New study measures methane emissions from natural gas production and offers insights into 2 large sources

A team of researchers from the Cockrell School of Engineering at The University of Texas at Austin and environmental testing firm URS reports that a small subset of natural gas wells are responsible for the majority of methane emissions from two major sources — liquid unloadings and pneumatic controller equipment — at natural gas production sites.

With natural gas production in the United States expected to continue to increase during the next few decades, there is a need for a better understanding of methane emissions during natural gas production. The study team believes this research, published Dec. 9 in Environmental Science & Technology, will help to provide a clearer picture of methane emissions from natural gas production sites.

The UT Austin-led field study closely examined two major sources of methane emissions — liquid unloadings and pneumatic controller equipment — at well pad sites across the United States. Researchers found that 19 percent of the pneumatic devices accounted for 95 percent of the emissions from pneumatic devices, and 20 percent of the wells with unloading emissions that vent to the atmosphere accounted for 65 percent to 83 percent of those emissions.

“To put this in perspective, over the past several decades, 10 percent of the cars on the road have been responsible for the majority of automotive exhaust pollution,” said David Allen, chemical engineering professor at the Cockrell School and principal investigator for the study. “Similarly, a small group of sources within these two categories are responsible for the vast majority of pneumatic and unloading emissions at natural gas production sites.”

Additionally, for pneumatic devices, the study confirmed regional differences in methane emissions first reported by the study team in 2013. The researchers found that methane emissions from pneumatic devices were highest in the Gulf Coast and lowest in the Rocky Mountains.

The study is the second phase of the team’s 2013 study, which included some of the first measurements for methane emissions taken directly at hydraulically fractured well sites. Both phases of the study involved a partnership between the Environmental Defense Fund, participating energy companies, an independent Scientific Advisory Panel and the UT Austin study team.

The unprecedented access to natural gas production facilities and equipment allowed researchers to acquire direct measurements of methane emissions.

Study and Findings on Pneumatic Devices

Pneumatic devices, which use gas pressure to control the opening and closing of valves, emit gas as they operate. These emissions are estimated to be among the larger sources of methane emissions from the natural gas supply chain. The Environmental Protection Agency reports that 477,606 pneumatic (gas actuated) devices are in use at natural gas production sites throughout the U.S.

“Our team’s previous work established that pneumatics are a major contributor to emissions,” Allen said. “Our goal here was to measure a more diverse population of wells to characterize the features of high-emitting pneumatic controllers.”

The research team measured emissions from 377 gas actuated (pneumatic) controllers at natural gas production sites and a small number of oil production sites throughout the U.S.

The researchers sampled all identifiable pneumatic controller devices at each well site, a more comprehensive approach than the random sampling previously conducted. The average methane emissions per pneumatic controller reported in this study are 17 percent higher than the average emissions per pneumatic controller in the 2012 EPA greenhouse gas national emission inventory (released in 2014), but the average from the study is dominated by a small subpopulation of the controllers. Specifically, 19 percent of controllers, with measured emission rates in excess of 6 standard cubic feet per hour (scf/h), accounted for 95 percent of emissions.

The high-emitting pneumatic devices are a combination of devices that are not operating as designed, are used in applications that cause them to release gas frequently or are designed to emit continuously at a high rate.

The researchers also observed regional differences in methane emission levels, with the lowest emissions per device measured in the Rocky Mountains and the highest emissions in the Gulf Coast, similar to the earlier 2013 study. At least some of the regional differences in emission rates can be attributed to the difference in controller type (continuous vent vs. intermittent vent) among regions.

Study and Findings on Liquid Unloadings

After observing variable emissions for liquid unloadings for a limited group of well types in the 2013 study, the research team made more extensive measurements and confirmed that a majority of emissions come from a small fraction of wells that vent frequently. Although it is not surprising to see some correlation between frequency of unloadings and higher annual emissions, the study’s findings indicate that wells with a high frequency of unloadings have annual emissions that are 10 or more times as great as wells that unload less frequently.

The team’s field study, which measured emissions from unloadings from wells at 107 natural gas production wells throughout the U.S., represents the most extensive measurement of emissions associated with liquid unloadings in scientific literature thus far.

A liquid unloading is one method used to clear wells of accumulated liquids to increase production. Because older wells typically produce less gas as they near the end of their life cycle, liquid unloadings happen more often in those wells than in newer wells. The team found a statistical correlation between the age of wells and the frequency of liquid unloadings. The researchers found that the key identifier for high-emitting wells is how many times the well unloads in a given year.

Because liquid unloadings can employ a variety of liquid lifting mechanisms, the study results also reflect differences in liquid unloadings emissions between wells that use two different mechanisms (wells with plunger lifts and wells without plunger lifts). Emissions for unloading events for wells without plunger lifts averaged 21,000 scf (standard cubic feet) to 35,000 scf. For wells with plunger lifts that vent to the atmosphere, emissions averaged 1,000 scf to 10,000 scf of methane per event. Although the emissions per event were higher for wells without plunger lifts, these wells had, on average, fewer events than wells with plunger lifts. Wells without plunger lifts averaged fewer than 10 unloading events per year, and wells with plunger lifts averaged more than 200 events per year.Overall, wells with plunger lifts were estimated to account for 70 percent of emissions from unloadings nationally.

Additionally, researchers found that the Rocky Mountain region, with its large number of wells with a high frequency of unloadings that vent to the atmosphere, accounts for about half of overall emissions from liquid unloadings.

The study team hopes its measurements of liquid unloadings and pneumatic devices will provide a clearer picture of methane emissions from natural gas well sites and about the relationship between well characteristics and emissions.

The study was a cooperative effort involving experts from the Environmental Defense Fund, Anadarko Petroleum Corporation, BG Group PLC, Chevron, ConocoPhillips, Encana Oil & Gas (USA) Inc., Pioneer Natural Resources Company, SWEPI LP (Shell), Statoil, Southwestern Energy and XTO Energy, a subsidiary of ExxonMobil.

