Beijing — China makes a massive move towards a smogless society with its ban of over 500 car models that have been proven to contribute to urban air pollution.
Responding to anti-pollution measures established recently, the Chinese government has halted sales of over 500 models of vehicles that don’t meet fuel-consumption standards.
The halt in production of some 553 models will begin in early January and will include models from Audi, Beijing Benz and Chevrolet, said the China Vehicle Technology Service Center in a statement to the press Thursday.
China’s anti-pollution plan has taken effect in the form of regulating output from steel production, coal usage restrictions, and a never before seen measure to eventually phase out vehicles powered by fossil fuels within the next few years. This ban is the first of its kind, according to Wang Liusheng, a Shanghai-based analyst at China Merchants Securities.
Wang said in an email to Bloomberg,
“To emphasize a cut back on energy consumption, such documents will surface frequently in the future. It’s an essential move to ensure the healthy development of the industry in the long run.”
The move sounds and looks sweeping, however Cui Dongshu, secretary general of the China Passenger Car Association, said that the models make up a “very small percentage” of polluting vehicles. Meanwhile, Beijing is set to record its most impressive improvements to its air quality in nine years, with an almost 20 percent drop in pollution over the past year alone.
Getting climate change under control is a formidable, multifaceted challenge. Analysis by my colleagues and me suggests that staying within safe warming levels now requires removing carbon dioxide from the atmosphere, as well as reducing greenhouse gas emissions.
The technology to do this is in its infancy and will take years, even decades, to develop, but our analysis suggests that this must be a priority. If pushed, operational large-scale systems should be available by 2050.
We created a simple climate model and looked at the implications of different levels of carbon in the ocean and the atmosphere. This lets us make projections about greenhouse warming, and see what we need to do to limit global warming to within 1.5℃ of pre-industrial temperatures – one of the ambitions of the 2015 Paris climate agreement.
To put the problem in perspective, here are some of the key numbers.
Humans have emitted 1,540 billion tonnes of carbon dioxide gas since the industrial revolution. To put it another way, that’s equivalent to burning enough coal to form a square tower 22 metres wide that reaches from Earth to the Moon.
Half of these emissions have remained in the atmosphere, causing a rise of CO₂ levels that is at least 10 times faster than any known natural increase during Earth’s long history. Most of the other half has dissolved into the ocean, causing acidification with its own detrimental impacts.
Although nature does remove CO₂, for example through growth and burial of plants and algae, we emit it at least 100 times faster than it’s eliminated. We can’t rely on natural mechanisms to handle this problem: people will need to help as well.
What’s the goal?
The Paris climate agreement aims to limit global warming to well below 2℃, and ideally no higher than 1.5℃. (Others say that 1℃ is what we should be really aiming for, although the world is already reaching and breaching this milestone.)
In our research, we considered 1℃ a better safe warming limit because any more would take us into the territory of the Eemian period, 125,000 years ago. For natural reasons, during this era the Earth warmed by a little more than 1℃. Looking back, we can see the catastrophic consequences of global temperatures staying this high over an extended period.
So how much CO₂ do we need to remove to prevent global disaster?
Are you a pessimist or an optimist?
Currently, humanity’s net emissions amount to roughly 37 gigatonnes of CO₂ per year, which represents 10 gigatonnes of carbon burned (a gigatonne is a billion tonnes). We need to reduce this drastically. But even with strong emissions reductions, enough carbon will remain in the atmosphere to cause unsafe warming.
The first scenario is pessimistic. It has CO₂ emissions remaining stable after 2020. To keep warming within safe limits, we then need to remove almost 700 gigatonnes of carbon from the atmosphere and ocean, which freely exchange CO₂. To start, reforestation and improved land use can lock up to 100 gigatonnes away into trees and soils. This leaves a further 600 gigatonnes to be extracted via technological means by 2100.
Technological extraction currently costs at least US$150 per tonne. At this price, over the rest of the century, the cost would add up to US$90 trillion. This is similar in scale to current global military spending, which – if it holds steady at around US$1.6 trillion a year – will add up to roughly US$132 trillion over the same period.
The second scenario is optimistic. It assumes that we reduce emissions by 6% each year starting in 2020. We then still need to remove about 150 gigatonnes of carbon.
As before, reforestation and improved land use can account for 100 gigatonnes, leaving 50 gigatonnes to be technologically extracted by 2100. The cost for that would be US$7.5 trillion by 2100 – only 6% of the global military spend.
Of course, these numbers are a rough guide. But they do illustrate the crossroads at which we find ourselves.
The job to be done
Right now is the time to choose: without action, we’ll be locked into the pessimistic scenario within a decade. Nothing can justify burdening future generations with this enormous cost.
Releasing large amounts of iron or mineral dust into the oceans could remove CO₂ by changing environmental chemistry and ecology. But doing so requires revision of international legal structures that currently forbid such activities.
Similarly, certain minerals can help remove CO₂ by increasing the weathering of rocks and enriching soils. But large-scale mining for such minerals will impact on landscapes and communities, which also requires legal and regulatory revisions.
And finally, direct CO₂ capture from the air relies on industrial-scale installations, with their own environmental and social repercussions.
