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.

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.

Aiming to improve the air quality in underground mines

Reducing diesel particulate matter emitted by the diesel powered vehicles used for underground mine work is the aim of researchers from Monash University. -  Monash University
Reducing diesel particulate matter emitted by the diesel powered vehicles used for underground mine work is the aim of researchers from Monash University. – Monash University

Reducing diesel particulate matter (DPM) exposure to miners in underground coalmines will be a step closer to reality with the awarding of a research grant to engineers from Monash University.

The $275,000 grant from the Australian Coal Association Research Programme (ACARP) goes to a multi-disciplinary team from the Maintenance Technology Institute (MTI), the Laboratory for Turbulence Research in Aerospace and Combustion (LTRAC) and the Australian Pulp and Paper Institute (APPI).

The grant will allow them to collaborate with leading industry original equipment manufacturers and mine site personnel as part of a broader long-term strategy to minimise DPM emissions in the mining industry.

Joint project leader Associate Professor Damon Honnery said it was important to find a way to reduce miners exposure to DPM which is both effective and cost efficient.

“DPM has recently been classified as a Group 1 carcinogen by the World Health Organisation, and is a significant problem for operators of underground coalmines,” Associate Professor Honnery said.

“Diesel powered vehicles are widely used for underground mine work and are generally fitted with diesel particulate filters (DPFs) to reduce particulate emissions which have very limited service life – typically around one or two shifts – resulting in excessive costs and ineffective control of DPM.”

The new project will complement an earlier ACARP project by the team that focussed on improving the service life of DPFs used in underground coalmines, which found reconditioned filters could be reused up to five times without compromising filter integrity or DPM filtration efficiency.

Fellow Project leader Dr Daya Dayawansa said while the earlier results offer a viable short-term solution to the DPM problem, a medium-term solution requires the careful examination and possible redesign of the entire exhaust conditioning system, in combination with improved diesel particulate filters.

Ultimately, the researchers believe that many diesel engines used in underground mining could be replaced by electric motors, despite the stringent regulations relating to electric systems in the potentially explosive underground atmosphere.

“While filter use will continue to reduce the impact of DPM emission in underground mines, the only truly effective long term solution is to remove the source from the mines altogether. Working with our partners, we hope to achieve this through the development of electric powered vehicles,” Dr Dayawansa said.

Aiming to improve the air quality in underground mines

Reducing diesel particulate matter emitted by the diesel powered vehicles used for underground mine work is the aim of researchers from Monash University. -  Monash University
Reducing diesel particulate matter emitted by the diesel powered vehicles used for underground mine work is the aim of researchers from Monash University. – Monash University

Reducing diesel particulate matter (DPM) exposure to miners in underground coalmines will be a step closer to reality with the awarding of a research grant to engineers from Monash University.

The $275,000 grant from the Australian Coal Association Research Programme (ACARP) goes to a multi-disciplinary team from the Maintenance Technology Institute (MTI), the Laboratory for Turbulence Research in Aerospace and Combustion (LTRAC) and the Australian Pulp and Paper Institute (APPI).

The grant will allow them to collaborate with leading industry original equipment manufacturers and mine site personnel as part of a broader long-term strategy to minimise DPM emissions in the mining industry.

Joint project leader Associate Professor Damon Honnery said it was important to find a way to reduce miners exposure to DPM which is both effective and cost efficient.

“DPM has recently been classified as a Group 1 carcinogen by the World Health Organisation, and is a significant problem for operators of underground coalmines,” Associate Professor Honnery said.

“Diesel powered vehicles are widely used for underground mine work and are generally fitted with diesel particulate filters (DPFs) to reduce particulate emissions which have very limited service life – typically around one or two shifts – resulting in excessive costs and ineffective control of DPM.”

The new project will complement an earlier ACARP project by the team that focussed on improving the service life of DPFs used in underground coalmines, which found reconditioned filters could be reused up to five times without compromising filter integrity or DPM filtration efficiency.

Fellow Project leader Dr Daya Dayawansa said while the earlier results offer a viable short-term solution to the DPM problem, a medium-term solution requires the careful examination and possible redesign of the entire exhaust conditioning system, in combination with improved diesel particulate filters.

Ultimately, the researchers believe that many diesel engines used in underground mining could be replaced by electric motors, despite the stringent regulations relating to electric systems in the potentially explosive underground atmosphere.

“While filter use will continue to reduce the impact of DPM emission in underground mines, the only truly effective long term solution is to remove the source from the mines altogether. Working with our partners, we hope to achieve this through the development of electric powered vehicles,” Dr Dayawansa said.

