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.”

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.

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.

Researchers use simple scaling theory to better predict gas production in barnett shale wells

Researchers at The University of Texas at Austin have developed a simple scaling theory to estimate gas production from hydraulically fractured wells in the Barnett Shale. The method is intended to help the energy industry accurately identify low- and high-producing horizontal wells, as well as accurately predict how long it will take for gas reserves to deplete in the wells.

Using historical data from horizontal wells in the Barnett Shale formation in North Texas, Tad Patzek, professor and chair in the Department of Petroleum and Geosystems Engineering in the Cockrell School of Engineering; Michael Marder, professor of physics in the College of Natural Sciences; and Frank Male, a graduate student in physics, used a simple physics theory to model the rate at which production from the wells declines over time, known as the “decline curve.”

They describe their new model of the decline curve in the paper “Gas production in the Barnett Shale obeys a simple scaling theory,” published this week in the Proceedings of the National Academy of Sciences. To test their theory, the researchers analyzed 10 years of gas production data from the Barnett Shale licensed to the university by IHS CERA, a provider of global market and economic information.

On average, they found that gas production in individual wells begins declining after about five years of production. They also found that wells generally produce less gas than predicted under previous, theoretical models and that production can be increased if hydrofractures connected better to the natural fractures in the rock.

The team’s estimates were an instrumental part of the comprehensive assessment of Barnett Shale reserves funded by the Alfred P. Sloan Foundation and issued earlier this year by the Bureau of Economic Geology at UT Austin.

Until now, estimates of shale gas production have primarily relied on models established for conventional oil and gas wells, which behave differently from the horizontal wells in gas-rich shales.

The researchers estimate the ultimate gas recovery from a sample of 8,294 horizontal wells in the Barnett Shale will be between 10 trillion and 20 trillion standard cubic feet (scf) during the lifetime of the wells. The study’s well sample is made up of about half of the 15,000 existing wells in the Barnett Shale, the geological formation outside Fort Worth that offers the longest production history for hydrofractured horizontal wells in the world.

“With our model at hand, you can better predict how much gas volume is left and how long it will take until that volume will be depleted,” Patzek said. “We are able to match historical production and predict future production of thousands of horizontal gas wells using this scaling theory.”

“The contributions of shale gas to the U.S. economy are so enormous that even small corrections to production estimates are of great practical significance,” Patzek said.

The researchers were surprised by how all of the wells they analyzed adhere to that simple scaling curve.

“By analyzing the basic physics underlying gas recovery from hydrofractured wells, we calculated a single curve that should describe how much gas comes out over time, and we showed that production from thousands of wells follows this curve,” Marder said.

Patzek adds: “We are able to predict when the decline will begin. Once decline sets in, gas production goes down rapidly.”

The decline of a well happens because of a process called pressure diffusion that causes pressure around a well to drop and gas production to decrease. The time at which gas pressure drops below its initial value everywhere in the rock between hydrofractures is called its interference time. On average, it takes five years for interference to occur, at which point wells produce gas at a far lower rate because the amount of gas coming out over time is proportional to the amount of gas remaining.

Using two parameters – a well’s interference time and the original gas in place – the researchers were able to determine the universal decline curve and extrapolate total gas production over time.

The researchers found that the scaling theory accurately predicted the behavior of approximately 2,000 wells in which production had begun to decrease exponentially within the past 10 years. The remaining wells were too young for the model to predict when decreases would set in, but the model enabled the researchers to estimate upper and lower production limits for well lifetime and the amount of gas that will be produced by the wells.

“For 2,057 of the horizontal wells in the Barnett Shale, interference is far enough advanced for us to verify that wells behave as predicted by the scaling form,” Patzek said. “The production forecasts will become more accurate as more production data becomes available.”

As a byproduct of their analysis, the researchers found that most horizontal wells for which predictions are possible underperform their theoretical production limits. The researchers have reached a tentative conclusion that many wells are on track to produce only about 10 percent of their potential.

