Space-based methane maps find largest US signal in Southwest

An unexpectedly high amount of the climate-changing gas methane, the main component of natural gas, is escaping from the Four Corners region in the U.S. Southwest, according to a new study by the University of Michigan and NASA.

The researchers mapped satellite data to uncover the nation’s largest methane signal seen from space. They measured levels of the gas emitted from all sources, and found more than half a teragram per year coming from the area where Arizona, New Mexico, Colorado and Utah meet. That’s about as much methane as the entire coal, oil, and gas industries of the United Kingdom give off each year.

Four Corners sits on North America’s most productive coalbed methane basin. Coalbed methane is a variety of the gas that’s stuck to the surface of coal. It is dangerous to miners (not to mention canaries), but in recent decades, it’s been tapped as a resource.

“There’s so much coalbed methane in the Four Corners area, it doesn’t need to be that crazy of a leak rate to produce the emissions that we see. A lot of the infrastructure is likely contributing,” said Eric Kort, assistant professor of atmospheric, oceanic and space sciences at the U-M College of Engineering.

Kort, first author of a paper on the findings published in Geophysical Research Letters, says the controversial natural gas extraction technique of hydraulic fracturing is not the main culprit.

“We see this large signal and it’s persistent since 2003,” Kort said. “That’s a pre- fracking timeframe in this region. While fracking has become a focal point in conversations about methane emissions, it certainly appears from this and other studies that in the U.S., fossil fuel extraction activities across the board likely emit higher than inventory estimates.”

While the signal represents the highest concentration of methane seen from space, the researchers caution that Four Corners isn’t necessarily the highest emitting region.

“One has to be somewhat careful in equating abundances with emissions,” said study contributor Christian Frankenberg at Jet Propulsion Laboratory. “The Four Corners methane source is in a relatively isolated area with little other methane emissions, hence causing a well distinguishable hot-spot in methane abundances. Local or more diffuse emissions in other areas, such as the eastern U.S., may be convoluted with other nearby sources

Natural gas is often touted as more sustainable than coal and oil because it releases fewer pollutants when it burns. But when it leaks into the air before it gets to the pilot light, methane has 30 times the short-term heat-trapping effects of carbon dioxide. Policymakers, energy companies and environmentalists alike are aiming to reduce methane emissions as a way to curb climate change. But pinpointing plumes—a first step to stopping them—has been a difficult task with today’s tools.

The research team demonstrated a new approach to finding leaks. They used a satellite instrument—the European Space Agency’s SCIAMACHY—to get regional methane measurements over the entire United States. They ran the data through a mathematical model to account for mountains and valleys, which can trap methane. That’s how they identified the anomaly at Four Corners. Then they zoomed in on that region and ran another mathematical model to control for wind, to make sure that didn’t negate the original signal. It didn’t.

“We didn’t know this was a region we should look at. We found it from space,” Kort said. “We’ve demonstrated that satellite measurements can help identify, locate and quantify anomalous methane emissions in regions that are unexpected.”

Methane gets into the atmosphere from both natural and human-made sources. Wetlands and landfills release it, as do certain bacteria. Agriculture is a big contributor. So are gas and oil drilling and distribution. Inventories such as those the EPA compiles make estimates based on measurements from a sampling of these sources. In previous work, air measurements from planes and a sparse network of monitoring towers have revealed that the inventory-based numbers are coming in low—roughly 50 percent low. But towers and planes can’t see everywhere to figure out exactly where all the methane is coming from. With limited observations there can be blind spots, the researchers say.

This study used satellite data from 2003 to 2009. In later years, they were able to validate the satellite measurements with a year of ground-based data.

SCIAMACHY is no longer operating, so there aren’t equivalent satellites to provide this information for other parts of the world. For the Four Corners region, Kort will be taking readings from an airplane next year, to get even closer to identifying the leaks.

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The study is titled “Four Corners: the largest US methane anomaly viewed from space.” The research was funded by NASA and Los Alamos National Lab.

Eric Kort: http://aoss.engin.umich.edu/people/eakort

Abstract: http://onlinelibrary.wiley.com/doi/10.1002/2014GL061503/abstract

Fracking’s environmental impacts scrutinized

Greenhouse gas emissions from the production and use of shale gas would be comparable to conventional natural gas, but the controversial energy source actually faired better than renewables on some environmental impacts, according to new research.

