seismometers deployed in the northeast United States to measure ground movement.

Benoit and Ebinger also made use of the North American Gravity Database, a compilation of open-source data from the U.S., Canada, and Mexico. The database, started two decades ago, contains measurements of the gravitational pull over the North American terrain. Most people assume that gravity has a constant value, but when gravity is experimentally measured, it changes from place to place due to variations in the density and thickness of Earth’s rock layers. Certain parts of the Earth are denser than others, causing the gravitational pull to be slightly greater in those places.

Data on the changes in gravitational pull and seismic velocity together allowed the researchers to determine the density of the underground structure and conclude that it is volcanic in origin, with dimensions of 450 kilometers by 100 kilometers. This information, along with data from the Earthscope project ultimately helped the researchers to model how the bend was formed.

Ebinger called the research project a “foundation study” that will improve scientists’ understanding of the Earth’s underlying structures. As an example, Ebinger said their findings could provide useful information in the debate over hydraulic fracturing-popularly known is hydrofracking-in New York State.

Hydrofracking is a mining technique used to extract natural gas from deep in the earth. It involves drilling horizontally into shale formations, then injecting the rock with sand, water, and a cocktail of chemicals to free the trapped gas for removal. The region just west of the Appalachian Basin-the Marcellus Shale formation-is rich in natural gas reserves and is being considered for development by drilling companies.

Fracking flowback could pollute groundwater with heavy metals

Partially wetted sand grains (grey) with colloids (red) are shown. -  Cornell University
Partially wetted sand grains (grey) with colloids (red) are shown. – Cornell University

The chemical makeup of wastewater generated by “hydrofracking” could cause the release of tiny particles in soils that often strongly bind heavy metals and pollutants, exacerbating the environmental risks during accidental spills, Cornell University researchers have found.

Previous research has shown 10 to 40 percent of the water and chemical solution mixture injected at high pressure into deep rock strata, surges back to the surface during well development. Scientists at the College of Agriculture and Life Sciences studying the environmental impacts of this “flowback fluid” found that the same properties that make it so effective at extracting natural gas from shale can also displace tiny particles that are naturally bound to soil, causing associated pollutants such as heavy metals to leach out.

They described the mechanisms of this release and transport in a paper published in the American Chemical Society journal Environmental Science & Technology.

The particles they studied are colloids – larger than the size of a molecule but smaller than what can be seen with the naked eye – which cling to sand and soil due to their electric charge.

In experiments, glass columns were filled with sand and synthetic polystyrene colloids. They then flushed the column with different fluids – deionized water as a control, and flowback fluid collected from a Marcellus Shale drilling site – at different rates of flow and measured the amount of colloids that were mobilized.

On a bright field microscope, the polystyrene colloids were visible as red spheres between light-grey sand grains, which made their movement easy to track. The researchers also collected and analyzed the water flowing out of the column to quantify the colloid concentration leaching out.

They found that fewer than five percent of colloids were released when they flushed the columns with deionized water. That figure jumped to 32 to 36 percent when flushed with flowback fluid. Increasing the flow rate of the flowback fluid mobilized an additional 36 percent of colloids.

They believe this is because the chemical composition of the flowback fluid reduced the strength of the forces that allow colloids to remain bound to the sand, causing the colloids to actually be repelled from the sand.

“This is a first step into discovering the effects of flowback fluid on colloid transport in soils,” said postdoctoral associate Cathelijne Stoof, a co-author on the paper.

The authors hope to conduct further experiments using naturally occurring colloids in more complex field soil systems, as well as different formulations of flowback fluid collected from other drilling sites.

Stoof said awareness of the phenomenon and an understanding of the mechanisms behind it can help identify risks and inform mitigation strategies.

“Sustainable development of any resource requires facts about its potential impacts, so legislators can make informed decisions about whether and where it can and cannot be allowed, and to develop guidelines in case it goes wrong,” Stoof said. “In the case of spills, you want to know what happens when the fluid moves through the soil.”

Click on this image to view the .mp4 video
This video visualizes the effects of hydrofracking flowback fluid on colloid mobilization in unsaturated sand. Included are the injection of the colloids into the sand column at the beginning of the experiment, the deionized water flush at 0.3 ml/min, the flowback water flush at 0.3 ml/min, and the flowback water flush at 1.5 ml/min. – Cornell University

Acid mine drainage reduces radioactivity in fracking waste

Much of the naturally occurring radioactivity in fracking wastewater might be removed by blending it with another wastewater from acid mine drainage, according to a Duke University-led study.

