To the Ends of the Earth by Corporate Watch

Corporate Watch

ends OF to

the

earth

Underground a Coalbed shale gas Gaseification Coal Methane shale To Oil Coalandgas uncon tar sands what are they?

guide

to Liquids

ventional

fossil

shaleOil Methane

Hidrates fuels

Where are they found? how are they Extracted? social and environmental issues Climate change companies involved Resistance!

ends OF to

the

earth

a guide To unconventional fossil fuels

London, June 2014 ISBN: 978-1-907738-14-2

Corporate Watch c/o Freedom Press Angel Alley 84b Whitechapel High Street London, E1 7QX

www.corporatewatch.org

Printed on 100% recycled paper

Corporate Watch Corporate Watch is an independent, not-for-profit research and publishing group that investigates the social and environmental impacts of corporate power. Since 1996 Corporate Watch has been publishing corporate critical ‘information for action’ in the form of books, reports, investigative articles, briefings and magazines.

Author: Chris Kitchen Design: Ricardo Santos With thanks to: Charlotte Wilson, Clare Fauset, Emily Coats, Lucy Michaels, Mark Muller, Paul Mobbs, Rebecca Spencer, Simon Pirani, the Corporate Watch coop and everyone else who helped out with the report.

Contents

Introduction Summary table

Factsheets:

shale gas

p16

p19

( Tight Gas)

tar sands Coalbed Methane

p27 p35

Underground CoalGasification

p43

Oilshale p51 p59 shaleOil ( Tight oil)

Coalandgasto Liquids

( Synthetic Liquid Fuels)

Methane Hidrates

p67

p71

Other UnconventionalFossilFuels

p79

Carbon Capture andstorage Glossary p87

p83

endsOF earth

the

a guide To uncon

Introduction We are at a crossroads: either we move away from fossil fuels, reduce energy consumption and develop renewable energy sources, or we face a future of environmental devastation and catastrophic irreversible climate change. As oil, coal and gas run low, the fossil fuels industry, following its unspoken mantra of profit at any cost, is developing new unconventional forms of fossil fuel that will have an even greater impact on local environments, on water resources and the climate. They must be stopped. And people are resisting. The term ‘fracking’ has been transformed from technical engineering slang to a globally recognised rallying call (and perhaps the most widely used pun in the history of environmental activism!). Tar sands, once a fantasy fossil fuel of the future, but now exploited on a vast scale, have been become a focal point for the transnational environmental movement. But despite the growing awareness of fracking and tar sands, relatively few people comprehend the significance of the move towards unconventional fossil fuels, and what it means for the environment. The truth is, that if we exploit the world’s unconventional fossil fuel resources we are likely to create a very different planet, with disastrous consequences for our species. This report aims to go some way in addressing this lack of understanding. It explains some of the reasons for the move towards unconventional fossil fuels and describes the consequences globally and locally, for people and the planet.

ventional

fossil

This report includes:

fuels

• An overview of our global energy problems including the drivers of energy consumption. • A short history of fossil fuels and their historical role. • The motivations behind the development of unconventional fossil fuels. • A brief explanation of the concept of Energy Return on Energy Invested (EROI) and its value in thinking about future energy needs. • The role that unconventional fossil fuels will play in our changing climate: perhaps their most important consequence, as well as other impacts, particularly on water resources. • Conclusions on where we might go from here. • A table summarising information on the various types of unconventional fossil fuel • Nine stand-alone factsheets on each of the types of unconventional fossil fuel, describing where they are found, how they are extracted, the significant environmental and social issues, stage of development, notable companies and resistance. • A factsheet on carbon capture and storage technologies.

450

The Global Energy Context Around the world we are consuming more and more energy. As the more easily accessible forms of energy, such as conventional oil and gas, run low we are moving towards increasingly exotic and difficult to extract sources such as shale gas and tar sands.