The UK holds enough shale gas to supply its entire gas demand for 470 years, promising to solve the country’s energy crisis and end its reliance on fossil-fuel imports from unstable markets. But for many, including climate scientists and environmental groups, shale gas exploitation is viewed as environmentally dangerous and would result in the UK reneging on its greenhouse gas reduction obligations under the Climate Change Act.

University of Manchester scientists have now conducted one of the most thorough examinations of the likely environmental impacts of shale gas exploitation in the UK in a bid to inform the debate. Their research has just been published in the leading academic journal Applied Energy and study lead author, Professor Adisa Azapagic, will outline the findings at the Labour Party Conference in Manchester, England, today (Monday, 22 September).

“While exploration is currently ongoing in the UK, commercial extraction of shale gas has not yet begun, yet its potential has stirred controversy over its environmental impacts, its safety and the difficulty of justifying its use to a nation conscious of climate change,” said Professor Azapagic.

“There are many unknowns in the debate surrounding shale gas, so we have attempted to address some of these unknowns by estimating its life cycle environmental impacts from ‘cradle to grave’. We looked at 11 different impacts from the extraction of shale gas using hydraulic fracturing – known as ‘fracking’- as well as from its processing and use to generate electricity.”

The researchers compared shale gas to other fossil-fuel alternatives, such as conventional natural gas and coal, as well as low-carbon options, including nuclear, offshore wind and solar power (solar photovoltaics).

The results of the research suggest that the average emissions of greenhouse gases from shale gas over its entire life cycle are about 460 grams of carbon dioxide-equivalent per kilowatt-hour of electricity generated. This, the authors say, is comparable to the emissions from conventional natural gas. For most of the other life-cycle environmental impacts considered by the team, shale gas was also comparable to conventional natural gas.

But the study also found that shale gas was better than offshore wind and solar for four out of 11 impacts: depletion of natural resources, toxicity to humans, as well as the impact on freshwater and marine organisms. Additionally, shale gas was better than solar (but not wind) for ozone layer depletion and eutrophication (the effect of nutrients such as phosphates, on natural ecosystems).

On the other hand, shale gas was worse than coal for three impacts: ozone layer depletion, summer smog and terrestrial eco-toxicity.

Professor Azapagic said: “Some of the impacts of solar power are actually relatively high, so it is not a complete surprise that shale gas is better in a few cases. This is mainly because manufacturing solar panels is very energy and resource-intensive, while their electrical output is quite low in a country like the UK, as we don’t have as much sunshine. However, our research shows that the environmental impacts of shale gas can vary widely, depending on the assumptions for various parameters, including the composition and volume of the fracking fluid used, disposal routes for the drilling waste and the amount of shale gas that can be recovered from a well.

“Assuming the worst case conditions, several of the environmental impacts from shale gas could be worse than from any other options considered in the research, including coal. But, under the best-case conditions, shale gas may be preferable to imported liquefied natural gas.”

The authors say their results highlight the need for tight regulation of shale gas exploration – weak regulation, they claim, may result in shale gas having higher impacts than coal power, resulting in a failure to meet climate change and sustainability imperatives and undermining the deployment of low-carbon technologies.

Professor Azapagic added: “Whether shale gas is an environmentally sound option depends on the perceived importance of different environmental impacts and the regulatory structure under which shale gas operates.

“From the government policy perspective – focusing mainly on economic growth and energy security – it appears likely that shale gas represents a good option for the UK energy sector, assuming that it can be extracted at reasonable cost.

“However, a wider view must also consider other aspects of widespread use of shale gas, including the impact on climate change, as well as many other environmental considerations addressed in our study. Ultimately, the environmental impacts from shale gas will depend on which options it is displacing and how tight the regulation is.”

Study co-author Dr Laurence Stamford, from Manchester’s School of Chemical Engineering and Analytical Science, said: “Appropriate regulation should introduce stringent controls on the emissions from shale gas extraction and disposal of drilling waste. It should also discourage extraction from sites where there is little shale gas in order to avoid the high emissions associated with a low-output well.

He continued: “If shale gas is extracted under tight regulations and is reasonably cheap, there is no obvious reason, as yet, why it should not make some contribution to our energy mix. However, regulation should also ensure that investment in sustainable technologies is not reduced at the expense of shale gas.”