The researchers conclude that well production could be greatly improved if the hydrofractures connected better to natural fractures in the surrounding rock. The process of hydraulic fracturing creates a network of cracks, like veins, in rocks that was previously impermeable, allowing gas to move. If there are high porosity and permeability within those connected cracks and hydrofractures, then a well is high producing. By contrast, if the connection with hydrofractures is weak, then a well is low producing.

“If this finding spurs research to understand why wells underperform, it may lead to improved production methods and eventually increase gas extraction from wells,” Marder said.

Work is underway on how to improve performance of hydrofractures in horizontal wells, Patzek added.

Researchers use simple scaling theory to better predict gas production in barnett shale wells

Researchers at The University of Texas at Austin have developed a simple scaling theory to estimate gas production from hydraulically fractured wells in the Barnett Shale. The method is intended to help the energy industry accurately identify low- and high-producing horizontal wells, as well as accurately predict how long it will take for gas reserves to deplete in the wells.

Using historical data from horizontal wells in the Barnett Shale formation in North Texas, Tad Patzek, professor and chair in the Department of Petroleum and Geosystems Engineering in the Cockrell School of Engineering; Michael Marder, professor of physics in the College of Natural Sciences; and Frank Male, a graduate student in physics, used a simple physics theory to model the rate at which production from the wells declines over time, known as the “decline curve.”

They describe their new model of the decline curve in the paper “Gas production in the Barnett Shale obeys a simple scaling theory,” published this week in the Proceedings of the National Academy of Sciences. To test their theory, the researchers analyzed 10 years of gas production data from the Barnett Shale licensed to the university by IHS CERA, a provider of global market and economic information.

On average, they found that gas production in individual wells begins declining after about five years of production. They also found that wells generally produce less gas than predicted under previous, theoretical models and that production can be increased if hydrofractures connected better to the natural fractures in the rock.

The team’s estimates were an instrumental part of the comprehensive assessment of Barnett Shale reserves funded by the Alfred P. Sloan Foundation and issued earlier this year by the Bureau of Economic Geology at UT Austin.

Until now, estimates of shale gas production have primarily relied on models established for conventional oil and gas wells, which behave differently from the horizontal wells in gas-rich shales.

The researchers estimate the ultimate gas recovery from a sample of 8,294 horizontal wells in the Barnett Shale will be between 10 trillion and 20 trillion standard cubic feet (scf) during the lifetime of the wells. The study’s well sample is made up of about half of the 15,000 existing wells in the Barnett Shale, the geological formation outside Fort Worth that offers the longest production history for hydrofractured horizontal wells in the world.

“With our model at hand, you can better predict how much gas volume is left and how long it will take until that volume will be depleted,” Patzek said. “We are able to match historical production and predict future production of thousands of horizontal gas wells using this scaling theory.”

“The contributions of shale gas to the U.S. economy are so enormous that even small corrections to production estimates are of great practical significance,” Patzek said.

The researchers were surprised by how all of the wells they analyzed adhere to that simple scaling curve.

“By analyzing the basic physics underlying gas recovery from hydrofractured wells, we calculated a single curve that should describe how much gas comes out over time, and we showed that production from thousands of wells follows this curve,” Marder said.

Patzek adds: “We are able to predict when the decline will begin. Once decline sets in, gas production goes down rapidly.”

The decline of a well happens because of a process called pressure diffusion that causes pressure around a well to drop and gas production to decrease. The time at which gas pressure drops below its initial value everywhere in the rock between hydrofractures is called its interference time. On average, it takes five years for interference to occur, at which point wells produce gas at a far lower rate because the amount of gas coming out over time is proportional to the amount of gas remaining.

Using two parameters – a well’s interference time and the original gas in place – the researchers were able to determine the universal decline curve and extrapolate total gas production over time.

The researchers found that the scaling theory accurately predicted the behavior of approximately 2,000 wells in which production had begun to decrease exponentially within the past 10 years. The remaining wells were too young for the model to predict when decreases would set in, but the model enabled the researchers to estimate upper and lower production limits for well lifetime and the amount of gas that will be produced by the wells.