First-ever 3D image created of the structure beneath Sierra Negra volcano

This is a photo of the Sierra Negra volcano on Isabela Island in the Galápagos Archipelago. -  Cynthia Ebinger, University of Rochester
This is a photo of the Sierra Negra volcano on Isabela Island in the Galápagos Archipelago. – Cynthia Ebinger, University of Rochester

The Galápagos Islands are home to some of the most active volcanoes in the world, with more than 50 eruptions in the last 200 years. Yet until recently, scientists knew far more about the history of finches, tortoises, and iguanas than of the volcanoes on which these unusual fauna had evolved.

Now research out of the University of Rochester is providing a better picture of the subterranean plumbing system that feeds the Galápagos volcanoes, as well as a major difference with another Pacific Island chain-the Hawaiian Islands. The findings have been published in the Journal of Geophysical Research: Solid Earth.

“With a better understanding of what’s beneath the volcanoes, we’ll now be able to more accurately measure underground activity,” said Cynthia Ebinger, a professor of earth and environmental sciences. “That should help us better anticipate earthquakes and eruptions, and mitigate the hazards associated with them.”

Ebinger’s team, which included Mario Ruiz from the Instituto Geofisico Escuela Politecnica Nacional in Quito, Ecuador, buried 15 seismometers around Sierra Negra, the largest and most active volcano in the Galápagos. The equipment was used to measure the velocity and direction of different sound waves generated by earthquakes as they traveled under Sierra Negra. Since the behavior of the waves varies according to the temperature and types of material they’re passing through, the data collected allowed the researchers to construct a 3D image of the plumbing system beneath the volcano, using a technique similar to a CAT-scan.

Five kilometers down is the beginning of a large magma chamber lying partially within old oceanic crust that had been buried by more than 8 km of eruptive rock layers. And the oceanic crust has what appears to be a thick underplating of rock formed when magma that was working its way toward the surface became trapped under the crust and cooled-very much like the processes that occur under the Hawaiian Islands.

The researchers found that the Galápagos had something else in common with the Hawaiian Islands. Their data suggest the presence of a large chamber filled with crystal-mush magma-cooled magma that includes crystallized minerals.

The Galápagos Islands formed from a hotspot of magma located in an oceanic plate-called Nazca-about 600 miles of Ecuador, in a process very similar to how the Hawaiian Islands were created. Magma rising from the hotspot eventually hardened into an island. Then, as the Nazca plate inched its way westward, new islands formed in the same manner, resulting in the present-day Galápagos Archipelago.

While there are several similarities between the two island chains, Ebinger uncovered a major difference. The older volcanos in the Hawaiian Islands are dormant, because they’ve moved away from the hotspot that provided the source of magma. In the Galápagos, the volcanoes are connected to the same plumbing system. By studying satellite views of the volcanoes, Ebinger and colleagues noticed that, as the magma would sink in one, it would rise in a different volcano-indicating that that some of the youngest volcanoes had magma connections, even if those connections were temporary.

“Not only do we have a better understanding of the physical properties of Sierra Negra,” said Ebinger, “we have increased out knowledge of island volcano systems, in general.”

The Galápagos Islands are home to some of the most active volcanoes in the world, with more than 50 eruptions in the last 200 years. Yet until recently, scientists knew far more about the history of finches, tortoises, and iguanas than of the volcanoes on which these unusual fauna had evolved.

Now research out of the University of Rochester is providing a better picture of the subterranean plumbing system that feeds the Galápagos volcanoes, as well as a major difference with another Pacific Island chain-the Hawaiian Islands.

First-ever 3D image created of the structure beneath Sierra Negra volcano

This is a photo of the Sierra Negra volcano on Isabela Island in the Galápagos Archipelago. -  Cynthia Ebinger, University of Rochester
This is a photo of the Sierra Negra volcano on Isabela Island in the Galápagos Archipelago. – Cynthia Ebinger, University of Rochester

The Galápagos Islands are home to some of the most active volcanoes in the world, with more than 50 eruptions in the last 200 years. Yet until recently, scientists knew far more about the history of finches, tortoises, and iguanas than of the volcanoes on which these unusual fauna had evolved.

Now research out of the University of Rochester is providing a better picture of the subterranean plumbing system that feeds the Galápagos volcanoes, as well as a major difference with another Pacific Island chain-the Hawaiian Islands. The findings have been published in the Journal of Geophysical Research: Solid Earth.

“With a better understanding of what’s beneath the volcanoes, we’ll now be able to more accurately measure underground activity,” said Cynthia Ebinger, a professor of earth and environmental sciences. “That should help us better anticipate earthquakes and eruptions, and mitigate the hazards associated with them.”