‘Fracking’ in the dark: Biological fallout of shale-gas production still largely unknown

Eight conservation biologists from various organizations and institutions, including Princeton University, found that shale-gas extraction in the United States has vastly outpaced scientists' understanding of the industry's environmental impact. With shale-gas production projected to surge during the next 30 years, determining and minimizing the industry's effects on nature and wildlife must become a top priority for scientists, industry and policymakers, the researchers said. The photo above shows extensive natural-gas operations at Jonah Field in Wyoming. -  Photo courtesy of EcoFlight.
Eight conservation biologists from various organizations and institutions, including Princeton University, found that shale-gas extraction in the United States has vastly outpaced scientists’ understanding of the industry’s environmental impact. With shale-gas production projected to surge during the next 30 years, determining and minimizing the industry’s effects on nature and wildlife must become a top priority for scientists, industry and policymakers, the researchers said. The photo above shows extensive natural-gas operations at Jonah Field in Wyoming. – Photo courtesy of EcoFlight.

In the United States, natural-gas production from shale rock has increased by more than 700 percent since 2007. Yet scientists still do not fully understand the industry’s effects on nature and wildlife, according to a report in the journal Frontiers in Ecology and the Environment.

As gas extraction continues to vastly outpace scientific examination, a team of eight conservation biologists from various organizations and institutions, including Princeton University, concluded that determining the environmental impact of gas-drilling sites – such as chemical contamination from spills, well-casing failures and other accidents – must be a top research priority.

With shale-gas production projected to surge during the next 30 years, the authors call on scientists, industry representatives and policymakers to cooperate on determining – and minimizing – the damage inflicted on the natural world by gas operations such as hydraulic fracturing, or “fracking.” A major environmental concern, hydraulic fracturing releases natural gas from shale by breaking the rock up with a high-pressure blend of water, sand and other chemicals, which can include carcinogens and radioactive substances.

“We can’t let shale development outpace our understanding of its environmental impacts,” said co-author Morgan Tingley, a postdoctoral research associate in the Program in Science, Technology and Environmental Policy in Princeton’s Woodrow Wilson School of Public and International Affairs.

“The past has taught us that environmental impacts of large-scale development and resource extraction, whether coal plants, large dams or biofuel monocultures, are more than the sum of their parts,” Tingley said.

The researchers found that there are significant “knowledge gaps” when it comes to direct and quantifiable evidence of how the natural world responds to shale-gas operations. A major impediment to research has been the lack of accessible and reliable information on spills, wastewater disposal and the composition of fracturing fluids. Of the 24 American states with active shale-gas reservoirs, only five – Pennsylvania, Colorado, New Mexico, Wyoming and Texas – maintain public records of spills and accidents, the researchers report.

“The Pennsylvania Department of Environmental Protection’s website is one of the best sources of publicly available information on shale-gas spills and accidents in the nation. Even so, gas companies failed to report more than one-third of spills in the last year,” said first author Sara Souther, a postdoctoral research associate at the University of Wisconsin-Madison.

“How many more unreported spills occurred, but were not detected during well inspections?” Souther asked. “We need accurate data on the release of fracturing chemicals into the environment before we can understand impacts to plants and animals.”

One of the greatest threats to animal and plant life identified in the study is the impact of rapid and widespread shale development, which has disproportionately affected rural and natural areas. A single gas well results in the clearance of 3.7 to 7.6 acres (1.5 to 3.1 hectares) of vegetation, and each well contributes to a collective mass of air, water, noise and light pollution that has or can interfere with wild animal health, habitats and reproduction, the researchers report.

“If you look down on a heavily ‘fracked’ landscape, you see a web of well pads, access roads and pipelines that create islands out of what was, in some cases, contiguous habitat,” Souther said. “What are the combined effects of numerous wells and their supporting infrastructure on wide-ranging or sensitive species, like the pronghorn antelope or the hellbender salamander?”

The chemical makeup of fracturing fluid and wastewater is often unknown. The authors reviewed chemical-disclosure statements for 150 wells in three of the top gas-producing states and found that an average of two out of every three wells were fractured with at least one undisclosed chemical. The exact effect of fracturing fluid on natural water systems as well as drinking water supplies remains unclear even though improper wastewater disposal and pollution-prevention measures are among the top state-recorded violations at drilling sites, the researchers found.