Without new legal, policy, and ethical frameworks, no significant advances will be possible, no matter how great the technological developments. Progressive nations may forge ahead toward delivering the combined package.
The costs of this are high. But countries that take the lead stand to gain technology, jobs, energy independence, better health, and international gravitas.
We seriously need to do something about CO2 emissions. Besides shifting to renewable energy sources and increasing energy efficiency, we need to start putting some of the CO2 away before it reaches the atmosphere. Perhaps the impacts of human-induced climate change will be so severe that we might even have to capture CO2 from the air and convert it into useful products such as plastic materials or put it someplace safe.
A group of scientists from several European countries and the United States including myself met in the middle, in Iceland, to figure out how CO2 could be put away safely – in the ground. In a recently published study, we demonstrated that two years after injecting CO2 underground at our pilot test site in Iceland, almost all of it has been converted into minerals.
The injection well that pumped waste CO2 and hydrogen sulfide gas from a geothermal well underground. Martin Stute, Author provided
Mineralization
Iceland is a very green country; almost all of its electricity comes from renewable sources including geothermal energy. Hot water from rocks beneath the surface is converted into steam which drives a turbine to generate electricity. However, geothermal power plants there do emit CO2 (much less than a comparable coal-fired power plant) because the hot steam from deep wells that runs the turbines also contains CO2 and sometimes hydrogen sulfide (H2S). Those gases usually just get released into the air.
Is there another place we could put these gases?
Conventional carbon sequestration deposits CO2 into deep saline aquifers or into depleted oil and natural gas reservoirs. CO2 is pumped under very high pressure into these formations and, since they held gases and fluids already over millions of year in place, the probability of CO2 leaking out is minuscule, as many studies have shown.
In a place like Iceland with its daily earthquakes cracking the volcanic rocks (basalts), this approach would not work. The CO2 could bubble up through cracks and leak back into the atmosphere.
However, basalt also has a great advantage: it reacts with CO2 and converts it into carbonate minerals. These carbonates form naturally and can be found as white spots in the basalt. The reactions also have been demonstrated in laboratory experiments.
Dissolving CO2 in water
For the first test, we used pure CO2 and pumped it through a pipe into an existing well that tapped an aquifer containing fresh water at about 1,700 feet of depth. Six months later we injected a mixture of CO2 and hydrogen sulfide piped in from the turbines of the power plant. Through a separate pipe we also pumped water into the well.
In the well, we released the CO2 through a sparger – a device for introducing gases into liquids similar to a bubble stone in an aquarium – into water. The CO2 dissolved completely within a couple of minutes in the water because of the high pressure at depth. That mixture then entered the aquifer.
We also added tiny quantities of tracers (gases and dissolved substances) that allow us to differentiate the injected water and CO2 from what’s already in the aquifer. The CO2 dissolved in water was then carried away by the slowly flowing groundwater.
Downstream, we had installed monitoring wells that allowed us to collect samples to figure out what happened to the CO2. Initially, we saw some of the CO2 and tracers coming through. After a few months, though, the tracers kept arriving but very little of the injected CO2 showed up.
Where was it going? Our pump in the monitoring well stopped working periodically, and when we brought it to the surface, we noticed that it was covered by white crystals. We analyzed the crystals and found they contained some of the tracers we had added and, best of all, they turned out to be mostly carbonate minerals! We had turned CO2 into rocks.
The CO2 dissolved in water had reacted with the basalt in the aquifer and more than 95 percent of the CO2 precipitated out as solid carbonate minerals – and it all happened much faster than anticipated, in less than two years.
The fracture in this basalt rock shows the white calcium carbonate crystals that form from the injection of CO2 with water at the test site. Annette K. Mortensen, CC BY
This is the safest way to put CO2 away. By dissolving it in water, we already prevent CO2 gas from bubbling up toward the surface through cracks in the rocks. Finally, we convert it into stone that cannot move or dissolve under natural conditions.
One downside of this approach is that water needs to be injected alongside the CO2. However, because of the very rapid removal of the CO2 from the water in mineral form, this water could be pumped back out of the ground downstream and reused at the injection site.
Will it work elsewhere?
Ours was a small-scale pilot study, and the question is whether these reactions would continue into the future or pores and cracks in the subsurface basalt stone would eventually clog up and no longer be able to convert CO2 to carbonate.
Our Iceland geothermal power plant has increased the amount of gas injected several times in the years since our experiment was started using a different nearby location. No clogging has been encountered yet, and the plan is to soon inject almost all waste gases into the basalt. This process will also prevent the toxic and corrosive gas hydrogen sulfide from going into the atmosphere, which currently still can be detected at low levels near the power plant because of its characteristic rotten egg smell.
The very reactive rocks found in Iceland are quite common on Earth; about 10 percent of the continents and almost all of the ocean floors are made of basalt. This technology, in other words, is not limited to emissions from geothermal power plants but could also be used for other CO2 sources, such as fossil fuel power plants.
The commercial viability of the process still needs to be established in different locations. Carbon mineralization adds costs to a power plant’s operation, so this, like any form of carbon sequestration, needs an economic incentive to make it feasible.