The University of Texas at Austin is committed to transparency and disclosure of all potential conflicts of interest of its researchers. Lead researcher David Allen serves as chair of the Environmental Protection Agency’s Science Advisory Board and in this role is a paid Special Governmental Employee. He is also a journal editor for the American Chemical Society and has served as a consultant for multiple companies, including Eastern Research Group, ExxonMobil and the Research Triangle Institute. He has worked on other research projects funded by a variety of governmental, nonprofit and private sector sources including the National Science Foundation, the Environmental Protection Agency, the Texas Commission on Environmental Quality, the American Petroleum Institute and an air monitoring and surveillance project that was ordered by the U.S. District Court for the Southern District of Texas. Adam Pacsi and Daniel Zavala-Araiza, who were graduate students at The University of Texas at the time this work was done, have accepted positions at Chevron Energy Technology Company and the Environmental Defense Fund, respectively.

Financial support for this work was provided by the Environmental Defense Fund (EDF), Anadarko Petroleum Corporation, BG Group PLC, Chevron, ConocoPhillips, Encana Oil & Gas (USA) Inc., Pioneer Natural Resources Company, SWEPI LP (Shell), Statoil, Southwestern Energy and XTO Energy, a subsidiary of ExxonMobil.

Major funding for the EDF’s 30-month methane research series, including their portion of the University of Texas study, is provided for by the following individuals and foundations: Fiona and Stan Druckenmiller, the Heising-Simons Foundation, Bill and Susan Oberndorf, Betsy and Sam Reeves, the Robertson Foundation, TomKat Charitable Trust and the Walton Family Foundation.

New study measures methane emissions from natural gas production and offers insights into 2 large sources

A team of researchers from the Cockrell School of Engineering at The University of Texas at Austin and environmental testing firm URS reports that a small subset of natural gas wells are responsible for the majority of methane emissions from two major sources — liquid unloadings and pneumatic controller equipment — at natural gas production sites.

With natural gas production in the United States expected to continue to increase during the next few decades, there is a need for a better understanding of methane emissions during natural gas production. The study team believes this research, published Dec. 9 in Environmental Science & Technology, will help to provide a clearer picture of methane emissions from natural gas production sites.

The UT Austin-led field study closely examined two major sources of methane emissions — liquid unloadings and pneumatic controller equipment — at well pad sites across the United States. Researchers found that 19 percent of the pneumatic devices accounted for 95 percent of the emissions from pneumatic devices, and 20 percent of the wells with unloading emissions that vent to the atmosphere accounted for 65 percent to 83 percent of those emissions.

“To put this in perspective, over the past several decades, 10 percent of the cars on the road have been responsible for the majority of automotive exhaust pollution,” said David Allen, chemical engineering professor at the Cockrell School and principal investigator for the study. “Similarly, a small group of sources within these two categories are responsible for the vast majority of pneumatic and unloading emissions at natural gas production sites.”

Additionally, for pneumatic devices, the study confirmed regional differences in methane emissions first reported by the study team in 2013. The researchers found that methane emissions from pneumatic devices were highest in the Gulf Coast and lowest in the Rocky Mountains.

The study is the second phase of the team’s 2013 study, which included some of the first measurements for methane emissions taken directly at hydraulically fractured well sites. Both phases of the study involved a partnership between the Environmental Defense Fund, participating energy companies, an independent Scientific Advisory Panel and the UT Austin study team.

The unprecedented access to natural gas production facilities and equipment allowed researchers to acquire direct measurements of methane emissions.

Study and Findings on Pneumatic Devices

Pneumatic devices, which use gas pressure to control the opening and closing of valves, emit gas as they operate. These emissions are estimated to be among the larger sources of methane emissions from the natural gas supply chain. The Environmental Protection Agency reports that 477,606 pneumatic (gas actuated) devices are in use at natural gas production sites throughout the U.S.

“Our team’s previous work established that pneumatics are a major contributor to emissions,” Allen said. “Our goal here was to measure a more diverse population of wells to characterize the features of high-emitting pneumatic controllers.”

The research team measured emissions from 377 gas actuated (pneumatic) controllers at natural gas production sites and a small number of oil production sites throughout the U.S.

The researchers sampled all identifiable pneumatic controller devices at each well site, a more comprehensive approach than the random sampling previously conducted. The average methane emissions per pneumatic controller reported in this study are 17 percent higher than the average emissions per pneumatic controller in the 2012 EPA greenhouse gas national emission inventory (released in 2014), but the average from the study is dominated by a small subpopulation of the controllers. Specifically, 19 percent of controllers, with measured emission rates in excess of 6 standard cubic feet per hour (scf/h), accounted for 95 percent of emissions.

The high-emitting pneumatic devices are a combination of devices that are not operating as designed, are used in applications that cause them to release gas frequently or are designed to emit continuously at a high rate.

The researchers also observed regional differences in methane emission levels, with the lowest emissions per device measured in the Rocky Mountains and the highest emissions in the Gulf Coast, similar to the earlier 2013 study. At least some of the regional differences in emission rates can be attributed to the difference in controller type (continuous vent vs. intermittent vent) among regions.

Study and Findings on Liquid Unloadings

After observing variable emissions for liquid unloadings for a limited group of well types in the 2013 study, the research team made more extensive measurements and confirmed that a majority of emissions come from a small fraction of wells that vent frequently. Although it is not surprising to see some correlation between frequency of unloadings and higher annual emissions, the study’s findings indicate that wells with a high frequency of unloadings have annual emissions that are 10 or more times as great as wells that unload less frequently.

The team’s field study, which measured emissions from unloadings from wells at 107 natural gas production wells throughout the U.S., represents the most extensive measurement of emissions associated with liquid unloadings in scientific literature thus far.

A liquid unloading is one method used to clear wells of accumulated liquids to increase production. Because older wells typically produce less gas as they near the end of their life cycle, liquid unloadings happen more often in those wells than in newer wells. The team found a statistical correlation between the age of wells and the frequency of liquid unloadings. The researchers found that the key identifier for high-emitting wells is how many times the well unloads in a given year.

Because liquid unloadings can employ a variety of liquid lifting mechanisms, the study results also reflect differences in liquid unloadings emissions between wells that use two different mechanisms (wells with plunger lifts and wells without plunger lifts). Emissions for unloading events for wells without plunger lifts averaged 21,000 scf (standard cubic feet) to 35,000 scf. For wells with plunger lifts that vent to the atmosphere, emissions averaged 1,000 scf to 10,000 scf of methane per event. Although the emissions per event were higher for wells without plunger lifts, these wells had, on average, fewer events than wells with plunger lifts. Wells without plunger lifts averaged fewer than 10 unloading events per year, and wells with plunger lifts averaged more than 200 events per year.Overall, wells with plunger lifts were estimated to account for 70 percent of emissions from unloadings nationally.