“Some of the wells in the chemical disclosure registry were fractured with fluid containing 20 or more undisclosed chemicals,” said senior author Kimberly Terrell, a researcher at the Smithsonian Conservation Biology Institute. “This is an arbitrary and inconsistent standard of chemical disclosure.”

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.

Study on methane emissions from natural gas systems indicates new priorities

A new study published in the journal Science says that the total impact of switching to natural gas depends heavily on leakage of methane (CH4) during the natural gas life cycle, and suggests that more can be done to reduce methane emissions and to improve measurement tools which help inform policy choices.

Published in the February 14 issue of Science, the study, “Methane Leaks from North American Natural Gas Systems,” presents a first effort to systematically compare North American emissions estimates at scales ranging from device-level to continental atmospheric studies. Because natural gas emits less carbon dioxide during combustion than other fossil fuels, it has been looked to as a ‘bridge’ fuel to a lower carbon energy system.

“With this study and our larger body of work focusing on natural gas and our transforming energy economy, we offer policymakers and investors a solid analytical foundation for decision making,” said Doug Arent, executive director of the Joint Institute for Strategic Energy Analysis (JISEA) and a co-author to the study. “While we found that official inventories tend to under-estimate total methane leakage, leakage rates are unlikely to be high enough to undermine the climate benefits of gas versus coal.”

The article was organized by Novim with funding from the Cynthia and George Mitchell Foundation and led by Stanford University’s Adam Brandt. It was co-written by researchers from Stanford University, JISEA, Energy Department’s National Renewable Energy Laboratory (NREL), University of Michigan, Massachusetts Institute of Technology, National Oceanic and Atmospheric Administration, University of Calgary, U.S. State Department, Harvard University, Lawrence Berkeley National Laboratory, University of California Santa Barbara, and the Environmental Defense Fund.

“Recent life cycle assessments generally agree that replacing coal with natural gas has climate benefits,” said Garvin Heath, a senior scientist at the NREL and a lead author of the report. “Our findings show that natural gas can be a bridge to a sustainable energy future, but that bridge must be traversed carefully. Current evidence suggests leakages may be larger than official estimates, so diligence will be required to ensure that leakage rates are actually low enough to achieve sustainability goals.”

Among other key findings of the research:

  • Official inventories of methane leakage consistently underestimate actual leakage.

  • Evidence at multiple scales suggests that the natural gas and oil sectors are important contributors.
  • Independent experiments suggest that a small number of “super-emitters” could be responsible for a large fraction of leakage.
  • Recent regional atmospheric studies with very high emissions rates are unlikely to be representative of typical natural gas system leakage rates.
  • Hydraulic fracturing is not likely to be a substantial emissions source, relative to current national totals.
  • Abandoned oil and gas wells appear to be a significant source of current emissions.
  • Emissions inventories can be improved in ways that make them a more essential tool for policymaking.

Acid mine drainage reduces radioactivity in fracking waste

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Natural gas saves water, even when factoring in water lost to hydraulic fracturing

For every gallon of water used to produce natural gas through hydraulic fracturing, Texas saved 33 gallons of water by generating electricity with that natural gas instead of coal (in 2011). -  University of Texas at Austin
For every gallon of water used to produce natural gas through hydraulic fracturing, Texas saved 33 gallons of water by generating electricity with that natural gas instead of coal (in 2011). – University of Texas at Austin

A new study finds that in Texas, the U.S. state that annually generates the most electricity, the transition from coal to natural gas for electricity generation is saving water and making the state less vulnerable to drought.

Even though exploration for natural gas through hydraulic fracturing requires significant water consumption in Texas, the new consumption is easily offset by the overall water efficiencies of shifting electricity generation from coal to natural gas. The researchers estimate that water saved by shifting a power plant from coal to natural gas is 25 to 50 times as great as the amount of water used in hydraulic fracturing to extract the natural gas. Natural gas also enhances drought resilience by providing so-called peaking plants to complement increasing wind generation, which doesn’t consume water.

The results of The University of Texas at Austin study are published this week in the journal Environmental Research Letters.

The researchers estimate that in 2011 alone, Texas would have consumed an additional 32 billion gallons of water – enough to supply 870,000 average residents – if all its natural gas-fired power plants were instead coal-fired plants, even after factoring in the additional consumption of water for hydraulic fracturing to extract the natural gas.