People like to live near coasts, and many power plants have been built near their customers. Perhaps this technology could be used to put away CO2 emissions in coastal areas in nearby offshore basalt formations. Of course, there would be no shortage of water to co-inject with the CO2.
If we are forced to lower atmospheric CO2 levels in the future because we underestimate the damaging effects of climate change, we could perhaps use wind or solar-powered devices on an ocean platform to capture CO2 from the air and then inject the CO2 into basalt formations underneath.
Carbon mineralization, as demonstrated in Iceland, could be part of the solution of our carbon problem.
Using a new satellite-based method, scientists at NASA, Environment and Climate Change Canada, and two universities have located 39 unreported and major human-made sources of toxic sulfur dioxide emissions.
A known health hazard and contributor to acid rain, sulfur dioxide (SO2) is one of six air pollutants regulated by the U.S. Environmental Protection Agency. Current, sulfur dioxide monitoring activities include the use of emission inventories that are derived from ground-based measurements and factors, such as fuel usage. The inventories are used to evaluate regulatory policies for air quality improvements and to anticipate future emission scenarios that may occur with economic and population growth.
But, to develop comprehensive and accurate inventories, industries, government agencies and scientists first must know the location of pollution sources.
“We now have an independent measurement of these emission sources that does not rely on what was known or thought known,” said Chris McLinden, an atmospheric scientist with Environment and Climate Change Canada in Toronto and lead author of the study published this week in Nature Geosciences. “When you look at a satellite picture of sulfur dioxide, you end up with it appearing as hotspots – bull’s-eyes, in effect — which makes the estimates of emissions easier.”
The 39 unreported emission sources, found in the analysis of satellite data from 2005 to 2014, are clusters of coal-burning power plants, smelters, oil and gas operations found notably in the Middle East, but also in Mexico and parts of Russia. In addition, reported emissions from known sources in these regions were — in some cases — two to three times lower than satellite-based estimates.
Altogether, the unreported and underreported sources account for about 12 percent of all human-made emissions of sulfur dioxide – a discrepancy that can have a large impact on regional air quality, said McLinden.
The research team also located 75 natural sources of sulfur dioxide — non-erupting volcanoes slowly leaking the toxic gas throughout the year. While not necessarily unknown, many volcanoes are in remote locations and not monitored, so this satellite-based data set is the first to provide regular annual information on these passive volcanic emissions.
“Quantifying the sulfur dioxide bull’s-eyes is a two-step process that would not have been possible without two innovations in working with the satellite data,” said co-author Nickolay Krotkov, an atmospheric scientist at NASA’s Goddard Space Flight Center in Greenbelt, Maryland.
First was an improvement in the computer processing that transforms raw satellite observations from the Dutch-Finnish Ozone Monitoring Instrument aboard NASA’s Aura spacecraft into precise estimates of sulfur dioxide concentrations. Krotkov and his team now are able to more accurately detect smaller sulfur dioxide concentrations, including those emitted by human-made sources such as oil-related activities and medium-size power plants.
Being able to detect smaller concentrations led to the second innovation. McLinden and his colleagues used a new computer program to more precisely detect sulfur dioxide that had been dispersed and diluted by winds. They then used accurate estimates of wind strength and direction derived from a satellite data-driven model to trace the pollutant back to the location of the source, and also to estimate how much sulfur dioxide was emitted from the smoke stack.
“The unique advantage of satellite data is spatial coverage,” said Bryan Duncan, an atmospheric scientist at Goddard. “This paper is the perfect demonstration of how new and improved satellite datasets, coupled with new and improved data analysis techniques, allow us to identify even smaller pollutant sources and to quantify these emissions over the globe.”
The University of Maryland, College Park, and Dalhousie University in Halifax, Nova Scotia, contributed to this study.
For more information about, and access to, NASA’s air quality data, visit:
NASA uses the vantage point of space to increase our understanding of our home planet, improve lives, and safeguard our future. NASA develops new ways to observe and study Earth’s interconnected natural systems with long-term data records. The agency freely shares this unique knowledge and works with institutions around the world to gain new insights into how our planet is changing.
For more information about NASA Earth science research, visit:
Florida is on the front lines of a debate over the spread of the controversial drilling technique hydraulic fracturing, or fracking, which raises a crucial question: are the state’s unique geology and hydrology safe for expanded oil and gas drilling?
Over the past several months, a number of counties and cities in Florida have banned fracking over environmental concerns. Earlier this year, the state legislature considered but did not pass a bill to regulate fracking at the state level, which would have superseded local bans.
So far, there has been at least one exploratory well in Florida using fracking, but the practice is not widespread. However, the question of how and whether to allow fracking is likely to come back up again, as early as next year.
How would fracking be done in Florida and what environmental and geologic questions are worth considering? A close look at the particular conditions of the Florida peninsula reveals a number of unresolved areas of concern.
Acid fracturing
In some respects, Florida is an unlikely site for this battle. Florida ranks 31st of the 50 states in energy production. The state currently has two regions with conventional hydrocarbon production – the Sunniland trend in South Florida and the western Panhandle. Hydrocarbons are stored within carbonate rocks, which are composed of limestone and dolostone in South Florida and carbonates and sand in the Panhandle.