Other Biomass Hydro Electricity Nuclear Electricity

350

Natural Gas

Crude Oil

200

Primary Energy Production Exajoules per Year

100

Coal

1850

1800

1900

1950

2000

Graph showing increase in global energy consumption since 1820. 1 exajoule = 1 x10^18 (which means one followed by 18 zeros) joules. Adapted from: ‘World Energy Consumption Since 1820 in Charts’. The Oil Drum. Accessed March 2014. <http://www.theoildrum.com/node/9023>

But what is behind this? Why do we consume ever more energy? For economies to survive in our economic system, they must continually expand, and as they expand they consume more resources. It is this constant need for economic growth that is behind our increasing consumption of energy and other resources.

Economic growth is also exponential, this means that the economy doesn’t just steadily increase in size, rather the rate of growth increases all the time. For example, if an economy is growing at two percent per year it will double in size (and consume twice the amount of resources) roughly every 35 years. As the earth has a finite amount of resources, exponential economic growth clearly cannot go on for ever, as eventually resources will run out.

Per Capita Energy Consumption (Gigajoules per Capita)

60 50 1970

1980

1990

2000

2010

Graph showing global increase in per capita (per person) energy consumption since 1965. 1 gigajoule = 1 billion (one followed by nine zeros) joules. Adapted from: ‘World Energy Consumption Since 1820 in Charts’. The Oil Drum. Accessed March 2014. <http://www.theoildrum.com/node/9023>

It is perhaps tempting to conclude that population growth drives energy consumption: that the reason we are using more and more energy is because there are more and more people on the planet using energy. However, both population growth and global energy consumption are symptoms of a wider problem, consequences of economic systems based on inequality, competition and growth. The highest rates of population growth are in economically poorer countries and regions, and are mainly the result of people trying to protect their families from the impacts of poverty and child mortality. This is borne out by the fact that population levels tend to level off once certain standards in quality of life and education, especially for women, are achieved. Some economically richer countries such as Japan actually have falling population levels.

Considering the problem of increasing global energy consumption from the narrow perspective of population growth also ignores the fact that there are huge disparities in the amount of energy that people consume. Most of the global population relies on a tiny amount of energy, while those in richer, mostly Western, countries consume comparatively enormous amounts. For example, the average energy consumption per person in the US is over 34 times that of Bangladesh.1 Further to this, competitive markets require inequality, winners and losers (on an individual and national basis), and it is primarily this inequality that drives population growth. The ‘population problem’ is however particularly appealing to those who seek to maintain the status quo as it conveniently deflects attention from wider systemic failures. Instead of focusing on the excessive consumption in the West, and the ideologies that sustain this, they talk about our growth in energy

and resource consumption as if it were simply caused by the expanding numbers of our species. This is not just disingenuous, it is extremely dangerous, as the problem can rapidly descend into a disturbing framing of ‘too many brown people’. It is often argued that our current economic systems do not need to change and that economic growth can be de-coupled from energy and resource consumption; that economies can go on expanding and that technological advances will allow us to also reduce our resource consumption at the same time. However, this dream has never been realised. Much like proposed climate techno-fixes such as geo-engineering and carbon capture and storage (see below), clinging to the dream of ‘de-coupling’ allows existing economic and energy systems to continue with ‘business as usual’, while promising that problems will somehow be dealt with in the future.

12000 50

Total Energy Million Tonnes of Oil Equiv.

10000 8000

1980

1990

2000 30

If we really want to deal with ever-increasing energy consumption we need to address its root causes: the economic and political systems that determine energy demand and supply and the individualist, anthropocentric philosophies that underpin them. An anthropocentric philosophy places humans at the centre of the universe, where nature is viewed as something separate to the human world to be conquered and controlled. Many environmentalists believe instead that we need to adopt ecological thinking, to consider

Real GDP

Trillion US 2005 $

2010

Graph showing increase in global energy use with increase in global GDP (recently energy use per GDP has started to increase again). Adapted from: ‘World Energy Consumption Since 1820 in Charts’. The Oil Drum. Accessed March 2014. <http://www.theoildrum.com/node/9023>

the human world as part of the natural world, and to exist in harmony with nature instead of simply exploiting it. Fossil fuels have provided the energy that has powered industrialisation and economic expansion, they still provide most of the world’s energy needs, and if the fossil fuels industry and its supporters have their way, we will remain hooked for decades to come.