Ebinger’s team, which included Mario Ruiz from the Instituto Geofisico Escuela Politecnica Nacional in Quito, Ecuador, buried 15 seismometers around Sierra Negra, the largest and most active volcano in the Galápagos. The equipment was used to measure the velocity and direction of different sound waves generated by earthquakes as they traveled under Sierra Negra. Since the behavior of the waves varies according to the temperature and types of material they’re passing through, the data collected allowed the researchers to construct a 3D image of the plumbing system beneath the volcano, using a technique similar to a CAT-scan.

Five kilometers down is the beginning of a large magma chamber lying partially within old oceanic crust that had been buried by more than 8 km of eruptive rock layers. And the oceanic crust has what appears to be a thick underplating of rock formed when magma that was working its way toward the surface became trapped under the crust and cooled-very much like the processes that occur under the Hawaiian Islands.

The researchers found that the Galápagos had something else in common with the Hawaiian Islands. Their data suggest the presence of a large chamber filled with crystal-mush magma-cooled magma that includes crystallized minerals.

The Galápagos Islands formed from a hotspot of magma located in an oceanic plate-called Nazca-about 600 miles of Ecuador, in a process very similar to how the Hawaiian Islands were created. Magma rising from the hotspot eventually hardened into an island. Then, as the Nazca plate inched its way westward, new islands formed in the same manner, resulting in the present-day Galápagos Archipelago.

While there are several similarities between the two island chains, Ebinger uncovered a major difference. The older volcanos in the Hawaiian Islands are dormant, because they’ve moved away from the hotspot that provided the source of magma. In the Galápagos, the volcanoes are connected to the same plumbing system. By studying satellite views of the volcanoes, Ebinger and colleagues noticed that, as the magma would sink in one, it would rise in a different volcano-indicating that that some of the youngest volcanoes had magma connections, even if those connections were temporary.

“Not only do we have a better understanding of the physical properties of Sierra Negra,” said Ebinger, “we have increased out knowledge of island volcano systems, in general.”

The Galápagos Islands are home to some of the most active volcanoes in the world, with more than 50 eruptions in the last 200 years. Yet until recently, scientists knew far more about the history of finches, tortoises, and iguanas than of the volcanoes on which these unusual fauna had evolved.

Now research out of the University of Rochester is providing a better picture of the subterranean plumbing system that feeds the Galápagos volcanoes, as well as a major difference with another Pacific Island chain-the Hawaiian Islands.

World’s first magma-enhanced geothermal system created in Iceland

This image shows a flow test of the IDDP-1 well at Krafla. Note the transparent superheated steam at the top of the rock muffler. -  Kristján Einarsson.
This image shows a flow test of the IDDP-1 well at Krafla. Note the transparent superheated steam at the top of the rock muffler. – Kristján Einarsson.

In 2009, a borehole drilled at Krafla, northeast Iceland, as part of the Icelandic Deep Drilling Project (IDDP), unexpectedly penetrated into magma (molten rock) at only 2100 meters depth, with a temperature of 900-1000 C. The borehole, IDDP-1, was the first in a series of wells being drilled by the IDDP in Iceland in the search for high-temperature geothermal resources.

The January 2014 issue of the international journal Geothermics is dedicated to scientific and engineering results arising from that unusual occurrence. This issue is edited by Wilfred Elders, a professor emeritus of geology at the University of California, Riverside, who also co-authored three of the research papers in the special issue with Icelandic colleagues.

“Drilling into magma is a very rare occurrence anywhere in the world and this is only the second known instance, the first one, in 2007, being in Hawaii,” Elders said. “The IDDP, in cooperation with Iceland’s National Power Company, the operator of the Krafla geothermal power plant, decided to investigate the hole further and bear part of the substantial costs involved.”

Accordingly, a steel casing, perforated in the bottom section closest to the magma, was cemented into the well. The hole was then allowed to heat slowly and eventually allowed to flow superheated steam for the next two years, until July 2012, when it was closed down in order to replace some of the surface equipment.

“In the future, the success of this drilling and research project could lead to a revolution in the energy efficiency of high-temperature geothermal areas worldwide,” Elders said.

He added that several important milestones were achieved in this project: despite some difficulties, the project was able to drill down into the molten magma and control it; it was possible to set steel casing in the bottom of the hole; allowing the hole to blow superheated, high-pressure steam for months at temperatures exceeding 450 C, created a world record for geothermal heat (this well was the hottest in the world and one of the most powerful); steam from the IDDP-1 well could be fed directly into the existing power plant at Krafla; and the IDDP-1 demonstrated that a high-enthalpy geothermal system could be successfully utilized.