A protest in 2014 against a bill that would allow fracking in Florida, where there are worries over the effects to the drinking water and tourism industry. astronomygal/flickr, CC BY-NC
Potential hydrocarbon reservoir rocks in Florida are distinct from shales – the layers of sedimentary rock in other parts of the U.S. where fracking has led to a drilling boom in natural gas and oil. The rock under Florida generally has a higher permeability, making it easier for liquids to move through it.
A fracas ensued when one company in 2013 tested fracking before receiving a permit in Florida, which resulted in a cease and desist order from the Department of Environment Protection (DEP).
The company used a technique known as acid fracturing, which is substantially different than what’s more commonly practiced elsewhere in the U.S. In this method, which is suitable only for carbonate reservoirs, acidic water is injected at high pressure into a well to dissolve the rock. Because carbonate rocks are highly soluble, acids can increase pore size and permeability, allowing oil or gas to flow.
What we know
Elsewhere in the U.S., fracking has gained attention due to its association with two hazards: earthquakes and groundwater contamination.
Fracking is a well stimulation technique that entails injecting a mixture of water, sand and chemicals at high pressure into oil and natural gas wells. The fracking fluid pressure breaks up the rocks hosting the oil and gas, increasing their permeability and allowing the oil, gas, natural brine in the rock (called produced waters) and fracking fluid to migrate quickly to the surface. The oil and gas make their way to market, and the fracking fluids are often recovered and reused.
The practice of fracturing rock with high pressure does not cause earthquakes but disposal of water that comes up after wells have been drilled has been linked to seismic activity in Oklahoma and other places in the U.S. EPA
However, the briny produced waters can pose a problem. They are too laden with dissolved salts to release on the surface, where they would constitute a major pollutant. So, these brines are generally reinjected into the Earth in very deep wells, called injection wells.
A growing body of research based on high-quality seismic data collected at surface sites around these injection wells clearly shows that voluminous wastewater injection affects seismicity. Earthquakes in Oklahoma and several other pockets of midcontinent U.S. – including two in Oklahoma with magnitudes greater than 5 since 2011 – have been associated with high-volume deep-well injection of wastewater, a byproduct of oil and gas production.
An additional problem associated with oil and gas production is the potential for contamination of drinking water and irrigation aquifers by either fracking fluids or produced wastewaters. Done correctly, production wells can be constructed and cemented to avoid the migration of fluids into the well. However, natural gas and chemicals used in fracking have been found in the aquifers of the Marcellus Shale in Pennsylvania, and poor drilling practices have been blamed for methane entering aquifers. Surface operations associated with drilling may also contribute to contamination.
As a result of the experiences in other states, the possibility of fracking in Florida has met strong opposition in some quarters.
What we still don’t know
What would the environmental impact of fracking be in Florida?
At this point, there are more questions than answers. The specifics of proposed fracking in Florida are complicated by the very different regional geology of the peninsula.
Much of Florida sits atop what is called a karst terrane, a geological formation characterized by a complex, highly permeable and porous carbonate aquifer system. The geology includes an equally complex set of less permeable rock units – called confining units – that are distributed within, around and throughout the aquifer system.
Key unknowns for Florida include:
Are there are extractable oil and gas reservoirs outside of the currently producing regions of the Panhandle and South Florida? The recent local bans include many regions with no confirmed oil or gas reserves. Shales exist below the carbonate rocks in some locations, but it is unclear if conditions were right for oil/gas to form in those shale formations.
Where are the faults that could produce earthquakes in Florida? Wastewater injection occurs in many locations, but earthquakes are much less common. Earthquakes due to wastewater injection require a combination of factors. First, there must be faults that can produce earthquakes and sufficient stresses. Second, there must be fluid pathways within the rock through which injected wastewater can increase the fluid pressure significantly. The locations of basement faults in Florida are poorly known, and although none have been known to generate earthquakes, their ultimate impact on seismicity in the state will depend on knowing their proximity to proposed locations of wastewater injection.
Where and how deeply will wastewater be injected? Currently, some of the wastewater from Florida’s oil and gas drilling is injected where it is produced, which are in zones below drinking water. In South Florida, the “Boulder Zone” lies above layers from which oil and gas are drawn and below the tapped ends of the Floridan aquifer system. This cavernous zone receives injected wastewater from oil and gas and from municipalities with little pressure increase. This could possibly indicate that induced seismicity may not occur even following rapid and high volume wastewater injection. Many other parts of Florida do not have such a permeable zone similar to the Boulder Zone, but the precise distribution of permeable and impermeable zones in the Florida subsurface is poorly known, so safe wastewater disposal is highly uncertain.
A sinkhole in Florida. The state’s unique geology means water moves rapidly, making the state’s aquifers potentially vulnerable to spills and contaminants. innovationschool/flickr, CC BY-NC
Florida’s geology is significantly different from Oklahoma, where there has been the most seismic activity. In Florida, wastewater injection has generally been above oil/gas producing zones. This means they are farther from deep formations. That could decrease the risk of earthquakes, since earthquake-producing faults occur in these deep formations in locations such as Oklahoma.