“For 2,057 of the horizontal wells in the Barnett Shale, interference is far enough advanced for us to verify that wells behave as predicted by the scaling form,” Patzek said. “The production forecasts will become more accurate as more production data becomes available.”

As a byproduct of their analysis, the researchers found that most horizontal wells for which predictions are possible underperform their theoretical production limits. The researchers have reached a tentative conclusion that many wells are on track to produce only about 10 percent of their potential.

The researchers conclude that well production could be greatly improved if the hydrofractures connected better to natural fractures in the surrounding rock. The process of hydraulic fracturing creates a network of cracks, like veins, in rocks that was previously impermeable, allowing gas to move. If there are high porosity and permeability within those connected cracks and hydrofractures, then a well is high producing. By contrast, if the connection with hydrofractures is weak, then a well is low producing.

“If this finding spurs research to understand why wells underperform, it may lead to improved production methods and eventually increase gas extraction from wells,” Marder said.

Work is underway on how to improve performance of hydrofractures in horizontal wells, Patzek added.

Potential well water contaminants highest near natural gas drilling

Brian Fontenot, who earned his Ph.D. in quantitative biology from UT Arlington, worked with Kevin Schug, UT Arlington associate professor of chemistry and biochemistry, and a team of researchers to analyze samples from 100 private water wells. -  UT Arlington
Brian Fontenot, who earned his Ph.D. in quantitative biology from UT Arlington, worked with Kevin Schug, UT Arlington associate professor of chemistry and biochemistry, and a team of researchers to analyze samples from 100 private water wells. – UT Arlington

A new study of 100 private water wells in and near the Barnett Shale showed elevated levels of potential contaminants such as arsenic and selenium closest to natural gas extraction sites, according to a team of researchers that was led by UT Arlington associate professor of chemistry and biochemistry Kevin Schug.

The results of the North Texas well study were published online by the journal Environmental Science & Technology Thursday. The peer-reviewed paper focuses on the presence of metals such as arsenic, barium, selenium and strontium in water samples. Many of these heavy metals occur naturally at low levels in groundwater, but disturbances from natural gas extraction activities could cause them to occur at elevated levels.

“This study alone can’t conclusively identify the exact causes of elevated levels of contaminants in areas near natural gas drilling, but it does provide a powerful argument for continued research,” said Brian Fontenot, a UT Arlington graduate with a doctorate in quantitative biology and lead author on the new paper.

He added: “We expect this to be the first of multiple projects that will ultimately help the scientific community, the natural gas industry, and most importantly, the public, understand the effects of natural gas drilling on water quality.”

Researchers believe the increased presence of metals could be due to a variety of factors including: industrial accidents such as faulty gas well casings; mechanical vibrations from natural gas drilling activity disturbing particles in neglected water well equipment; or the lowering of water tables through drought or the removal of water used for the hydraulic fracturing process. Any of these scenarios could release dangerous compounds into shallow groundwater.

Researchers gathered samples from private water wells of varying depth within a 13 county area in or near the Barnett Shale in North Texas over four months in the summer and fall of 2011. Ninety-one samples were drawn from what they termed “active extraction areas,” or areas that had one or more gas wells within a five kilometer radius. Another nine samples were taken from sites either inside the Barnett Shale and more than 14 kilometers from a natural gas drilling site, or from sites outside the Barnett Shale altogether. The locations of those sites were referred to as “non-active/reference areas” in the study.

Researchers accepted no outside funding to ensure the integrity of the study. They compared the samples to historical data on water wells in these counties from the Texas Water Development Board groundwater database for 1989-1999, prior to the proliferation of natural gas drilling.

In addition to standard water quality tests, the researchers used gas chromatography – mass spectrometry (GC-MS), headspace gas chromatography (HS-GC) and inductively coupled plasma-mass spectrometry (ICP-MS). Many of the tests were conducted in the Shimadzu Center for Advanced Analytical Chemistry on the UT Arlington campus.