Hydraulic fracturing is a process in which water, sand and chemicals are pumped at high pressure into a well to fracture surrounding rocks and allow oil or gas to more easily flow. Hydraulic fracturing and horizontal drilling are the main drivers behind the current boom in U.S. natural gas production.

Environmentalists and others have raised concerns about the amount of water that is consumed. In Texas, concerns are heightened because the use of hydraulic fracturing is expanding rapidly while water supplies are dwindling as the third year of a devastating drought grinds on. Because most electric power plants rely on water for cooling, the electric power supply might be particularly vulnerable to drought.

“The bottom line is that hydraulic fracturing, by boosting natural gas production and moving the state from water-intensive coal technologies, makes our electric power system more drought resilient,” says Bridget Scanlon, senior research scientist at the university’s Bureau of Economic Geology, who led the study.

To study the drought resilience of Texas power plants, Scanlon and her colleagues collected water use data for all 423 of the state’s power plants from the Energy Information Administration and from state agencies including the Texas Commission on Environmental Quality and the Texas Water Development Board, as well as other data.

Since the 1990s, the primary type of power plant built in Texas has been the natural gas combined cycle (NGCC) plant with cooling towers, which uses fuel and cooling water more efficiently than older steam turbine technologies. About a third of Texas power plants are NGCC. NGCC plants consume about a third as much water as coal steam turbine (CST) plants.

The other major type of natural gas plant in the state is a natural gas combustion turbine (NGCT) plant. NGCT plants can also help reduce the state’s water consumption for electricity generation by providing “peaking power” to support expansion of wind energy. Wind turbines don’t require water for cooling; yet wind doesn’t always blow when you need electricity. NGCT generators can be brought online in a matter of seconds to smooth out swings in electricity demand. By combining NGCT generation with wind generation, total water use can be lowered even further compared with coal-fired power generation.

The study focused exclusively on Texas, but the authors believe the results should be applicable to other regions of the U.S., where water consumption rates for the key technologies evaluated – hydraulic fracturing, NGCC plants with cooling towers and traditional coal steam turbine plants – are generally the same.

The Electric Reliability Council of Texas, manager of the state’s electricity grid, projects that if current market conditions continue through 2029, 65 percent of new power generation in the state will come from NGCC plants and 35 percent from natural gas combustion turbine plants, which use no water for cooling, but are less energy efficient than NGCC plants.

“Statewide, we’re on track to continue reducing our water intensity of electricity generation,” says Scanlon.

Hydraulic fracturing accounts for less than 1 percent of the water consumed in Texas. But in some areas where its use is heavily concentrated, it strains local water supplies, as documented in a 2011 study by Jean-Philippe Nicot of the Bureau of Economic Geology. Because natural gas is often used far from where it is originally produced, water savings from shifting to natural gas for electricity generation might not benefit the areas that use more water for hydraulic fracturing.

Oil- and metal-munching microbes dominate deep sandstone formations

<IMG SRC="/Images/325645565.jpg" WIDTH="350" HEIGHT="245" BORDER="0" ALT="Halomonas bacteria are well-known for consuming the metal parts of the Titanic. Researchers now have found Halomonas in sandstone formations deep underground. – NOAA”>
Halomonas bacteria are well-known for consuming the metal parts of the Titanic. Researchers now have found Halomonas in sandstone formations deep underground. – NOAA

Halomonas are a hardy breed of bacteria. They can withstand heat, high salinity, low oxygen, utter darkness and pressures that would kill most other organisms. These traits enable these microbes to eke out a living in deep sandstone formations that also happen to be useful for hydrocarbon extraction and carbon sequestration, researchers report in a new study.

The analysis, the first unobstructed view of the microbial life of sandstone formations more than a mile below the surface, appears in the journal Environmental Microbiology.

“We are using new DNA technologies to understand the distribution of life in extreme natural environments,” said study leader Bruce Fouke, a professor of geology and of microbiology at the University of Illinois at Urbana-Champaign. Fouke also is an investigator with the Energy Biosciences Institute, which funded the research, and an affiliate of the Institute for Genomic Biology at Illinois.

Underground microbes are at least as diverse as their surface-dwelling counterparts, Fouke said, and that diversity has gone largely unstudied.