“Fracking wastewater and acid mine drainage each pose well-documented environmental and public health risks. But in laboratory tests, we found that by blending them in the right proportions we can bind some of the fracking contaminants into solids that can be removed before the water is discharged back into streams and rivers,” said Avner Vengosh, professor of geochemistry and water quality at Duke’s Nicholas School of the Environment.

“This could be an effective way to treat Marcellus Shale hydraulic fracturing wastewater, while providing a beneficial use for acid mine drainage that currently is contaminating waterways in much of the northeastern United States,” Vengosh said. “It’s a win-win for the industry and the environment.”

Blending fracking wastewater with acid mine drainage also could help reduce the depletion of local freshwater resources by giving drillers a source of usable recycled water for the hydraulic fracturing process, he added.

“Scarcity of fresh water in dry regions or during periods of drought can severely limit shale gas development in many areas of the United States and in other regions of the world where fracking is about to begin,” Vengosh said. “Using acid mine drainage or other sources of recycled or marginal water may help solve this problem and prevent freshwater depletion.”

The peer-reviewed study was published in late December 2013 in the journal Environmental Science & Technology.

In hydraulic fracturing – or fracking, as it is sometimes called – millions of tons of water are injected at high pressure down wells to crack open shale deposits buried deep underground and extract natural gas trapped within the rock. Some of the water flows back up through the well, along with natural brines and the natural gas. This “flowback fluid” typically contains high levels of salts, naturally occurring radioactive materials such as radium, and metals such as barium and strontium.

A study last year by the Duke team showed that standard treatment processes only partially remove these potentially harmful contaminants from Marcellus Shale wastewater before it is discharged back into streams and waterways, causing radioactivity to accumulate in stream sediments near the disposal site.

Acid mine drainage flows out of abandoned coal mines into many streams in the Appalachian Basin. It can be highly toxic to animals, plants and humans, and affects the quality of hundreds of waterways in Pennsylvania and West Virginia.

Because much of the current Marcellus shale gas development is taking place in regions where large amounts of historic coal mining occurred, some experts have suggested that acid mine drainage could be used to frack shale gas wells in place of fresh water.

To test that hypothesis, Vengosh and his team blended different mixtures of Marcellus Shale fracking wastewater and acid mine drainage, all of which were collected from sites in western Pennsylvania and provided to the scientists by the industry.

After 48 hours, the scientists examined the chemical and radiological contents of 26 different mixtures. Geochemical modeling was used to simulate the chemical and physical reactions that had occurred after the blending; the results of the modeling were then verified using x-ray diffraction and by measuring the radioactivity of the newly formed solids.

“Our analysis suggested that several ions, including sulfate, iron, barium and strontium, as well as between 60 and 100 percent of the radium, had precipitated within the first 10 hours into newly formed solids composed mainly of strontium barite,” Vengosh said. These radioactive solids could be removed from the mixtures and safely disposed of at licensed hazardous-waste facilities, he said. The overall salinity of the blended fluids was also reduced, making the treated water suitable for re-use at fracking sites.

“The next step is to test this in the field. While our laboratory tests show that is it technically possible to generate recycled, treated water suitable for hydraulic fracturing, field-scale tests are still necessary to confirm its feasibility under operational conditions,” Vengosh said.

Radioactive shale gas contaminants found at wastewater discharge site

Elevated levels of radioactivity, salts and metals have been found in river water and sediments at a site where treated water from oil and gas operations is discharged into a western Pennsylvania creek.

“Radium levels were about 200 times greater in sediment samples collected where the Josephine Brine Treatment Facility discharges its treated wastewater into Blacklick Creek than in sediment samples collected just upstream of the plant,” said Avner Vengosh, professor of geochemistry and water quality at Duke University’s Nicholas School of the Environment.

The new Duke study examined the quality of shale gas wastewater from hydraulic fracturing and the stream water above and below the disposal site. The study found that some of the discharged effluent is derived from the Marcellus shale gas flowback water, which is naturally high in salinity and radioactivity.

High concentrations of some salts and metals were also observed in the stream water. “The treatment removes a substantial portion of the radioactivity, but it does not remove many of the other salts, including bromide,” Vengosh said. “When the high-bromide effluents are discharged to the stream, it increases the concentrations of bromide above the original background levels. This is significant because bromide increases the risks for formation of highly toxic disinfection byproducts in drinking water treatment facilities that are located downstream.”

“The radioactivity levels we found in sediments near the outflow are above management regulations in the U.S. and would only be accepted at a licensed radioactive disposal facility,” said Robert B. Jackson, professor of environmental science at Duke. “The facility is quite effective in removing metals such as barium from the water but concentrates sulfates, chlorides and bromides. In fact this single facility contributes four-fifths of the total downstream chloride flow at this point.”