“Natural gas drilling is one of the most talked about issues in North Texas and throughout the country. This study was an opportunity for us to use our knowledge of chemistry and statistical analysis to put people’s concerns to the test and find out whether they would be backed by scientific data,” said Schug, who is also the Shimadzu Distinguished Professor of Analytical Chemistry in the UT Arlington College of Science.

On average, researchers detected the highest levels of these contaminants within 3 kilometers of natural gas wells, including several samples that had arsenic and selenium above levels considered safe by the Environmental Protection Agency. For example, 29 wells that were within the study’s active natural gas drilling area exceeded the EPA’s Maximum Contaminant Limit of 10 micrograms per liter for arsenic, a potentially dangerous situation.

The areas lying outside of active drilling areas or outside the Barnett Shale did not show the same elevated levels for most of the metals.
Other leaders of the Texas Gas Wells team were Laura Hunt, who conducted her post-doctoral research in biology at UT Arlington, and Zacariah Hildenbrand, who earned his doctorate in biochemistry from the University of Texas at El Paso and performed post-doctoral research at UT Southwestern Medical Center. Hildenbrand is also the founder of Inform Environmental, LLC. Fontenot and Hunt work for the EPA regional office in Dallas, but the study is unaffiliated with the EPA and both received permission to work on this project outside the agency.

Scientists note in the paper that they did not find uniformity among the contamination in the active natural gas drilling areas. In other words, not all gas well sites were associated with higher levels of the metals in well water.

Some of the most notable results were on the following heavy metals:

  • Arsenic occurs naturally in the region’s water and was detected in 99 of the 100 samples. But, the concentrations of arsenic were significantly higher in the active extraction areas compared to non-extraction areas and historical data. The maximum concentration from an extraction area sample was 161 micrograms per liter, or 16 times the EPA safety standard set for drinking water. According to the EPA, people who drink water containing arsenic well in excess of the safety standard for many years “could experience skin damage or problems with their circulatory system, and may have an increased risk of getting cancer.”
  • Selenium was found in 10 samples near extraction sites, and all of those samples showed selenium levels were higher than the historical average. Two samples exceeded the standard for selenium set by the EPA. Circulation problems as well as hair or fingernail loss are some possible consequences of long-term exposure to high levels of selenium, according to the EPA.
  • Strontium was also found in almost all the samples, with concentrations significantly higher than historical levels in the areas of active gas extraction. A toxicological profile by the federal government’s Agency for Toxic Substances and Disease Registry recommends no more than 4,000 micrograms of strontium per liter in drinking water. Seventeen samples from the active extraction area and one from the non-active areas exceeded that recommended limit. Exposure to high levels of stable strontium can result in impaired bone growth in children, according to the toxic substances agency.

“After we put the word out about the study, we received numerous calls from landowner volunteers and their opinions about the natural gas drilling in their communities varied,” Hildenbrand said. “By participating in the study, they were able to get valuable data about their water, whether it be for household or land use.

“Their participation has been incredibly important to this study and has helped us bring to light some of the important environmental questions surrounding this highly contentious issue.”

The paper also recommends further research on levels of methanol and ethanol in water wells. Twenty-nine private water wells in the study contained methanol, with the highest concentrations in the active extraction areas. Twelve samples, four of which were from the non-active extraction sites, contained measurable ethanol. Both ethanol and methanol can occur naturally or as a result of industrial contamination.

Historical data on methanol and ethanol was not available, researchers said in the paper.

The paper is called “An evaluation of water quality in private drinking water wells near natural gas extraction sites in the Barnett Shale formation.” It is available on the Just Accepted page of the journal’s website. A YouTube interview with some of the study’s authors is available here: http://www.youtube.com/watch?v=H1_WDDtWR_k&feature=youtu.be.

Other co-authors include: Qinhong “Max” Hu, associate professor of earth and environmental sciences at UT Arlington; Doug D. Carlton Jr., a Ph.D. student in the chemistry and biochemistry department at UT Arlington; Hyppolite Oka, a recent graduate of the environmental and earth sciences master’s program at UT Arlington; Jayme L. Walton, a recent graduate of the biology master’s program at UT Arlington; and Dan Hopkins, of Carrollton-based Geotech Environmental Equipment, Inc.