On the other hand, Florida’s practice results in wastewater injection closer to drinking water aquifers. The confining units within the Floridan aquifer system (FAS) have been extremely difficult to map and are highly variable in thickness and properties. A comprehensive effort to map these and zones of high permeability – which could be suitable for injecting and storing wastewater – and rapid groundwater flow would be a monumental task requiring full-time work from many geologists and geophysicists for decades. In other words, understanding with certainty how effective Florida’s geology is for storing wastewater from oil and gas drilling and its ultimate effect on aquifers will be a huge undertaking.
Furthermore, Florida cities have generally tapped shallower aquifers until now. However, as these aquifers become overused, deeper brackish to saline portions of the FAS are being considered as source of freshwater through desalination. These aquifers could be used to store freshwater during wet periods, which would be pumped later during dry times (aquifer storage and recovery). Thus, zones of water used for human consumption may approach those where wastewater would be injected.
What will be the impact of surface operations? More widespread production of oil and gas drilling with fracking can result in a larger footprint of operations and more opportunity for surface contamination. Florida’s karst geology contains sinkholes, as well as extensive cave systems, which allow rapid entry and dispersive flow of contaminants into the aquifer system. These karst features are obvious in North and Central Florida, where caves can be large enough to walk or swim through.
South Florida’s aquifers also have rapid flow. In a 2003 dye tracer study in the Miami region, dyes reached the Miami Dade County well field in hours rather than the expected days. Not only did the dye turn the water red, it exposed the vulnerability of Florida’s carbonate aquifers to contamination. Contaminants could reach irrigation and drinking water systems rapidly enough to pose economic and health risks before any effective warnings could be issued.
So although there’s been a sharp debate over fracking in Florida, the focus on “fracking” alone risks losing sight of the bigger picture. Florida’s aquifers are potentially vulnerable to injected wastes, contaminant migration through poorly sealed wells and from surface activities, regardless of whether fracking is involved.
Coal’s share of the U.S. energy market is rapidly plunging. Low-cost fracking-generated natural gas has overtaken the use of coal at America’s power plants. Impending implementation of the Obama administration’s proposed Clean Power Plan, which would place stringent regulations on coal-fired power plant emissions, has also helped to drive coal production to its lowest level in decades. Government sources predict further decline.
Fifty U.S. coal companies have filed for bankruptcy since 2012. Competition and more stringent environmental regulations played a role in this decline. But, just before coal prices collapsed, speculating top producers borrowed billions to finance unwise acquisitions. Now, unable to pay loan interest and principal, they have sought bankruptcy protection to restructure US$30 billion in debt. The bankrupt companies include Arch Coal, Alpha Natural Resources, Patriot Coal and Jim Walter Resources.
Amid this turmoil, many observers fear that bankrupt coal companies will be able to shift their huge liabilities for reclamation, or restoring land that has been mined, to taxpayers.
Congress passed the Surface Mining Control & Reclamation Act, or SMCRA, in 1977 to prevent such a scenario. But, in my view, state and federal coal regulators have failed to ensure that coal companies have enforceable financial guarantees in place, as the law requires.
I have interacted with the coal industry for 40 years, first as a government enforcement lawyer and then litigating issues relating to coal mine reclamation cases on behalf of conservation organizations and coalfield communities. I believe that if the unfunded liabilities of bankrupt coal companies are not covered by new guarantees and additional companies seek bankruptcy protection, there is a real chance that taxpayer-funded billion-dollar bailouts will be necessary to cover their cleanup costs.
Planning for reclamation
SMCRA was designed to prevent bankrupt coal companies from foisting onto taxpayers the costs of restoring thousands of acres of mined land and treating millions of gallons of polluted mine water.
When Congress enacted the law, it identified many of the adverse impacts when mined land was not reclaimed:
…mined lands burden and adversely affect commerce and the public welfare by destroying or diminishing the utility of land for commercial, industrial, residential, recreational, agricultural, and forestry purposes, by causing erosion and landslides, contributing to floods, polluting the water, destroying fish and wildlife habitats, impairing natural beauty, damaging the property of citizens, creating hazards dangerous to life and property, degrading the quality of life in local communities, and by counteracting governmental programs and efforts to conserve soil, water, and other natural resources.
In the decades preceding SMCRA’s enactment, thousands of bankrupt companies abandoned mines without reclaiming them. Many of these sites remain untreated today. According to the U.S. Geological Survey, restoring streams and watersheds across Pennsylvania that were damaged by acidic drainage from mines abandoned before 1977 would cost $5 billion to $15 billion. Similarly, reclaiming mining lands abandoned in West Virginia before SMCRA will cost an estimated $1.3 billion or more.
SMCRA is designed to force a coal company to address and incorporate the cost of reclamation in its business planning. The law mandates that when state or federal regulators issue mining permits, coal companies must provide bonds or other financial guarantees to ensure that if they fail to fully reclaim mines, the state will have money available to do the job.
Most coalfield states administer the federal law through state-law-based regulatory programs overseen by the Department of the Interior. SMCRA offers states several options. They include requiring companies to provide financial guarantees in the form of corporate surety bonds, collateral bonds or self-bonds.
When companies use site-specific surety or collateral bonds, SMCRA requires states to calculate the cost of reclamation before any mining can begin. These studies must consider each mine site’s topography, geology, water resources and revegetation potential.