Fossil Fuels Fossil fuels are formed when organic matter is transformed by geological processes over millions of years. As marine organisms die and float to the seabed, they are slowly covered by layers of sediment, then gradually fossilised by heat and pressure to form oil. Coal is made by a similar process: organic matter from swamps and forests decays and over

thousands of years forms peat. It is then covered by layers of mud and sand, and eventually transformed by heat and pressure over millions of years to form coal. Natural gas is also usually formed in a similar way, from both ancient sea life and land based plants, and is often found near reserves of coal or oil.

Fossil fuels contain hydrocarbons (molecules made up of carbon and hydrogen atoms) that can be burnt to release their stored chemical energy. Fossil hydrocarbons are extremely energy-dense. For example, burning coal releases more than three times the energy of wood (by weight). This combined with the relative ease of transporting and storing solid and liquid fossil fuels contributes to their usefulness as energy sources. Although fossil fuels have been used for heating and light for thousands of years, it was not until the early 1800s, during the Industrial Revolution, that fossil fuels replaced wind, water power and human and animal labour as the primary source of mechanical energy (energy for moving things). Along with technological advances such as the steam engine, fossil fuels hugely increased the amount of energy available for carrying out tasks, leading to perhaps the biggest change in society since humans began using agriculture around 10,000 years ago. Over a matter of decades, the dominant economies expanded massively, and the fossil-fuelled Industrial Revolution induced a period of rapid industrial expansion across the globe. The energy in fossil fuels represents hundreds of millions of years of stored up solar energy. However, it has only taken a couple of hundred years for us to use a large proportion of it and this glut of energy has come at a cost. Our current economic system was

built on the availability of ‘cheap’ energy. Economies are now dependent on using ever greater amounts of energy and the infrastructure supporting them, particularly transport systems, rely upon getting this energy from fossil fuels, particularly oil. We are now hooked on oil and kicking the habit is going to require radical social, economic and political change. Our extreme dependence on oil has led some to conclude that ‘peak oil’ would spell the imminent collapse of modern civilisation. ‘Peak oil’ is a term used to describe the time when oil production around the world reaches its maximum before a slow decline in production rates begins. Partly due to the highly politicised and therefore unreliable nature of oil reserve statistics, there are ongoing debates about whether this has already happened or, if it hasn’t, when it will. There is, however, a general agreement that we are at least close to a peak in conventional oil production. Many predicted that when peak oil occurred and production rates slowed, the ever-increasing demand for oil would begin to outstrip supply and as the lifeblood of industrial civilisation began to run dry global economic and social collapse would result. However, this no longer seems so likely. As oil (and gas) reserves begin to run low, energy prices rise, and this, along with enormous power held by fossil fuel companies, means that new, more extreme methods of production are being found to sustain our society’s addiction to fossil fuels.

Unconventional Fossil Fuels While there is no strict definition of an ‘unconventional fossil fuel’, the term is often used to describe fuels that cannot be extracted using conventional drilling or mining. It can also refer to fuels from conventional sources which have been processed using unconventional methods, such as liquid fuels produced from coal. Conventional oil, coal and gas can all be extracted relatively easily, but as these run low, energy prices rise, and new technologies are developed it becomes economically viable to produce fossil fuels from other, harder to extract sources such as tar sands and shale gas. The move towards unconventional fossil fuels is also being driven by countries’ desires to develop their own energy sources, rather than being dependent on foreign oil and gas. This aim for ‘energy security’ is partly due to the failure of ‘neo-liberal’

markets to rationally distribute energy resources. With states such as Venezuela, Russia and China not obeying the neo-liberal doctrine, and with continuing instability in the Middle East, developing domestic, often unconventional, energy sources is now a priority for many countries. Deposits of unconventional fossil fuels are usually larger and more dispersed than conventional ones. Conventional deposits of oil and gas are accumulations that have seeped out from the source rock where they were formed and become trapped by geological boundaries, such as layers of impermeable rock. As a result they are generally smaller and more concentrated. Unconventional oil and gas (such as tight oil and shale gas) is usually extracted from the rock where it formed and is found in larger, more spread-out deposits. This means that they are harder

The move towards unconventional fossil fuels has already resulted in extreme environmental and social costs, as well as huge shifts in geopolitical relations. Unconventional fossil fuels generally require more energy to produce than conventional fossil fuels, i.e. you have to put more energy in to get energy out. This ratio of energy in to energy out can be described by a fuel’s Energy Return on Energy Invested or EROI.