“Essentially, the IDDP-1 created the world’s first magma-enhanced geothermal system,” Elders said. “This unique engineered geothermal system is the world’s first to supply heat directly from a molten magma.”

Elders explained that in various parts of the world so-called enhanced or engineered geothermal systems are being created by pumping cold water into hot dry rocks at 4-5 kilometers depths. The heated water is pumped up again as hot water or steam from production wells. In recent decades, considerable effort has been invested in Europe, Australia, the United States, and Japan, with uneven, and typically poor, results.

“Although the IDDP-1 hole had to be shut in, the aim now is to repair the well or to drill a new similar hole,” Elders said. “The experiment at Krafla suffered various setbacks that tried personnel and equipment throughout. However, the process itself was very instructive, and, apart from scientific articles published in Geothermics, comprehensive reports on practical lessons learned are nearing completion.”

The IDDP is a collaboration of three energy companies – HS Energy Ltd., National Power Company and Reykjavik Energy – and a government agency, the National Energy Authority of Iceland. It will drill the next borehole, IDDP-2, in southwest Iceland at Reykjanes in 2014-2015. From the onset, international collaboration has been important to the project, and in particular a consortium of U.S. scientists, coordinated by Elders, has been very active, authoring several research papers in the special issue of Geothermics.

World’s first magma-enhanced geothermal system created in Iceland

This image shows a flow test of the IDDP-1 well at Krafla. Note the transparent superheated steam at the top of the rock muffler. -  Kristján Einarsson.
This image shows a flow test of the IDDP-1 well at Krafla. Note the transparent superheated steam at the top of the rock muffler. – Kristján Einarsson.

In 2009, a borehole drilled at Krafla, northeast Iceland, as part of the Icelandic Deep Drilling Project (IDDP), unexpectedly penetrated into magma (molten rock) at only 2100 meters depth, with a temperature of 900-1000 C. The borehole, IDDP-1, was the first in a series of wells being drilled by the IDDP in Iceland in the search for high-temperature geothermal resources.

The January 2014 issue of the international journal Geothermics is dedicated to scientific and engineering results arising from that unusual occurrence. This issue is edited by Wilfred Elders, a professor emeritus of geology at the University of California, Riverside, who also co-authored three of the research papers in the special issue with Icelandic colleagues.

“Drilling into magma is a very rare occurrence anywhere in the world and this is only the second known instance, the first one, in 2007, being in Hawaii,” Elders said. “The IDDP, in cooperation with Iceland’s National Power Company, the operator of the Krafla geothermal power plant, decided to investigate the hole further and bear part of the substantial costs involved.”

Accordingly, a steel casing, perforated in the bottom section closest to the magma, was cemented into the well. The hole was then allowed to heat slowly and eventually allowed to flow superheated steam for the next two years, until July 2012, when it was closed down in order to replace some of the surface equipment.

“In the future, the success of this drilling and research project could lead to a revolution in the energy efficiency of high-temperature geothermal areas worldwide,” Elders said.

He added that several important milestones were achieved in this project: despite some difficulties, the project was able to drill down into the molten magma and control it; it was possible to set steel casing in the bottom of the hole; allowing the hole to blow superheated, high-pressure steam for months at temperatures exceeding 450 C, created a world record for geothermal heat (this well was the hottest in the world and one of the most powerful); steam from the IDDP-1 well could be fed directly into the existing power plant at Krafla; and the IDDP-1 demonstrated that a high-enthalpy geothermal system could be successfully utilized.

“Essentially, the IDDP-1 created the world’s first magma-enhanced geothermal system,” Elders said. “This unique engineered geothermal system is the world’s first to supply heat directly from a molten magma.”

Elders explained that in various parts of the world so-called enhanced or engineered geothermal systems are being created by pumping cold water into hot dry rocks at 4-5 kilometers depths. The heated water is pumped up again as hot water or steam from production wells. In recent decades, considerable effort has been invested in Europe, Australia, the United States, and Japan, with uneven, and typically poor, results.

“Although the IDDP-1 hole had to be shut in, the aim now is to repair the well or to drill a new similar hole,” Elders said. “The experiment at Krafla suffered various setbacks that tried personnel and equipment throughout. However, the process itself was very instructive, and, apart from scientific articles published in Geothermics, comprehensive reports on practical lessons learned are nearing completion.”

The IDDP is a collaboration of three energy companies – HS Energy Ltd., National Power Company and Reykjavik Energy – and a government agency, the National Energy Authority of Iceland. It will drill the next borehole, IDDP-2, in southwest Iceland at Reykjanes in 2014-2015. From the onset, international collaboration has been important to the project, and in particular a consortium of U.S. scientists, coordinated by Elders, has been very active, authoring several research papers in the special issue of Geothermics.