Alexandria Osorio and Bryan Bjorndal of Assure Controls, Inc. in Vista, Calif., also are co-authors. The team used Assure’s Qwiklite? system to test for toxicity in well samples and those results are being prepared for a separate publication.

Many from the research team are now conducting well water sampling in the Permian Basin region of Texas, establishing a baseline set of data prior to gas well drilling activities there. That baseline will be used for a direct comparison to samples that will be collected during and after upcoming natural gas extraction. The team hopes that these efforts will shed further light on the relationship between natural gas extraction and ground water quality.

Potential well water contaminants highest near natural gas drilling

Brian Fontenot, who earned his Ph.D. in quantitative biology from UT Arlington, worked with Kevin Schug, UT Arlington associate professor of chemistry and biochemistry, and a team of researchers to analyze samples from 100 private water wells. -  UT Arlington
Brian Fontenot, who earned his Ph.D. in quantitative biology from UT Arlington, worked with Kevin Schug, UT Arlington associate professor of chemistry and biochemistry, and a team of researchers to analyze samples from 100 private water wells. – UT Arlington

A new study of 100 private water wells in and near the Barnett Shale showed elevated levels of potential contaminants such as arsenic and selenium closest to natural gas extraction sites, according to a team of researchers that was led by UT Arlington associate professor of chemistry and biochemistry Kevin Schug.

The results of the North Texas well study were published online by the journal Environmental Science & Technology Thursday. The peer-reviewed paper focuses on the presence of metals such as arsenic, barium, selenium and strontium in water samples. Many of these heavy metals occur naturally at low levels in groundwater, but disturbances from natural gas extraction activities could cause them to occur at elevated levels.

“This study alone can’t conclusively identify the exact causes of elevated levels of contaminants in areas near natural gas drilling, but it does provide a powerful argument for continued research,” said Brian Fontenot, a UT Arlington graduate with a doctorate in quantitative biology and lead author on the new paper.

He added: “We expect this to be the first of multiple projects that will ultimately help the scientific community, the natural gas industry, and most importantly, the public, understand the effects of natural gas drilling on water quality.”

Researchers believe the increased presence of metals could be due to a variety of factors including: industrial accidents such as faulty gas well casings; mechanical vibrations from natural gas drilling activity disturbing particles in neglected water well equipment; or the lowering of water tables through drought or the removal of water used for the hydraulic fracturing process. Any of these scenarios could release dangerous compounds into shallow groundwater.

Researchers gathered samples from private water wells of varying depth within a 13 county area in or near the Barnett Shale in North Texas over four months in the summer and fall of 2011. Ninety-one samples were drawn from what they termed “active extraction areas,” or areas that had one or more gas wells within a five kilometer radius. Another nine samples were taken from sites either inside the Barnett Shale and more than 14 kilometers from a natural gas drilling site, or from sites outside the Barnett Shale altogether. The locations of those sites were referred to as “non-active/reference areas” in the study.

Researchers accepted no outside funding to ensure the integrity of the study. They compared the samples to historical data on water wells in these counties from the Texas Water Development Board groundwater database for 1989-1999, prior to the proliferation of natural gas drilling.

In addition to standard water quality tests, the researchers used gas chromatography – mass spectrometry (GC-MS), headspace gas chromatography (HS-GC) and inductively coupled plasma-mass spectrometry (ICP-MS). Many of the tests were conducted in the Shimadzu Center for Advanced Analytical Chemistry on the UT Arlington campus.

“Natural gas drilling is one of the most talked about issues in North Texas and throughout the country. This study was an opportunity for us to use our knowledge of chemistry and statistical analysis to put people’s concerns to the test and find out whether they would be backed by scientific data,” said Schug, who is also the Shimadzu Distinguished Professor of Analytical Chemistry in the UT Arlington College of Science.