“Astonishingly little is known of this vast subsurface reservoir of biodiversity, despite our civilization’s regular access to and exploitation of subterranean environments,” he said.

To address this gap in knowledge, Fouke and his colleagues collected microbial samples from a sandstone reservoir 1.8 kilometers (1.1 miles) below the surface.

The team used a probe developed by the oilfield services company Schlumberger that reduces or eliminates contamination from mud and microbes at intermediate depths. The researchers sampled sandstone deposits of the Illinois Basin, a vast, subterranean bowl underlying much of Illinois and parts of Indiana, Kentucky and Tennessee, and a rich source of coal and oil.

A genomic study and analysis of the microbes the team recovered revealed “a low-diversity microbial community dominated by Halomonas sulfidaeris-like bacteria that have evolved several strategies to cope with and survive the high-pressure, high-temperature and nutrient deprived deep subsurface environment,” Fouke said.

An analysis of the microbes’ metabolism found that these bacteria are able to utilize iron and nitrogen from their surroundings and recycle scarce nutrients to meet their metabolic needs. (Another member of the same group, Halomonas titanicae, is so named because it is consuming the iron superstructure of the Titanic.)

Perhaps most importantly, the team found that the microbes living in the deep sandstone deposits of the Illinois Basin were capable of metabolizing aromatic compounds, a common component of petroleum.

“This means that these indigenous microbes would have the adaptive edge if hydrocarbon migration eventually does occur,” Fouke said.

A better understanding of the microbial life of the subterranean world will “enhance our ability to explore for and recover oil and gas, and to make more environmentally sound choices for subsurface gas storage,” he said.

Neutrons, electrons and theory reveal secrets of natural gas reserves

Gas and oil deposits in shale have no place to hide from an Oak Ridge National Laboratory technique that provides an inside look at pores and reveals structural information potentially vital to the nation’s energy needs.

The research by scientists at the Department of Energy laboratory could clear the path to the more efficient extraction of gas and oil from shale, environmentally benign and efficient energy production from coal and perhaps viable carbon dioxide sequestration technologies, according to Yuri Melnichenko, an instrument scientist at ORNL’s High Flux Isotope Reactor.

Melnichenko’s broader work was emboldened by a collaboration with James Morris and Nidia Gallego, lead authors of a paper recently published in Journal of Materials Chemistry A and members of ORNL’s Materials Science and Technology Division.

Researchers were able to describe a small-angle neutron scattering technique that, combined with electron microscopy and theory, can be used to examine the function of pore sizes.

Using their technique at the General Purpose SANS instrument at the High Flux Isotope Reactor, scientists showed there is significantly higher local structural order than previously believed in nanoporous carbons. This is important because it allows scientists to develop modeling methods based on local structure of carbon atoms. Researchers also probed distribution of adsorbed gas molecules at unprecedented smaller length scales, allowing them to devise models of the pores.

“We have recently developed efficient approaches to predict the effect of pore size on adsorption,” Morris said. “However, these predictions need verification – and the recent small-angle neutron experiments are ideal for this. The experiments also beg for further calculations, so there is much to be done.”

While traditional methods provide general information about adsorption averaged over an entire sample, they do not provide insight into how pores of different sizes contribute to the total adsorption capacity of a material. Unlike absorption, a process involving the uptake of a gas or liquid in some bulk porous material, adsorption involves the adhesion of atoms, ions or molecules to a surface.

This research, in conjunction with previous work, allows scientists to analyze two-dimensional images to understand how local structures can affect the accessibility of shale pores to natural gas.

“Combined with atomic-level calculations, we demonstrated that local defects in the porous structure observed by microscopy provide stronger gas binding and facilitate its condensation into liquid in pores of optimal sub-nanometer size,” Melnichenko said. “Our method provides a reliable tool for probing properties of sub- and super-critical fluids in natural and engineered porous materials with different structural properties.

“This is a crucial step toward predicting and designing materials with enhanced gas adsorption properties.”

Together, the application of neutron scattering, electron microscopy and theory can lead to new design concepts for building novel nanoporous materials with properties tailored for the environment and energy storage-related technologies. These include capture and sequestration of man-made greenhouse gases, hydrogen storage, membrane gas separation, environmental remediation and catalysis.