The Duke team also analyzed stream-bottom sediments for radium isotopes that are typically found in Marcellus wastewater. “Although the facility’s treatment process significantly reduced radium and barium levels in the wastewater, the amount of radioactivity that has accumulated in the river sediments still exceeds thresholds for safe disposal of radioactive materials,” Vengosh said. “Years of disposal of oil and gas wastewater with high radioactivity has created potential environmental risks for thousands of years to come.”

“While water contamination can be mitigated by treatment to a certain degree, our findings indicate that disposal of wastewater from both conventional and unconventional oil and gas operations has degraded the surface water and sediments,” said Nathaniel R. Warner, a recent Ph.D. graduate of Duke who is now a postdoctoral researcher at Dartmouth College. “This could be a long-term legacy of radioactivity.”

Industry has made efforts to reuse or to transport shale gas wastewater to deep injection wells, but wastewater is still discharged to the environment in some states. “It is clear that this practice of releasing wastewater without adequate treatment should be stopped in order to protect freshwater resources in areas of oil and gas development,” Vengosh said.

The Duke team published their findings Oct. 2 in the peer-reviewed journal Environmental Science & Technology.

Methane out, carbon dioxide in?

A University of Virginia engineering professor has proposed a novel approach for keeping waste carbon dioxide out of the atmosphere.

Andres Clarens, an assistant professor of civil and environmental engineering at U.Va.’s School of Engineering and Applied Science, and graduate student Zhiyuan Tao have published a paper in which they estimate the amount of carbon dioxide that could be stored in hydraulically fractured shale deposits after the methane gas has been extracted. Their peer-reviewed finding was published in Environmental Science and Technology, a publication of the American Chemical Society.

The team applied their model to the Marcellus Shale geological formation in Pennsylvania and found that the fractured rock has the potential to store roughly 50 percent of the U.S. carbon dioxide emissions produced from stationary sources between 2018 and 2030. According to his estimate, about 10 to 18 gigatonnes of carbon dioxide could be stored in the Marcellus formation alone. The U.S. has several other large shale formations that could provide additional storage.

The researchers’ model is based on historical and projected methane production, along with published data and models for estimating the carbon dioxide capacity of the formations. Clarens said that production records are available for how much methane gas producers have already extracted from the Marcellus Shale, as well as estimates of how much more they expect to extract. That provides a basis for determining how much space will be left in the formation when the methane is gone, he said. Clarens said gas would be adsorbed into the pores of the shale and held securely.

“This would be a way of eating our cake and having it too,” Clarens said. “We can drill the shale, pump out the gas and pump in the carbon dioxide.. I think this will get policymakers’ attention.”

He said his work deals with the chemical feasibility of the idea, and that additional studies must be performed to examine the economical, political and logistical implication.

“My field is carbon management – high-pressure carbon dioxide chemistry,” he said. “Right now, we are emitting huge levels of carbon dioxide, and we need new ideas on ways to store the waste.”

Clarens, who said he has no connection with the oil and gas industry, knows some in the environmental movement oppose hydraulic fracturing because of possible risks to ground and surface waters. However, he thinks this type of extraction is inevitable in many places and it is important to preemptively develop new strategies for handling the environmental implications, especially those related to carbon dioxide.

“There are a lot of people who say we need to get away from carbon-based fuels, and that may be possible in a few decades, but right now, fossil fuels power everything,” he said. “Finding ways to harvest these non-conventional fossil fuel sources without contributing to climate changes is a difficult but important challenge.”

Clarens said he believes he and Tao are the first researchers to propose this strategy. He hopes this paper will contribute to a discourse on how best to responsibly develop this booming resource.

Clarens, who received his doctorate from the University of Michigan, did his undergraduate work at U.Va., receiving a bachelor’s degree in chemical engineering in 1999.

Stray gases found in water wells near shale gas sites

Homeowners living within one kilometer of shale gas wells appear to be at higher risk of having their drinking water contaminated by stray gases, according to a new Duke University-led study.

Duke scientists analyzed 141 drinking water samples from private water wells across northeastern Pennsylvania’s gas-rich Marcellus shale basin. Their study documented not only higher methane concentrations in drinking water within a kilometer of shale gas drilling — which past studies have shown — but higher ethane and propane concentrations as well.

Methane concentrations were six times higher and ethane concentrations were 23 times higher at homes within a kilometer of a shale gas well. Propane was detected in 10 samples, all of them from homes within a kilometer of drilling.

“The methane, ethane and propane data, and new evidence from hydrocarbon and helium isotopes, all suggest that drilling has affected some homeowners’ water,” said Robert B. Jackson, a professor of environmental sciences at Duke’s Nicholas School of the Environment. “In a minority of cases, the gas even looks Marcellus-like, probably caused by faulty well construction.”