Higher

Conventional resources

Improved technology Increased pricing

Net Energy

The definition of ‘unconventional’ also changes over time, with sources becoming ‘conventional’ as they become more widely used. For example offshore oil deposits that were once considered unconventional due to their depth (and thus difficulty to access) are now routinely drilled and treated as a conventional fuel source.

More than 90% of World production

Price and/or technology limit GAS SHALES

TIGHT GAS SANDS HEAVY OIL

COALBED METHANE

Unconventional resources GAS HYDRATES

OIL SHALE

Lower

to extract and result in more widespread social and environmental impacts.

Volume of resource

Resource triangle

At the top are conventional resources, in small volumes that are easy to extract. At the bottom are unconventional resources, in large volumes that are difficult to extract. Increasing price and improved technology allow resources further down the triangle to be extracted.

Energy Return On Investment (EROI) Energy Return On Investment (sometimes called ‘energy returned on energy invested’ or EROEI) is used as a measure of how much energy you need to expend in order to extract energy from a particular energy resource. More exactly, it is the ratio of the amount of usable energy returned from extraction and production activities compared to the amount of energy invested in those energy-gathering processes. For example, a certain fuel may have an EROI of 20:1 meaning that for every unit of energy put into producing the fuel, it provides 20 units of usable energy. Resources with a high EROI, such as conventional oil or coal, give a lot of usable energy for a relatively small amount energy required to extract them. Low EROI resources on the other hand give only slightly more usable energy than you need to expend on extraction. If an energy resource has an EROI of less than 1:1, it is no longer a useful source of primary energy, as you need to put more energy in than you will get out. Measuring EROI can be difficult as it depends on where you draw the boundaries for what is included in the process of extraction, production, transportation etc. For example, if you are measuring the EROI of mined coal, should you include the energy used to make the

miners’ breakfasts? Or some of the energy used to make the cutlery they are eating their breakfast with? Where do you draw the line? Despite the difficulties in measuring EROIs, standard approaches can be used so that different resources can be compared on a reasonably equal footing. Some approximation is involved but this does not mean measures of EROI are of no value. EROI does not give a complete picture of the utility of an energy source as it does not measure the type or quality of energy produced. For example, oil is particularly valuable because it can be converted to a number of different fuels, is relatively easy to transport, and has a very high energy density (the energy contained in a unit volume of the fuel), none of which are used in calculating oil’s EROI. Also, measuring EROI does not include various ‘externalities’ of using a certain type of fuel, such as the health impacts, the greenhouse gases produced etc. The value of EROI analyses is that they can show which energy sources are viable as fuels, how much energy has to be expended to continue providing energy for society, and what proportion of the economy will need to be devoted to energy production.

EROI needed to support modern industrial societies?

Energy Out

100 90

HISTORIC OIL AND GAS FIELDS

NEW OIL AND GAS DISCOVERIES

WIND COAL NUCLEAR

SOLAR PV

SHALE OIL

The Net Energy Cliff

Fuels to the right require more energy for production. Beyond a certain point fuels no longer provide enough energy to support society

30 20

Energy Available for Consumiton

TAR SANDS

Energy Used in Production

OIL SHALE

EROI

Energy Return On Investment

50:1

40:1

30:1

Unconventional fossil fuels generally have lower EROI values than conventional ones. However, EROI values for conventional fossil fuels are also going down, as the deposits that are easiest to exploit are being used up and production moves to greater depths and more extreme environments. Moving towards lower EROI energy sources means committing a larger proportion of the economy to producing energy. A worrying consequence is that this will likely further increase the already enormous power held by the fossil fuel companies. EROI values must remain above a certain level in order to support a modern industrialised society. Rather than being triggered by peak oil, some