On average, researchers detected the highest levels of these contaminants within 3 kilometers of natural gas wells, including several samples that had arsenic and selenium above levels considered safe by the Environmental Protection Agency. For example, 29 wells that were within the study’s active natural gas drilling area exceeded the EPA’s Maximum Contaminant Limit of 10 micrograms per liter for arsenic, a potentially dangerous situation.

The areas lying outside of active drilling areas or outside the Barnett Shale did not show the same elevated levels for most of the metals.
Other leaders of the Texas Gas Wells team were Laura Hunt, who conducted her post-doctoral research in biology at UT Arlington, and Zacariah Hildenbrand, who earned his doctorate in biochemistry from the University of Texas at El Paso and performed post-doctoral research at UT Southwestern Medical Center. Hildenbrand is also the founder of Inform Environmental, LLC. Fontenot and Hunt work for the EPA regional office in Dallas, but the study is unaffiliated with the EPA and both received permission to work on this project outside the agency.

Scientists note in the paper that they did not find uniformity among the contamination in the active natural gas drilling areas. In other words, not all gas well sites were associated with higher levels of the metals in well water.

Some of the most notable results were on the following heavy metals:

  • Arsenic occurs naturally in the region’s water and was detected in 99 of the 100 samples. But, the concentrations of arsenic were significantly higher in the active extraction areas compared to non-extraction areas and historical data. The maximum concentration from an extraction area sample was 161 micrograms per liter, or 16 times the EPA safety standard set for drinking water. According to the EPA, people who drink water containing arsenic well in excess of the safety standard for many years “could experience skin damage or problems with their circulatory system, and may have an increased risk of getting cancer.”
  • Selenium was found in 10 samples near extraction sites, and all of those samples showed selenium levels were higher than the historical average. Two samples exceeded the standard for selenium set by the EPA. Circulation problems as well as hair or fingernail loss are some possible consequences of long-term exposure to high levels of selenium, according to the EPA.
  • Strontium was also found in almost all the samples, with concentrations significantly higher than historical levels in the areas of active gas extraction. A toxicological profile by the federal government’s Agency for Toxic Substances and Disease Registry recommends no more than 4,000 micrograms of strontium per liter in drinking water. Seventeen samples from the active extraction area and one from the non-active areas exceeded that recommended limit. Exposure to high levels of stable strontium can result in impaired bone growth in children, according to the toxic substances agency.

“After we put the word out about the study, we received numerous calls from landowner volunteers and their opinions about the natural gas drilling in their communities varied,” Hildenbrand said. “By participating in the study, they were able to get valuable data about their water, whether it be for household or land use.

“Their participation has been incredibly important to this study and has helped us bring to light some of the important environmental questions surrounding this highly contentious issue.”

The paper also recommends further research on levels of methanol and ethanol in water wells. Twenty-nine private water wells in the study contained methanol, with the highest concentrations in the active extraction areas. Twelve samples, four of which were from the non-active extraction sites, contained measurable ethanol. Both ethanol and methanol can occur naturally or as a result of industrial contamination.

Historical data on methanol and ethanol was not available, researchers said in the paper.

The paper is called “An evaluation of water quality in private drinking water wells near natural gas extraction sites in the Barnett Shale formation.” It is available on the Just Accepted page of the journal’s website. A YouTube interview with some of the study’s authors is available here: http://www.youtube.com/watch?v=H1_WDDtWR_k&feature=youtu.be.

Other co-authors include: Qinhong “Max” Hu, associate professor of earth and environmental sciences at UT Arlington; Doug D. Carlton Jr., a Ph.D. student in the chemistry and biochemistry department at UT Arlington; Hyppolite Oka, a recent graduate of the environmental and earth sciences master’s program at UT Arlington; Jayme L. Walton, a recent graduate of the biology master’s program at UT Arlington; and Dan Hopkins, of Carrollton-based Geotech Environmental Equipment, Inc.

Alexandria Osorio and Bryan Bjorndal of Assure Controls, Inc. in Vista, Calif., also are co-authors. The team used Assure’s Qwiklite? system to test for toxicity in well samples and those results are being prepared for a separate publication.