The ethane and propane contamination data are “new and hard to refute,” Jackson stressed. “There is no biological source of ethane and propane in the region and Marcellus gas is high in both, and higher in concentration than the Upper Devonian gas found in-between.”

The team examined which factors might explain their results, including topography, distance to gas wells and distance to geologic features. “Distance to gas wells was, by far, the most significant factor influencing gases in the drinking water we sampled,” said Jackson.

The peer-reviewed findings will appear this week in the online Early Edition of the Proceedings of the National Academy of Sciences.

Hydraulic fracturing, also called hydrofracking or fracking, involves pumping water, sand and chemicals deep underground into horizontal gas wells at high pressure to crack open hydrocarbon-rich shale and extract natural gas. Accelerated shale gas drilling and hydrofracking in recent years has fueled concerns about contamination in nearby drinking water supplies.

Two previous peer-reviewed studies by Duke scientists found direct evidence of methane contamination in water wells near shale-gas drilling sites in northeastern Pennsylvania, as well as possible connectivity between deep brines and shallow aquifers. A third study conducted with U.S. Geological Survey scientists found no evidence of drinking water contamination from shale gas production in Arkansas. None of the studies have found evidence of contamination by fracking fluids.

“Our studies demonstrate that distances from drilling sites, as well as variations in local and regional geology, play major roles in determining the possible risk of groundwater impacts from shale gas development,” said Avner Vengosh, professor of geochemistry and water quality at Duke’s Nicholas School. “As such, they must be taken into consideration before drilling begins.”

“The helium data in this study are the first from a new tool kit we’ve devised for identifying contamination using noble gas isotopes,” said Duke research scientist Thomas H. Darrah. “These tools allow us to identify and trace contaminants with a high degree of certainty.”

Analysis of Marcellus flowback finds high levels of ancient brines

Brine water that flows back from gas wells in the Marcellus Shale region after hydraulic fracturing is many times more salty than seawater, with high contents of various elements, including radium and barium. The chemistry is consistent with brines formed during the Paleozoic era, a study by an undergraduate student and two professors in Penn State’s Department of Geosciences found.

The study indicates that the brine flowback elements found in high levels in the late stages of hydraulic fracturing come from the ancient brines rather than from salts dissolved by the water and chemicals used as part of the fracking process. The paper by Lara O. Haluszczak, a Penn State student who has since graduated; professor emeritus Arthur W. Rose; and Lee R. Kump, professor and head of the Department of Geosciences, detailing those findings has been accepted for publication in Applied Geochemistry, the journal of the International Association of Geochemistry, and is available online.

For the study, the researchers analyzed data primarily from four sources: a report on brines from 40 conventional oil and gas wells in Pennsylvania; data on flowback waters from 22 Marcellus gas wells in Pennsylvania that the state Bureau of Oil and Gas Management had collected; flowback waters from two Marcellus gas wells from a previous study; and an industry study by the Marcellus Shale Coalition on flowback samples from eight horizontal wells that was reported in a Gas Technology Institute report.

Hydraulic fracturing, or fracking, is the process used to release natural gas from the shale formations deep underground. The process involves drilling down thousands of feet and, in the case of horizontal wells, sideways, then injecting a mixture of water, sand and chemicals to release the gas. The paper notes that about a quarter of the volume of fluid used for fracking returns to the surface, but with the brine as a major component.

The paper looked at fluids that flowed back within 90 days of fracking. The samples analyzed in the study come from wells in Pennsylvania, along with two from northern Virginia.

The analysis shows that the brine flowback had extremely high salinity that does not match the chemical composition of the solution put into the wells during the fracking process. Instead, the elements being released are similar to those deposited during the Paleozoic era, hundreds of millions of years ago.

Rose said the naturally occurring radioactive materials being brought to the surface after having been 8,000 feet deep were deposited with formations in that era. He noted that while much attention has been focused on the chemicals that are injected into the shale formation during the fracking process, also of concern is the release of elements such as barium and radium that have been in the ground for millions of years.

“Even if it’s diluted quite a bit, it’s still going to be above the drinking water limits,” Rose said. “There’s been very little research into this.”
Pennsylvania does have regulations on the disposal of fracking fluids. Rose said the findings highlight the importance of re-use and proper disposal of fracking fluids, including those from the later stages of drilling.

“Improper disposal of the flowback can lead to unsafe levels of these and other constituents in water, biota and sediment from wells and streams,” the researchers noted.

“The high salinity and toxicity of these waters must be a key criterion in the technology for disposal of both the flowback waters and the continuing outflow of the production waters,” the paper concludes.