States may also set up an “alternate” to a bonding system that achieves the objectives and purposes of a bonding program. This option has been described by a court as a “collective risk-spreading system that … allows a State to discount the amount of the required site-specific bond to … less than the full cost needed to complete reclamation of the site in the event of forfeiture.”
Surety bonds and collateral bonds are backed by cash, real property assets and financial guarantees from banks and surety companies. If a coal company goes bankrupt, regulators can collect on these bonds and use the money to fully reclaim abandoned mined land. However, state-approved “alternative” reclamation funding systems and self-bonding by coal companies do not provide the same certainty.
For example, both Pennsylvania and West Virginia approved systems in which coal operators paid nonrefundable fees into state funds that would be used to reclaim any bankrupt coal company sites. But neither required site-specific calculations of what reclamation would actually cost. Pennsylvania imposed a per-acre permit fee, and West Virginia required a few cents per-mined-ton reclamation fee.
Regulators in these states – enabled by lax federal oversight – failed to ensure that companies set aside enough funds. As a result, these agencies have exposed taxpayers to potentially enormous reclamation liability.
Reclamation IOUs
In 2001 a federal district court found that West Virginia’s federally approved state “alternate” bonding fund was hugely underfunded and could not guarantee reclamation of mines abandoned by bankrupt coal companies as required by SMCRA. The court held that state and federal regulators’ decade-long failure to institute a fully funded bonding system had created
[A] climate of lawlessness, which creates a pervasive impression that continued disregard for federal law and statutory requirements goes unpunished, or possibly unnoticed. Agency warnings have no more effect than a wink and a nod … Financial benefits accrue to the owners and operators who were not required to incur the statutory burden and costs attendant to surface mining …
SMCRA also allows companies to self-bond, if they meet rigorous asset requirements. But a self-bonding corporation’s promise to reclaim is little more than an IOU backed by company assets.
Companies reorganizing under federal bankruptcy laws will continue to mine and market coal, hoping to shed mountains of debt and eventually emerge from bankruptcy. It remains to be seen whether they will be able to obtain conventional surety bonds after they reorganize, or whether bankruptcy courts will direct the companies to use their remaining assets to partially fulfill their self-bonding obligations.
One thing is clear, however. Against the backdrop of a century of coal company bankruptcies and attendant environmental damage, regulators ignored a looming coal market collapse with a wink and a nod. Properly administered, SMCRA’s reclamation bonding requirements should have required secure financial guarantees collectible upon bankruptcy.
Unfortunately, coal regulators viewed America’s leading coal companies like Wall Street’s mismanaged banks – too big to fail. As a result, American taxpayers may have to pick up an enormous reclamation tab for coal producers.
The future role of gas in the UK is the subject of significant debate. There is controversy about how much gas we could use and for how long, and whether this will be compatible with statutory climate change targets. As North Sea supplies decline, there are also starkly differing views about whether some of the gas we will need in future should come from domestic shale gas resources.
Despite the number of headlines about shale gas, there has been very little development activity so far. Fracking for shale gas has only been carried out at one site near Blackpool, where operations by Cuadrilla caused minor earthquakes in 2011. This means that it is almost impossible to determine whether significant UK shale gas production would make economic sense. The recent falls in oil and gas prices have added to this uncertainty, but are likely to make commercial viability more challenging.
During the recent 14th licensing round for onshore oil and gas, 159 areas were awarded licenses for development – 75% of these were for unconventional oil and gas extraction, which has sparked local debates in many of the affected areas.
Two planning applications submitted by Cuadrilla for exploration at sites in Lancashire were recently turned down by the local council on the grounds of noise and traffic. One of these was refused against the advice of council officers. An appeal by Cuadrillia is currently underway. Whether or not it goes in favour of the council or the developer, it raises broader questions about the role of local democracy and decision-making.
Last August the government announced the introduction of fast-track planning regulations designed to limit the length of local planning processes for unconventional oil and gas operations. Greg Clark, the secretary of state for communities and local government, also said he expects to have the final say over the Lancashire applications.
What is Fracking?
This intention to constrain local planning processes has understandably led to concerns about local democracy. It is not the first time national government has tried to intervene in local decision-making, especially when it comes to the development of new large-scale infrastructures or natural resources.
While national government may emphasise a particular course of action, like the development of shale gas, there is no guarantee that local decision-makers will simply agree. Furthermore, selective limits on local planning risk exacerbating public mistrust. A Sciencewise project on public engagement with shale gas and oil, commissioned by the government, revealed significant unease among participants about decision-making processes.
A waste of energy?
Given that large-scale changes to energy infrastructures are very likely to be required across the UK as the energy system decarbonises, this issue goes well beyond shale gas. Local opposition has also been significant for other energy developments such as wind farms, solar farms, gas storage sites and electricity transmission lines.
The government’s approach to different energy sources appears to be inconsistent – most notably between onshore wind and shale gas. In contrast with the approach for shale, local planners will determine whether new onshore wind projects go ahead or not. Ministers have defended this situation on the grounds that a lot of wind farms are already being deployed, while shale gas is at a very early stage.