Additionally, researchers found that the Rocky Mountain region, with its large number of wells with a high frequency of unloadings that vent to the atmosphere, accounts for about half of overall emissions from liquid unloadings.

The study team hopes its measurements of liquid unloadings and pneumatic devices will provide a clearer picture of methane emissions from natural gas well sites and about the relationship between well characteristics and emissions.

The study was a cooperative effort involving experts from the Environmental Defense Fund, Anadarko Petroleum Corporation, BG Group PLC, Chevron, ConocoPhillips, Encana Oil & Gas (USA) Inc., Pioneer Natural Resources Company, SWEPI LP (Shell), Statoil, Southwestern Energy and XTO Energy, a subsidiary of ExxonMobil.

The University of Texas at Austin is committed to transparency and disclosure of all potential conflicts of interest of its researchers. Lead researcher David Allen serves as chair of the Environmental Protection Agency’s Science Advisory Board and in this role is a paid Special Governmental Employee. He is also a journal editor for the American Chemical Society and has served as a consultant for multiple companies, including Eastern Research Group, ExxonMobil and the Research Triangle Institute. He has worked on other research projects funded by a variety of governmental, nonprofit and private sector sources including the National Science Foundation, the Environmental Protection Agency, the Texas Commission on Environmental Quality, the American Petroleum Institute and an air monitoring and surveillance project that was ordered by the U.S. District Court for the Southern District of Texas. Adam Pacsi and Daniel Zavala-Araiza, who were graduate students at The University of Texas at the time this work was done, have accepted positions at Chevron Energy Technology Company and the Environmental Defense Fund, respectively.

Financial support for this work was provided by the Environmental Defense Fund (EDF), Anadarko Petroleum Corporation, BG Group PLC, Chevron, ConocoPhillips, Encana Oil & Gas (USA) Inc., Pioneer Natural Resources Company, SWEPI LP (Shell), Statoil, Southwestern Energy and XTO Energy, a subsidiary of ExxonMobil.

Major funding for the EDF’s 30-month methane research series, including their portion of the University of Texas study, is provided for by the following individuals and foundations: Fiona and Stan Druckenmiller, the Heising-Simons Foundation, Bill and Susan Oberndorf, Betsy and Sam Reeves, the Robertson Foundation, TomKat Charitable Trust and the Walton Family Foundation.

Abandoned wells can be ‘super-emitters’ of greenhouse gas

One of the wells the researchers tested; this one in the Allegheny National Forest. -  Princeton University
One of the wells the researchers tested; this one in the Allegheny National Forest. – Princeton University

Princeton University researchers have uncovered a previously unknown, and possibly substantial, source of the greenhouse gas methane to the Earth’s atmosphere.

After testing a sample of abandoned oil and natural gas wells in northwestern Pennsylvania, the researchers found that many of the old wells leaked substantial quantities of methane. Because there are so many abandoned wells nationwide (a recent study from Stanford University concluded there were roughly 3 million abandoned wells in the United States) the researchers believe the overall contribution of leaking wells could be significant.

The researchers said their findings identify a need to make measurements across a wide variety of regions in Pennsylvania but also in other states with a long history of oil and gas development such as California and Texas.

“The research indicates that this is a source of methane that should not be ignored,” said Michael Celia, the Theodore Shelton Pitney Professor of Environmental Studies and professor of civil and environmental engineering at Princeton. “We need to determine how significant it is on a wider basis.”

Methane is the unprocessed form of natural gas. Scientists say that after carbon dioxide, methane is the most important contributor to the greenhouse effect, in which gases in the atmosphere trap heat that would otherwise radiate from the Earth. Pound for pound, methane has about 20 times the heat-trapping effect as carbon dioxide. Methane is produced naturally, by processes including decomposition, and by human activity such as landfills and oil and gas production.

While oil and gas companies work to minimize the amount of methane emitted by their operations, almost no attention has been paid to wells that were drilled decades ago. These wells, some of which date back to the 19th century, are typically abandoned and not recorded on official records.

Mary Kang, then a doctoral candidate at Princeton, originally began looking into methane emissions from old wells after researching techniques to store carbon dioxide by injecting it deep underground. While examining ways that carbon dioxide could escape underground storage, Kang wondered about the effect of old wells on methane emissions.

“I was looking for data, but it didn’t exist,” said Kang, now a postdoctoral researcher at Stanford.

In a paper published Dec. 8 in the Proceedings of the National Academy of Sciences, the researchers describe how they chose 19 wells in the adjacent McKean and Potter counties in northwestern Pennsylvania. The wells chosen were all abandoned, and records about the origin of the wells and their conditions did not exist. Only one of the wells was on the state’s list of abandoned wells. Some of the wells, which can look like a pipe emerging from the ground, are located in forests and others in people’s yards. Kang said the lack of documentation made it hard to tell when the wells were originally drilled or whether any attempt had been made to plug them.

“What surprised me was that every well we measured had some methane coming out,” said Celia.

To conduct the research, the team placed enclosures called flux chambers over the tops of the wells. They also placed flux chambers nearby to measure the background emissions from the terrain and make sure the methane was emitted from the wells and not the surrounding area.

Although all the wells registered some level of methane, about 15 percent emitted the gas at a markedly higher level — thousands of times greater than the lower-level wells. Denise Mauzerall, a Princeton professor and a member of the research team, said a critical task is to discover the characteristics of these super-emitting wells.

Mauzerall said the relatively low number of high-emitting wells could offer a workable solution: while trying to plug every abandoned well in the country might be too costly to be realistic, dealing with the smaller number of high emitters could be possible.

“The fact that most of the methane is coming out of a small number of wells should make it easier to address if we can identify the high-emitting wells,” said Mauzerall, who has a joint appointment as a professor of civil and environmental engineering and as a professor of public and international affairs at the Woodrow Wilson School.

The researchers have used their results to extrapolate total methane emissions from abandoned wells in Pennsylvania, although they stress that the results are preliminary because of the relatively small sample. But based on that data, they estimate that emissions from abandoned wells represents as much as 10 percent of methane from human activities in Pennsylvania — about the same amount as caused by current oil and gas production. Also, unlike working wells, which have productive lifetimes of 10 to 15 years, abandoned wells can continue to leak methane for decades.