Many from the research team are now conducting well water sampling in the Permian Basin region of Texas, establishing a baseline set of data prior to gas well drilling activities there. That baseline will be used for a direct comparison to samples that will be collected during and after upcoming natural gas extraction. The team hopes that these efforts will shed further light on the relationship between natural gas extraction and ground water quality.

Texas earthquake study cites ‘plausible cause’

Brian Stump, Chris Hayward and student Ashley Howe install seismic equipment near DFW Airport.
Brian Stump, Chris Hayward and student Ashley Howe install seismic equipment near DFW Airport.

A study of seismic activity near Dallas/Fort Worth International Airport by researchers from Southern Methodist University and the University of Texas at Austin reveals that the operation of a saltwater injection disposal well in the area was a “plausible cause” for the series of small earthquakes that occurred in the area between Oct. 30, 2008, and May 16, 2009.

The incidents under study occurred in an area of North Texas where the vast Barnett Shale geological formation traps natural gas deposits in subsurface rock. Production in the Barnett Shale relies on the injection of pressurized water into the ground to crack open the gas-bearing rock, a process known as “hydraulic fracturing.” Some of the injected water is recovered with the produced gas in the form of waste fluids that require disposal.

The earthquakes do not appear to be directly connected to the drilling, hydraulic fracturing or gas production in the Barnett Shale, the study concludes. However, re-injection of waste fluids into a zone below the Barnett Shale at the nearby saltwater disposal well began in September 2008, seven weeks before the first DFW earthquakes occurred and none were recorded in the area after the injection well stopped operating in August 2009.

The largest of the DFW-area earthquakes was a 3.3 magnitude event reported by the USGS National Earthquake Information Center.

A state tectonic map prepared by the Texas Bureau of Economic Geology shows a northeast-trending fault intersects the Dallas-Tarrant County line approximately at the location where the DFW quakes occurred. The study concludes, “It is plausible that the fluid injection in the southwest saltwater disposal well could have affected the in-situ tectonic stress regime on the fault, reactivating it and generating the DFW earthquakes.”

An SMU team led by seismologists Brian Stump and Chris Hayward placed portable, broadband seismic monitoring equipment in the area after the earthquakes began. The seismographs recorded 11 earthquakes between Nov. 9, 2008 and Jan. 2, 2009 that were too small to be felt by area residents. Cliff Frohlich and Eric Potter of UT-Austin joined the SMU team in studying the DFW-area sequence of “felt” earthquakes as well as the 11 “non-felt” earthquakes. Their study appears in the March issue of The Leading Edge, a publication of the Society of Exploration Geophysicists.

The SMU team also installed temporary monitors in and around Cleburne, Texas where another series of small earthquake began June 2, 2009 – but results from that study are not yet available.

Stump and Hayward caution that the DFW study raises more questions than it answers.

“What we have is a correlation between seismicity, and the time and location of saltwater injection,” Stump said. “What we don’t have is complete information about the subsurface structure in the area – things like the porosity and permeability of the rock, the fluid path and how that might induce an earthquake.”

“More than 200 saltwater disposal wells are active in the area of Barnett production,” the study notes. “If the DFW earthquakes were caused by saltwater injection or other activities associated with producing gas, it is puzzling why there are only one or two areas of felt seismicity.”

Further compounding the problem, Hayward said, is that there is not a good system in place to measure the naturally occurring seismicity in Texas: “We don’t have a baseline for study.”

Enhanced geothermal projects also rely on methods of rock fracturing and fluid circulation. Geological carbon sequestration, an approach being researched to combat climate change, calls for pumping large volumes of carbon dioxide into subsurface rock formations. “It’s important we understand why and under what circumstances fluid injection sometimes causes small, felt earthquakes so that we can minimize their effects,” Frohlich said.

The study notes that fault ruptures for typical induced earthquakes generally are too small to cause much damage.

“There needs to be collaboration between universities, the state of Texas, local government, the energy industry and possibly the federal government for study of this complicated question of induced seismicity,” Stump said. “Everyone wants quick answers. What I can tell you is the direction these questions are leading us.”