Although the government’s regular energy opinion poll no longer asks specific questions about onshore wind, other polls suggest it still has significant public support – as well as being the cheapest low carbon electricity generation technology.
The focus on shale and wind could also be a missed opportunity for a broader conversation about the UK’s sustainable energy transition. This conversation should not be restricted to which technologies or resources should be used, and what they might cost. Previous research from the UK Energy Research Centre suggests that people are also interested in how energy systems can reflect values such as fairness, sustainability and efficiency. A focus on individual sources like shale gas in isolation leaves little space for this broader conversation to be held.
Even before President Obama announced the Environmental Protection Agency’s (EPA) Clean Power Plan on August 3 to regulate carbon emissions from power plants, there were a number of legal challenges to block the law at its proposal stage – none of them successful. Earlier this year, the DC Circuit Court told opponents, which included a coal company joined by 12 states, that their arguments were premature.
Now that the rules are final, the new court challenges will come fast and heavy. The legal arguments against the plan will be focused on two issues.
The first is based on an unusual legislative drafting inconsistency, whereby the House and Senate versions of the key Clean Air Act provision lead to different conclusions about the EPA’s authority here. In the rush to complete its 1990 amendments to the Clean Air Act, Congress allowed two inconsistent versions of the statute to pass through the conference committee, never to be reconciled. One would allow regulation of carbon dioxide from power plants under the provision being used in the Clean Power Plan; the other arguably would not. No court has ever addressed the question. Call this a drafting-error argument.
More centrally, the Clean Air Act language at issue is inherently ambiguous, as many texts are. It calls for the EPA to set standards for pollution reduction that are based on the “best system of emission reduction” that has been “adequately demonstrated.” Any first-year law student would know to ask: What’s a “system”? How do we know what’s the “best system”? And what level of demonstration is “adequate”?
Counter to conservative thinking
The EPA has taken a broad view of these terms, setting pollution reduction standards that assume states can, and should, do a lot to limit carbon dioxide from fossil fuel–powered plants. That includes things far outside the fenceline of those plants, such as creating incentives to ramp up solar power installations in urban neighborhoods.
To the EPA, “systems” are capacious, and “best” means we shouldn’t think small. Opponents in industry counter that this provision was never about making changes outside the property lines of the regulated emissions sources themselves. To them, the EPA’s stance is an unauthorized reach.
Both the drafting-error argument and the statutory ambiguity argument will come down to how much discretion one thinks the EPA should have to interpret its own legislative mandates.
Will the Supreme Court ultimately decide the EPA Clean Power Plan’s fate? bootbearwdc/flickr, CC BY
Traditionally, courts have deferred to agencies where they are acting in their areas of delegated power. And there are good reasons for courts to curtail the instinct to second-guess expert agencies when statutes can be interpreted more than one way. But this tradition of deference has run smack into the modern line of conservative thinking that maligns federal bureaucracy.
This case will almost certainly reach the US Supreme Court, given the force and funding of the opposition and the importance of the issue to federal energy policy. If and when it does reach the highest court, it is hard to say whether the EPA’s rule will be seen as an agency power grab, or, alternatively, as a reasonable exercise of authority given mandates that necessarily require interpretation.
The court’s most recent environmental cases suggest that the agency is on a shortening leash. Earlier this year, the Supreme Court ruled that the EPA misinterpreted the Clean Air Act in regulating mercury levels from power plants, by failing to consider costs early enough. The court’s reasoning betrayed an impatience with deferring to the EPA.
For now, we can only wait to see how the legal drama will play out.
You are gazing over the clear stream, thinking of fishing the crystal waters in the Rockies. The next morning, you are stunned to see an orange-yellow sludge covering the stream as far as you can see. Is this the Colorado Gold King Mine spill into Cement Creek of August 5, 2015?
How many other mines are leaking or holding millions of gallons of toxic wastewater? And how can we avoid these types of damaging spills in the future?
To the source
AMD, also known as acid-rock drainage (ARD) and mining-influenced water (MIW), results from the exposure of sulfide minerals, particularly pyrite (also known as fool’s gold), to oxygen and water. Then, biological and chemical reactions generate sulfuric acid and mobilize heavy metals associated with the rocks and ore.
Acidic wastewater with heavy metals spills from the opening of the Gold King Mine in photo released by the EPA. Reuters
AMD wastewater can be characterized by high acidity, elevated heavy metals as well as relatively high concentrations of sulfates and solid particles (suspended solids). Iron that is chemically bound to the solid particles give that orange-yellow color. The old-time miners called it “yellow boy.”
When a mine is dug, eventually water will be encountered. To maintain dry workings, the water is pumped out or a tunnel is dug underneath the work area to drain the water. When the mine ceases operations, the pumps are turned off and the mine begins to fill with water.
Under certain conditions, the water, perhaps contaminated with AMD, will decant or discharge out of the mine workings. The predominant AMD generating source in the Western United States is metal mine workings, whose drainage often contains cadmium, lead, nickel, copper and zinc.
Heavy metals
The Gold King Mine is one of many abandoned mines on the Colorado landscape. The Bureau of Land Management, (BLM) in Colorado maintains an ongoing inventory in the State and in 2008 reported 2,751 known abandoned hard rock mines on public lands. The inventory included 4,670 features of mines, such as draining openings and shafts, and mine waste, that may impact water resources.