“This may be a significant source,” Mauzerall said. “There is no single silver bullet but if it turns out that we can cap or capture the methane coming off these really big emitters, that would make a substantial difference.”


Besides Kang, who is the paper’s lead author, Celia and Mauzerall, the paper’s co-authors include: Tullis Onstott, a professor of geosciences at Princeton; Cynthia Kanno, who was a Princeton undergraduate and who is a graduate student at the Colorado School of Mines; Matthew Reid, who was a graduate student at Princeton and is a postdoctoral researcher at EPFL in Luzerne, Switzerland; Xin Zhang, a postdoctoral researcher in the Woodrow Wilson School at Princeton; and Yuheng Chen, an associate research scholar in geosciences at Princeton.

Abandoned wells can be ‘super-emitters’ of greenhouse gas

One of the wells the researchers tested; this one in the Allegheny National Forest. -  Princeton University
One of the wells the researchers tested; this one in the Allegheny National Forest. – Princeton University

Princeton University researchers have uncovered a previously unknown, and possibly substantial, source of the greenhouse gas methane to the Earth’s atmosphere.

After testing a sample of abandoned oil and natural gas wells in northwestern Pennsylvania, the researchers found that many of the old wells leaked substantial quantities of methane. Because there are so many abandoned wells nationwide (a recent study from Stanford University concluded there were roughly 3 million abandoned wells in the United States) the researchers believe the overall contribution of leaking wells could be significant.

The researchers said their findings identify a need to make measurements across a wide variety of regions in Pennsylvania but also in other states with a long history of oil and gas development such as California and Texas.

“The research indicates that this is a source of methane that should not be ignored,” said Michael Celia, the Theodore Shelton Pitney Professor of Environmental Studies and professor of civil and environmental engineering at Princeton. “We need to determine how significant it is on a wider basis.”

Methane is the unprocessed form of natural gas. Scientists say that after carbon dioxide, methane is the most important contributor to the greenhouse effect, in which gases in the atmosphere trap heat that would otherwise radiate from the Earth. Pound for pound, methane has about 20 times the heat-trapping effect as carbon dioxide. Methane is produced naturally, by processes including decomposition, and by human activity such as landfills and oil and gas production.

While oil and gas companies work to minimize the amount of methane emitted by their operations, almost no attention has been paid to wells that were drilled decades ago. These wells, some of which date back to the 19th century, are typically abandoned and not recorded on official records.

Mary Kang, then a doctoral candidate at Princeton, originally began looking into methane emissions from old wells after researching techniques to store carbon dioxide by injecting it deep underground. While examining ways that carbon dioxide could escape underground storage, Kang wondered about the effect of old wells on methane emissions.

“I was looking for data, but it didn’t exist,” said Kang, now a postdoctoral researcher at Stanford.

In a paper published Dec. 8 in the Proceedings of the National Academy of Sciences, the researchers describe how they chose 19 wells in the adjacent McKean and Potter counties in northwestern Pennsylvania. The wells chosen were all abandoned, and records about the origin of the wells and their conditions did not exist. Only one of the wells was on the state’s list of abandoned wells. Some of the wells, which can look like a pipe emerging from the ground, are located in forests and others in people’s yards. Kang said the lack of documentation made it hard to tell when the wells were originally drilled or whether any attempt had been made to plug them.

“What surprised me was that every well we measured had some methane coming out,” said Celia.

To conduct the research, the team placed enclosures called flux chambers over the tops of the wells. They also placed flux chambers nearby to measure the background emissions from the terrain and make sure the methane was emitted from the wells and not the surrounding area.

Although all the wells registered some level of methane, about 15 percent emitted the gas at a markedly higher level — thousands of times greater than the lower-level wells. Denise Mauzerall, a Princeton professor and a member of the research team, said a critical task is to discover the characteristics of these super-emitting wells.

Mauzerall said the relatively low number of high-emitting wells could offer a workable solution: while trying to plug every abandoned well in the country might be too costly to be realistic, dealing with the smaller number of high emitters could be possible.

“The fact that most of the methane is coming out of a small number of wells should make it easier to address if we can identify the high-emitting wells,” said Mauzerall, who has a joint appointment as a professor of civil and environmental engineering and as a professor of public and international affairs at the Woodrow Wilson School.

The researchers have used their results to extrapolate total methane emissions from abandoned wells in Pennsylvania, although they stress that the results are preliminary because of the relatively small sample. But based on that data, they estimate that emissions from abandoned wells represents as much as 10 percent of methane from human activities in Pennsylvania — about the same amount as caused by current oil and gas production. Also, unlike working wells, which have productive lifetimes of 10 to 15 years, abandoned wells can continue to leak methane for decades.

“This may be a significant source,” Mauzerall said. “There is no single silver bullet but if it turns out that we can cap or capture the methane coming off these really big emitters, that would make a substantial difference.”


Besides Kang, who is the paper’s lead author, Celia and Mauzerall, the paper’s co-authors include: Tullis Onstott, a professor of geosciences at Princeton; Cynthia Kanno, who was a Princeton undergraduate and who is a graduate student at the Colorado School of Mines; Matthew Reid, who was a graduate student at Princeton and is a postdoctoral researcher at EPFL in Luzerne, Switzerland; Xin Zhang, a postdoctoral researcher in the Woodrow Wilson School at Princeton; and Yuheng Chen, an associate research scholar in geosciences at Princeton.

Technology-dependent emissions of gas extraction in the US

The KIT measurement instrument on board of a minivan directly measures atmospheric emissions on site with a high temporal resolution. -  Photo: F. Geiger/KIT
The KIT measurement instrument on board of a minivan directly measures atmospheric emissions on site with a high temporal resolution. – Photo: F. Geiger/KIT

Not all boreholes are the same. Scientists of the Karlsruhe Institute of Technology (KIT) used mobile measurement equipment to analyze gaseous compounds emitted by the extraction of oil and natural gas in the USA. For the first time, organic pollutants emitted during a fracking process were measured at a high temporal resolution. The highest values measured exceeded typical mean values in urban air by a factor of one thousand, as was reported in ACP journal. (DOI 10.5194/acp-14-10977-2014)

Emission of trace gases by oil and gas fields was studied by the KIT researchers in the USA (Utah and Colorado) together with US institutes. Background concentrations and the waste gas plumes of single extraction plants and fracking facilities were analyzed. The air quality measurements of several weeks duration took place under the “Uintah Basin Winter Ozone Study” coordinated by the National Oceanic and Atmospheric Administration (NOAA).