Terahertz time-domain spectroscopy for oil and gas detection

This image shows R0% (vitrinite reflectance) dependence of α (absorption coefficients) of kerogen of different maturities at selected frequencies. -  ©Science China Press
This image shows R0% (vitrinite reflectance) dependence of α (absorption coefficients) of kerogen of different maturities at selected frequencies. – ©Science China Press

A greater understanding of the evolutionary stage of kerogen for hydrocarbon generation would play a role in easing the world’s current energy problem. Professor ZHAO Kun and his group from the Key Laboratory of Oil and Gas Terahertz Spectrum and Photoelectric Detection (CPCIF, China University of Petroleum, Beijing) set out to tackle this problem. After five years of innovative research, they have developed terahertz time-domain spectroscopy (THz-TDS) as an effective method to detect the generation of oil and gas from kerogen. Their work, entitled “Applying terahertz time-domain spectroscopy to probe the evolution of kerogen in close pyrolysis systems”, was published in Science China Physics, Mechanics & Astronomy, 2013, Vol. 56(8).

The evolution stages of kerogen and hydrocarbon generation are critical aspects of oil-gas exploration and source rock evaluation. In sedimentary rock, about 95% of the organic matter is kerogen, the key intermediate in the formation of oil and gas. The specific kerogen type and maturity level will determine the characteristics of the hydrocarbons that will be generated. Previous research has led to two primary observations: (i) kerogen serves as a significant energy source as recoverable shale oil and coal where reserves far exceed the remaining petroleum reserves; and (ii) kerogen possesses a significant sorption capacity for organic compounds. Kerogen is primarily composed of alicyclics, aromatics, and other functional groups. Therefore, the ability to generate oil and gas from kerogen is determined primarily by its specific composition and structure. However, each generation technique has advantages and disadvantages within the specific parameters of the kerogen. Thus, there is a need for new methods to characterize the numerous stages and mechanisms of hydrocarbon generation from kerogen.

Vitrinite reflectance (R0%), defined as the proportion of normal incident light reflected by a polished planar surface of vitrinite (found in kerogen), is commonly used to characterize the maturity stage of kerogen. Those stages are defined as: the immature (IM) stage, where it generally cannot produce oil and gas (R0%<0.5); the early mature (EM) stage, or heavy oil zone (0.5<R0%<0.7); the middle mature (MM) stage, which is a primary zone of crude oil generation, also referred to as the oil window (0.7<R0%<1.2); the late mature (LM) stage, or zone of light oil and natural gas (1.2<R0%2.0).

To meet the challenges of applying optical characterization in oil and gas exploration, we applied THz-TDS as a nondestructive, contact-free tool for identifying the transformational paths and hydrocarbon generation ability of kerogen. Specifically, the absorption coefficients at different temperatures and pressures indicated the maturity regime of the kerogen, which were in good agreement with the results of programmed pyrolysis experiments.

By comparing the kerogen THz curves under different R0% and the maturity stages of the hydrocarbons, we can conclude that a relationship exists between the kerogen THz optical constants and the maturity stage. The THz optical constant curves at a given frequency can be divided into several sections denoted by the IM, EM, MM, LM, and OM stages. The kerogens cannot generate any significant amount of oil or gas when in the IM stage (R0%<0.5). Therefore, the functional groups and characteristics do not alter, which results in little observed change of the THz optical constants. In the primary oil generation zone (0.7<R0%<1.2), methyl, methylene, aromatic hydrocarbon, oxygen, and nitrogen functional groups separate from the kerogen, and oil and gas begin to be generated. The residual kerogen forms macromolecules with aromatic components. From the changes in the molecular structures and features relative to those of the initial kerogen, the values of the first peak of the THz absorption coefficient curve (see Figure) and the real parts of the relative dielectric permittivity curves characterize the oil-generating stage of kerogen. At a more mature stage (R0%<1.2), alkyls in aromatic groups separate from the kerogen and begin to generate hydrocarbons in the primary gas zone (see Figure).

This study was a collaborative effect involving many university and company researchers. It was supported by a grant from the National Key Scientific Instruments and Equipment Development, a 973 grant from the Department of Science and Technology of China, and a grant from the Beijing National Science Foundation. Being nondestructive and contactless, this method has shown great promise to improve kerogen analysis. The technique needs to be applied in more instances that involve reservoir rocks and further research will determine whether it can be established as a key tool in petroleum exploration and impact the oil and gas industry.