In order to determine the behavior and impacts of the spill, it is necessary to know the chemical and physical aspects of the spill, and the characteristics of the receiving waters.
In the case of the Gold King spill on August 5, the Cement Creek has been exposed to input of mine drainage on a continuous basis for 100 years. The Cement Creek feeds into the Animas River which then flows to Durango, CO and down the San Juan River to New Mexico and Utah, and ultimately into Lake Powell.
Even before measurements were released to the public, we can assume that the water in the spill would be acidic, there would be solid particles containing high levels of iron and some other metals, and that there would be concentrations of metals dissolved in the water above stream standards. Metals become more soluble in the water as the pH decreases and acidity increases.
The spill was estimated to be three million gallons, or 400,000 cubic feet (ft3) of liquids. Three million gallons seems to be a large value. However, it is 400,000 ft3 of material going into a stream, Cement Creek, which flows at 8,400,000 ft3 per day. That means the spill is being diluted. Then Cement Creek flows into the higher flow Animas River. More dilution.
The spill is ugly but, in my view, it is not as bad as the local government administrators have suggested. The toxic metals will be at high concentrations, but briefly, then will decrease dramatically, as we have seen from previous spills.
As the plume of pollution passes, one would expect the water quality behind it to measure at levels seen before the spill. As it moves downstream, the toxic lead and cadmium will disperse and become lower in concentration. By the time the plume reaches Lake Powell, the levels of the pollutants from the spill won’t be detectable.
The data?
How can I say that the effects of the plume will be temporary and will decrease downstream?
Imagine a normal curve with its peak and tails. That is the spill in Cement Creek. As the plume moves downstream, the mixing and turbulence in the stream cause this normal curve to spread out and the peak decreases. The further the plume proceeds downstream, the more it spreads and the lower is the peak value.
Some of the solid particles that carry iron and other metals may settle or be trapped on the stream beds. Settling should be minimal because the small particles settle very slowly. Still, some might settle out.
The sediment on the bed likely will not be a threat to drinking water and irrigation water because the conditions of the rivers are not conducive to having the metals move from the solid particles and dissolve in the water. Algae on the rocks may take up metals and then the metals might move up the food chain through the insects and then fish. However, I don’t think that there will be enough residuals on the bottom to have a significant effect on the Animas River.
The above are and were my predictions, but what does the actual data from EPA say? The water going by Silverton and Durango, CO now is clear and toxic metals have gone back down to pre-spill levels, according to sampling data from the EPA from the week of August 9.
Now more than a week after the spill, the water below the confluence of Cement Creek and the Animas River resembles the concentrations upstream of the spill. The US Fish and Wildlife Service put 108 fingerling trout in cages and immersed them in the polluted water for 6 days. One died immediately and 107 survived intact. There were no fish kills in the Animas River. There were no fish kills in Cement Creek that received the spill. Then again, there are no fish or insects in Cement Creek because it has been accepting acid mine drainage for the last 120 years.
The released data show the concentrations in the plume decreasing downstream as predicted. Federal officials say initial tests on sediments collected downstream of a mine waste spill show no risk to people using Colorado’s Animas River. The state, too, conducted tests and found that there is not a threat to drinking water or to people during typical recreational explosure.
The Colorado Department of Public Health and Environment has collected and analyzed water quality and sediment from the Animas River. The data indicates that the river has returned to stable conditions that are not a concern for human health during [typical recreational exposure].
The San Juan Basin Heath Department concurs with the state health department findings, and advises that there are no adverse health effects from exposure to the water and sediment during normal recreational use (incidental or limited exposure).
Still, it was judicious to close the drinking water treatment plant intakes until the plume passed. The rafting companies lost business for several days. But, it is not an epic disaster as some folks have made it to be.
The next one?
So how do mines typically avoid this sort of spill? The common method used to temporarily stop AMD flowing out of a mine is installation of a bulkhead, a 10-15 foot thick, reinforced concrete plug with pipes that permit controlling the flow of water through the bulkhead.
Where possible, and where financial resources are available, a treatment facility is built along with a bulkhead to remove metals and acidity from the mine water.
The treatment system approach is problematic in remote areas and at high altitudes. The contaminated water is treated with chemicals to raise the pH, reduce solubility of metals and precipitate those metals as solid metal hydroxides on site. The very wet metal sludge is dried and the residual sent off to a landfill.
It’s also possible to use microbes to lower the cost of removing metals from mine wastewater. The microbial technology is still in a developmental stage.
There are tens of thousands of abandoned mines throughout the US. Most of the mining companies that operated these mines are long gone as are the people involved. Many are leaking AMD into water bodies and have been for decades. Periodically, a water barrier in a mine will be breached and a spill will occur, even without the help of the EPA.
Additionally, sometimes a storage dam containing tailings, or ore processing waste, will burst and send contaminated solids and water into the nearby stream. The Bureau of Land Management estimates that only 15% of these abandoned facilities have been cleaned, or remediated, or have plans to be remediated.
Until additional resources are allocated by Congress to address the abandoned mine problem, we can look forward to many more abandoned mine spills.