The KIT measurements focused on health-damaging aromatic hydrocarbons in air, such as carcinogenic benzene. Maximum concentrations were determined in the waste gas plumes of boreholes. Some extraction plants emitted up to about a hundred times more benzene than others. The highest values of some milligrams of benzene per cubic meter air were measured downstream of an open fracking facility, where returning drilling fluid is stored in open tanks and basins. Much better results were reached by oil and gas extraction plants and plants with closed production processes. In Germany, benzene concentration at the workplace is subject to strict limits: The Federal Emission Control Ordinance gives an annual benzene limit of five micrograms per cubic meter for the protection of human health, which is smaller than the values now measured at the open fracking facility in the US by a factor of about one thousand. The researchers published the results measured in the journal Atmospheric Chemistry and Physics ACP.

“Characteristic emissions of trace gases are encountered everywhere. These are symptomatic of gas and gas extraction. But the values measured for different technologies differ considerably,” Felix Geiger of the Institute of Meteorology and Climate Research (IMK) of KIT explains. He is one of the first authors of the study. By means of closed collection tanks and so-called vapor capture systems, for instance, the gases released during operation can be collected and reduced significantly.

“The gas fields in the sparsely populated areas of North America are a good showcase for estimating the range of impacts of different extraction and fracking technologies,” explains Professor Johannes Orphal, Head of IMK. “In the densely populated Germany, framework conditions are much stricter and much more attention is paid to reducing and monitoring emissions.”

Fracking is increasingly discussed as a technology to extract fossil resources from unconventional deposits. Hydraulic breaking of suitable shale stone layers opens up the fossil fuels stored there and makes them accessible for economically efficient use. For this purpose, boreholes are drilled into these rock formations. Then, they are subjected to high pressure using large amounts of water and auxiliary materials, such as sand, cement, and chemicals. The oil or gas can flow to the surface through the opened microstructures in the rock. Typically, the return flow of the aqueous fracking liquid with the dissolved oil and gas constituents to the surface lasts several days until the production phase proper of purer oil or natural gas. This return flow is collected and then reused until it finally has to be disposed of. Air pollution mainly depends on the treatment of this return flow at the extraction plant. In this respect, currently practiced fracking technologies differ considerably. For the first time now, the resulting local atmospheric emissions were studied at a high temporary resolution. Based on the results, emissions can be assigned directly to the different plant sections of an extraction plant. For measurement, the newly developed, compact, and highly sensitive instrument, a so-called proton transfer reaction mass spectrometer (PTR-MS), of KIT was installed on board of a minivan and driven closer to the different extraction points, the distances being a few tens of meters. In this way, the waste gas plumes of individual extraction sources and fracking processes were studied in detail.

Warneke, C., Geiger, F., Edwards, P. M., Dube, W., Pétron, G., Kofler, J., Zahn, A., Brown, S. S., Graus, M., Gilman, J. B., Lerner, B. M., Peischl, J., Ryerson, T. B., de Gouw, J. A., and Roberts, J. M.: Volatile organic compound emissions from the oil and natural gas industry in the Uintah Basin, Utah: oil and gas well pad emissions compared to ambient air composition, Atmos. Chem. Phys., 14, 10977-10988, doi:10.5194/acp-14-10977-2014, 2014.

Technology-dependent emissions of gas extraction in the US

The KIT measurement instrument on board of a minivan directly measures atmospheric emissions on site with a high temporal resolution. -  Photo: F. Geiger/KIT
The KIT measurement instrument on board of a minivan directly measures atmospheric emissions on site with a high temporal resolution. – Photo: F. Geiger/KIT

Not all boreholes are the same. Scientists of the Karlsruhe Institute of Technology (KIT) used mobile measurement equipment to analyze gaseous compounds emitted by the extraction of oil and natural gas in the USA. For the first time, organic pollutants emitted during a fracking process were measured at a high temporal resolution. The highest values measured exceeded typical mean values in urban air by a factor of one thousand, as was reported in ACP journal. (DOI 10.5194/acp-14-10977-2014)

Emission of trace gases by oil and gas fields was studied by the KIT researchers in the USA (Utah and Colorado) together with US institutes. Background concentrations and the waste gas plumes of single extraction plants and fracking facilities were analyzed. The air quality measurements of several weeks duration took place under the “Uintah Basin Winter Ozone Study” coordinated by the National Oceanic and Atmospheric Administration (NOAA).

The KIT measurements focused on health-damaging aromatic hydrocarbons in air, such as carcinogenic benzene. Maximum concentrations were determined in the waste gas plumes of boreholes. Some extraction plants emitted up to about a hundred times more benzene than others. The highest values of some milligrams of benzene per cubic meter air were measured downstream of an open fracking facility, where returning drilling fluid is stored in open tanks and basins. Much better results were reached by oil and gas extraction plants and plants with closed production processes. In Germany, benzene concentration at the workplace is subject to strict limits: The Federal Emission Control Ordinance gives an annual benzene limit of five micrograms per cubic meter for the protection of human health, which is smaller than the values now measured at the open fracking facility in the US by a factor of about one thousand. The researchers published the results measured in the journal Atmospheric Chemistry and Physics ACP.

“Characteristic emissions of trace gases are encountered everywhere. These are symptomatic of gas and gas extraction. But the values measured for different technologies differ considerably,” Felix Geiger of the Institute of Meteorology and Climate Research (IMK) of KIT explains. He is one of the first authors of the study. By means of closed collection tanks and so-called vapor capture systems, for instance, the gases released during operation can be collected and reduced significantly.

“The gas fields in the sparsely populated areas of North America are a good showcase for estimating the range of impacts of different extraction and fracking technologies,” explains Professor Johannes Orphal, Head of IMK. “In the densely populated Germany, framework conditions are much stricter and much more attention is paid to reducing and monitoring emissions.”

Fracking is increasingly discussed as a technology to extract fossil resources from unconventional deposits. Hydraulic breaking of suitable shale stone layers opens up the fossil fuels stored there and makes them accessible for economically efficient use. For this purpose, boreholes are drilled into these rock formations. Then, they are subjected to high pressure using large amounts of water and auxiliary materials, such as sand, cement, and chemicals. The oil or gas can flow to the surface through the opened microstructures in the rock. Typically, the return flow of the aqueous fracking liquid with the dissolved oil and gas constituents to the surface lasts several days until the production phase proper of purer oil or natural gas. This return flow is collected and then reused until it finally has to be disposed of. Air pollution mainly depends on the treatment of this return flow at the extraction plant. In this respect, currently practiced fracking technologies differ considerably. For the first time now, the resulting local atmospheric emissions were studied at a high temporary resolution. Based on the results, emissions can be assigned directly to the different plant sections of an extraction plant. For measurement, the newly developed, compact, and highly sensitive instrument, a so-called proton transfer reaction mass spectrometer (PTR-MS), of KIT was installed on board of a minivan and driven closer to the different extraction points, the distances being a few tens of meters. In this way, the waste gas plumes of individual extraction sources and fracking processes were studied in detail.

Warneke, C., Geiger, F., Edwards, P. M., Dube, W., Pétron, G., Kofler, J., Zahn, A., Brown, S. S., Graus, M., Gilman, J. B., Lerner, B. M., Peischl, J., Ryerson, T. B., de Gouw, J. A., and Roberts, J. M.: Volatile organic compound emissions from the oil and natural gas industry in the Uintah Basin, Utah: oil and gas well pad emissions compared to ambient air composition, Atmos. Chem. Phys., 14, 10977-10988, doi:10.5194/acp-14-10977-2014, 2014.

Geologists shed light on formation of Alaska Range

Syracuse University Professor Paul Fitzgerald and a group of students have been studying the Alaska Range. -  Syracuse University
Syracuse University Professor Paul Fitzgerald and a group of students have been studying the Alaska Range. – Syracuse University

Geologists in Syracuse University’s College of Arts and Sciences have recently figured out what has caused the Alaska Range to form the way it has and why the range boasts such an enigmatic topographic signature. The narrow mountain range is home to some of the world’s most dramatic topography, including 20,320-foot Mount McKinley, North America’s highest mountain.

Professor Paul Fitzgerald and a team of students and fellow scientists have been studying the Alaska Range along the Denali fault. They think they know why the fault is located where it is and what accounts for the alternating asymmetrical, mountain-scale topography along the fault.

Their findings were the subject of a recent paper in the journal Tectonics (American Geophysical Union, 2014).

In 2002, the Denali fault, which cuts across south-central Alaska, was the site of a magnitude-7.9 earthquake and was felt as far away as Texas and Louisiana. It was the largest earthquake of its kind in more than 150 years.

“Following the earthquake, researchers flocked to the area to examine the effects,” says Fitzgerald, who serves as professor of Earth Sciences and an associate dean for the College. “They were fascinated by how the frozen ground behaved; the many landslides [the earthquake] caused; how bridges responded; and how the Trans-Alaska oil pipeline survived, as it was engineered to do so.”

Geologists were also surprised by how the earthquake began on a previously unknown thrust-fault; then propagated eastward, along the Denali fault, and finally jumped onto another fault, hundreds of kilometers away.

“From our perspective, the earthquake has motivated analyses of why the highest mountains in the central Alaska Range occur south of the Denali fault and the highest mountains in the eastern Alaska Range occur north of the fault–something that has puzzled us for years,” Fitzgerald adds. “It’s been an enigma staring us in the face.”

He attributes the Alaska Range’s alternating topographic signatures to a myriad of factors: contrasting lithospheric strength between large terranes (i.e., distinctly different rock units); the location of the curved Denali fault; the transfer of strain inland from southern Alaska’s active plate margin; and the shape of the controlling former continental margin against weaker suture-zone rocks.

It’s no secret that Alaska is one of the most geologically active areas on the planet. For instance, scientists know that the North American Plate is currently overriding the Pacific Plate at the latter’s southern coast, while the Yakutat microplate is colliding with North America.

As a result of plate tectonics, Alaska is an amalgamation of terranes that have collided with the North American craton and have accreted to become part of North America.

Cratons are pieces of continents that have been largely stable for hundreds of millions of years.

Terranes often originate as volcanic islands (like those of Hawaii) and, after colliding with one another or a continent, are separated by large discrete faults. When terranes collide and accrete, they form a suture, also known as a collision zone, which is made up of weak, crushed rock. During deformation, suture-zone rocks usually deform first, especially if they are adjacent to a strong rock body.

“Technically, the Denali fault is what we’d call an ‘intercontinental right-lateral strike-slip fault system,'” says Fitzgerald, adding that a strike-slip fault occurs when rocks move horizontally past one another, usually on a vertical fault. “This motion includes a component of slip along the fault and a component of normal motion against the fault that creates mountains. Hence, the shape of the fault determines which of the two components is predominant and where mountains form.”

In Alaska, the shape of the accreted terranes generally controls the location of the Denali fault and the mountains that form along it, especially at the bends in the trace of the fault.

Fitzgerald: “Mount McKinley and the central Alaska Range lie within the concave curve of the Denali fault. There, higher topography and greater exhumation [uplift of rock] occur south of the Denali fault, exactly where you’d expect a mountain range to form, given the regional tectonics. In the eastern Alaska Range, higher topography and greater exhumation are found north of the fault, on its convex side–not an expected pattern at all and very puzzling.”

Using mapped surface geology, geophysical data, and thermochronology (i.e., time-temperature history of the rocks), Fitzgerald and colleagues have determined that much of Alaska’s uplift and deformation began some 25 million years ago, when the Yakutat microplate first started colliding with North America. The bold, glacier-clad peaks comprising the Alaska Range actually derive from within the aforementioned “weak suture-zone rocks” between the terranes.

While mountains are high and give the impression of strength, they are built largely from previously fractured rock units. Rock movement along the Denali fault drives the uplift of the mountains, which form at bends in the fault, where previously fractured suture-zone rocks are pinned against the stronger former North American continental margin.

“The patterns of deformation help us understand regional tectonics and the formation of the Alaska Range, which is fascinating to geologists and non-geologists alike,” says Fitzgerald. “Being able to determine patterns or how to reveal them, while others see chaos, is often the key to finding the answer to complex problems. … To us scientists, the real significance of this work is that it helps us understand the evolution of our planet, how faults and mountain belts form, and why earthquakes happen. It also provides a number of hypotheses about Alaskan tectonics and rock deformation that we can test, using the Alaska Range as our laboratory.”

In addition to Fitzgerald, the paper was co-authored by Sarah Roeske, a research scientist at the University of California, Davis; Jeff Benowitz, a research scientist at the Geophysical Institute at the University of Alaska Fairbanks; Steven Riccio and Stephanie Perry, graduate students in Earth Sciences at Syracuse; and Phillip Armstrong, professor and chair of geological sciences at California State University, Fullerton.

Housed in Syracuse’s College of Arts and Sciences, the Department of Earth Sciences offers graduate and undergraduate degree opportunities in crustal evolution and tectonics, environmental sciences and climate change, hydrogeology, sedimentology and paleolimnology, geochemistry, and paleobiology.

Geologists shed light on formation of Alaska Range

Syracuse University Professor Paul Fitzgerald and a group of students have been studying the Alaska Range. -  Syracuse University
Syracuse University Professor Paul Fitzgerald and a group of students have been studying the Alaska Range. – Syracuse University

Geologists in Syracuse University’s College of Arts and Sciences have recently figured out what has caused the Alaska Range to form the way it has and why the range boasts such an enigmatic topographic signature. The narrow mountain range is home to some of the world’s most dramatic topography, including 20,320-foot Mount McKinley, North America’s highest mountain.

Professor Paul Fitzgerald and a team of students and fellow scientists have been studying the Alaska Range along the Denali fault. They think they know why the fault is located where it is and what accounts for the alternating asymmetrical, mountain-scale topography along the fault.

Their findings were the subject of a recent paper in the journal Tectonics (American Geophysical Union, 2014).

In 2002, the Denali fault, which cuts across south-central Alaska, was the site of a magnitude-7.9 earthquake and was felt as far away as Texas and Louisiana. It was the largest earthquake of its kind in more than 150 years.

“Following the earthquake, researchers flocked to the area to examine the effects,” says Fitzgerald, who serves as professor of Earth Sciences and an associate dean for the College. “They were fascinated by how the frozen ground behaved; the many landslides [the earthquake] caused; how bridges responded; and how the Trans-Alaska oil pipeline survived, as it was engineered to do so.”

Geologists were also surprised by how the earthquake began on a previously unknown thrust-fault; then propagated eastward, along the Denali fault, and finally jumped onto another fault, hundreds of kilometers away.

“From our perspective, the earthquake has motivated analyses of why the highest mountains in the central Alaska Range occur south of the Denali fault and the highest mountains in the eastern Alaska Range occur north of the fault–something that has puzzled us for years,” Fitzgerald adds. “It’s been an enigma staring us in the face.”

He attributes the Alaska Range’s alternating topographic signatures to a myriad of factors: contrasting lithospheric strength between large terranes (i.e., distinctly different rock units); the location of the curved Denali fault; the transfer of strain inland from southern Alaska’s active plate margin; and the shape of the controlling former continental margin against weaker suture-zone rocks.

It’s no secret that Alaska is one of the most geologically active areas on the planet. For instance, scientists know that the North American Plate is currently overriding the Pacific Plate at the latter’s southern coast, while the Yakutat microplate is colliding with North America.

As a result of plate tectonics, Alaska is an amalgamation of terranes that have collided with the North American craton and have accreted to become part of North America.

Cratons are pieces of continents that have been largely stable for hundreds of millions of years.

Terranes often originate as volcanic islands (like those of Hawaii) and, after colliding with one another or a continent, are separated by large discrete faults. When terranes collide and accrete, they form a suture, also known as a collision zone, which is made up of weak, crushed rock. During deformation, suture-zone rocks usually deform first, especially if they are adjacent to a strong rock body.

“Technically, the Denali fault is what we’d call an ‘intercontinental right-lateral strike-slip fault system,'” says Fitzgerald, adding that a strike-slip fault occurs when rocks move horizontally past one another, usually on a vertical fault. “This motion includes a component of slip along the fault and a component of normal motion against the fault that creates mountains. Hence, the shape of the fault determines which of the two components is predominant and where mountains form.”

In Alaska, the shape of the accreted terranes generally controls the location of the Denali fault and the mountains that form along it, especially at the bends in the trace of the fault.

Fitzgerald: “Mount McKinley and the central Alaska Range lie within the concave curve of the Denali fault. There, higher topography and greater exhumation [uplift of rock] occur south of the Denali fault, exactly where you’d expect a mountain range to form, given the regional tectonics. In the eastern Alaska Range, higher topography and greater exhumation are found north of the fault, on its convex side–not an expected pattern at all and very puzzling.”

Using mapped surface geology, geophysical data, and thermochronology (i.e., time-temperature history of the rocks), Fitzgerald and colleagues have determined that much of Alaska’s uplift and deformation began some 25 million years ago, when the Yakutat microplate first started colliding with North America. The bold, glacier-clad peaks comprising the Alaska Range actually derive from within the aforementioned “weak suture-zone rocks” between the terranes.

While mountains are high and give the impression of strength, they are built largely from previously fractured rock units. Rock movement along the Denali fault drives the uplift of the mountains, which form at bends in the fault, where previously fractured suture-zone rocks are pinned against the stronger former North American continental margin.

“The patterns of deformation help us understand regional tectonics and the formation of the Alaska Range, which is fascinating to geologists and non-geologists alike,” says Fitzgerald. “Being able to determine patterns or how to reveal them, while others see chaos, is often the key to finding the answer to complex problems. … To us scientists, the real significance of this work is that it helps us understand the evolution of our planet, how faults and mountain belts form, and why earthquakes happen. It also provides a number of hypotheses about Alaskan tectonics and rock deformation that we can test, using the Alaska Range as our laboratory.”

In addition to Fitzgerald, the paper was co-authored by Sarah Roeske, a research scientist at the University of California, Davis; Jeff Benowitz, a research scientist at the Geophysical Institute at the University of Alaska Fairbanks; Steven Riccio and Stephanie Perry, graduate students in Earth Sciences at Syracuse; and Phillip Armstrong, professor and chair of geological sciences at California State University, Fullerton.

Housed in Syracuse’s College of Arts and Sciences, the Department of Earth Sciences offers graduate and undergraduate degree opportunities in crustal evolution and tectonics, environmental sciences and climate change, hydrogeology, sedimentology and paleolimnology, geochemistry, and paleobiology.

New tracers can identify frack fluids in the environment

Scientists have developed new geochemical tracers that can identify hydraulic fracturing flowback fluids that have been spilled or released into the environment.

The tracers, which were created by a team of U.S. and French researchers, have been field-tested at a spill site in West Virginia and downstream from an oil and gas brine wastewater treatment plant in Pennsylvania.

“This gives us new forensic tools to detect if ‘frac fluids’ are escaping into our water supply and what risks, if any, they might pose,” said Duke University geochemist Avner Vengosh, who co-led the research.

“By characterizing the isotopic and geochemical fingerprints of enriched boron and lithium in flowback water from hydraulic fracturing, we can now track the presence of frac fluids in the environment and distinguish them from wastewater coming from other sources, including conventional oil and gas wells,” Vengosh said.

Using the tracers, scientists can determine where fracturing fluids have or haven’t been released to the environment and, ultimately, help identify ways to improve how shale gas wastewater is treated and disposed of.

Vengosh and his colleagues published their peer-reviewed findings October 20 in the journal Environmental Science & Technology. Their study, which was funded in part by the National Science Foundation, is the first to report on the development of the boron and lithium tracers.

Nathaniel R. Warner, Obering Postdoctoral Fellow at Dartmouth College, was lead author of the study. “This new technology can be combined with other methods to identify specific instances of accidental releases to surface waters in areas of unconventional drilling,” he said. “It could benefit industry as well as federal and state agencies charged with monitoring water quality and protecting the environment.”

Hydraulic fracturing fluids, or frac fluids, typically contain mixes of water, proprietary chemicals and sand. Mixtures can vary from site to site. Drillers inject large volumes of the fluids down gas wells at high pressure to crack open shale formations deep underground and allow natural gas trapped within the shale to flow out and be extracted. After the shale has been fractured, the frac fluids flow back up the well to the surface along with the gas and highly saline brines from the shale formation.

Some people fear that toxic frac fluid chemicals in this flowback could contaminate nearby water supplies if flowback were accidentally spilled or insufficiently treated before being disposed of.

“The flowback fluid that returns to the surface becomes a waste that needs to be managed,” Vengosh explained. “Deep-well injection is the preferable disposal method, but injecting large volumes of wastewater into deep wells can cause earthquakes in sensitive areas and is not geologically available in some states. In Pennsylvania, much of the flowback is now recycled and reused, but a significant amount of it is still discharged into local streams or rivers.”

Vengosh said it’s possible to identify the presence of frac fluid in spilled or discharged flowback by tracing synthetic organic compounds that are added to the fluid before it’s injected down a well. But the proprietary nature of these chemicals, combined with their instability in the environment, limits the usefulness of such tracers.

By contrast, the new boron and lithium tracers remain stable in the environment. “The difference is that we are using tracers based on elements that occur naturally in shale formations,” Vengosh said.

When drillers inject frac fluids into a shale formation, they not only release hydrocarbon but also boron and lithium that are attached to clay minerals within the formation, he explained. As the fluids react and mix at depth, they become enriched in boron and lithium. As they are brought back to the surface, they have distinctive isotopic fingerprints that are different from other types of wastewater, including wastewater from a conventional gas or oil well, as well as from naturally occurring background water.

“This type of forensic research allows us to clearly delineate between the possible sources of wastewater contamination,” Vengosh said.

New tracers can identify frack fluids in the environment

Scientists have developed new geochemical tracers that can identify hydraulic fracturing flowback fluids that have been spilled or released into the environment.

The tracers, which were created by a team of U.S. and French researchers, have been field-tested at a spill site in West Virginia and downstream from an oil and gas brine wastewater treatment plant in Pennsylvania.

“This gives us new forensic tools to detect if ‘frac fluids’ are escaping into our water supply and what risks, if any, they might pose,” said Duke University geochemist Avner Vengosh, who co-led the research.

“By characterizing the isotopic and geochemical fingerprints of enriched boron and lithium in flowback water from hydraulic fracturing, we can now track the presence of frac fluids in the environment and distinguish them from wastewater coming from other sources, including conventional oil and gas wells,” Vengosh said.

Using the tracers, scientists can determine where fracturing fluids have or haven’t been released to the environment and, ultimately, help identify ways to improve how shale gas wastewater is treated and disposed of.

Vengosh and his colleagues published their peer-reviewed findings October 20 in the journal Environmental Science & Technology. Their study, which was funded in part by the National Science Foundation, is the first to report on the development of the boron and lithium tracers.

Nathaniel R. Warner, Obering Postdoctoral Fellow at Dartmouth College, was lead author of the study. “This new technology can be combined with other methods to identify specific instances of accidental releases to surface waters in areas of unconventional drilling,” he said. “It could benefit industry as well as federal and state agencies charged with monitoring water quality and protecting the environment.”

Hydraulic fracturing fluids, or frac fluids, typically contain mixes of water, proprietary chemicals and sand. Mixtures can vary from site to site. Drillers inject large volumes of the fluids down gas wells at high pressure to crack open shale formations deep underground and allow natural gas trapped within the shale to flow out and be extracted. After the shale has been fractured, the frac fluids flow back up the well to the surface along with the gas and highly saline brines from the shale formation.

Some people fear that toxic frac fluid chemicals in this flowback could contaminate nearby water supplies if flowback were accidentally spilled or insufficiently treated before being disposed of.

“The flowback fluid that returns to the surface becomes a waste that needs to be managed,” Vengosh explained. “Deep-well injection is the preferable disposal method, but injecting large volumes of wastewater into deep wells can cause earthquakes in sensitive areas and is not geologically available in some states. In Pennsylvania, much of the flowback is now recycled and reused, but a significant amount of it is still discharged into local streams or rivers.”

Vengosh said it’s possible to identify the presence of frac fluid in spilled or discharged flowback by tracing synthetic organic compounds that are added to the fluid before it’s injected down a well. But the proprietary nature of these chemicals, combined with their instability in the environment, limits the usefulness of such tracers.

By contrast, the new boron and lithium tracers remain stable in the environment. “The difference is that we are using tracers based on elements that occur naturally in shale formations,” Vengosh said.

When drillers inject frac fluids into a shale formation, they not only release hydrocarbon but also boron and lithium that are attached to clay minerals within the formation, he explained. As the fluids react and mix at depth, they become enriched in boron and lithium. As they are brought back to the surface, they have distinctive isotopic fingerprints that are different from other types of wastewater, including wastewater from a conventional gas or oil well, as well as from naturally occurring background water.

“This type of forensic research allows us to clearly delineate between the possible sources of wastewater contamination,” Vengosh said.