Climate change It is difficult to describe the scale and seriousness of global climate change (sometimes called ‘global warming’) but a fair description would be to say that it is one of the greatest challenges to ever face humanity. How we respond to this challenge could well determine our future existence as a species. Desperate attempts at disinformation by the fossil fuel industry and free market ideologues have influenced public opinion on climate change. But even the

20:1

10:1

predict that exceeding an EROI threshold and falling off the ‘net energy cliff’ (see graph) will cause economies and societies to start to collapse (some have estimated this to be EROI values of 3:1 others as high as 11:1). 2 3 Net energy aside, what are the other consequences of moving towards unconventional fossil fuels and lower EROI energy sources? The specific social and ecological impacts of developing unconventional fossil fuels are detailed in the factsheets. However, it is worth now discussing perhaps the most significant effect of unconventional fossil fuel use: the contribution to global climate change.

international body tasked with presenting scientific information on the issue, the Inter-governmental Panel on Climate Change (IPCC), which is highly conservative in its estimations, has stated in 2013 that it is extremely likely (more than 95% certain) that human influence has been the dominant cause of the observed warming since the mid-20th century.4 The scientific consensus is clear: our planet is warming; the burning of fossil fuels is primarily causing this

1:1

warming; it is dramatically changing Earth’s climate system at unprecedented rates, and if we don’t massively reduce greenhouse gas emissions soon we risk creating a future where our environment can no longer support us. The scale of the changes we are creating are so large, that some geologists are now referring to a new geological epoch, the Anthropocene (deriving from the Ancient Greek terms ‘anthrōpos’ for human and ‘cene’ for recent). Since the end of the industrial revolution (around 1900) the Earth’s surface has warmed by around 0.9 oC and billions of tonnes of carbon dioxide (CO2) and other greenhouse gasses have been emitted into the atmosphere.5 Estimations have been made of the amount of CO2 we can still emit while staying below so-called ‘dangerous’ levels of warming. The UN climate talks have established a limit of 2 degrees Celsius (oC) of warming, and this translates to a limit of about 1000Gt of carbon (1Gt = 1 gigatonne = 1 billion tonnes) emitted to the atmosphere from the start of the Industrial Revolution (generally agreed to be around the year 1750). We have already emitted about 370Gt, and there is easily enough remaining conventional fossil fuels to take us well beyond the remaining 630Gt.

However, the relatively small amount of warming already experienced to date is certainly dangerous, and it is already having huge impacts around the world. Further, recent research suggests that the impacts of 2oC of warming will be greater than previously anticipated and could trigger feedbacks (see below) that eventually result in 3 to 4oC temperature rise, with catastrophic consequences.6 The same research concludes that in order to avoid the most serious impacts and the risk of irreversible and uncontrollable changes to the climate, a total limit of 500Gt of carbon is required.7 As we have already emitted 370Gt this leaves a limit of 130Gt that could be further added. In order to stay within this limit we would have to leave the vast majority of the remaining conventional oil, coal and gas in the ground. Estimates vary significantly, but remaining conventional coal reserves alone are well over 500Gt of carbon8. Developing unconventional fossil fuels, and releasing the enormous amounts of carbon they contain, is thus absolutely incompatible with staying below this limit or maintaining anything like a reasonably habitable climate.

Feedback, tipping points: is it too late? As the planet warms the climate system responds in variety of ways. Some responses will act to reduce the warming (negative feedback) others will act to exacerbate it (positive feedback). For example, as the planet warms, ice and snow melt, causing the surface to darken, absorb more sunlight and warm further, which then melts more ice and snow. This creates a ‘positive feedback loop’. As well as positive and negative feedbacks, climatologists predict that there may be various ‘tipping points’ in the climate system, and that if we go beyond a certain amount of warming there will be irreversible changes to the global climate. The analogy often used is that of a glass of wine, you can push it a certain amount and it will stay up right, but if you push it beyond the ‘tipping point’ the situation suddenly changes, the glass falls and the wine spills. Despite the enormity of the problem, and the alarming implications of positive feedbacks and tipping

points, it is not too late. Going beyond one tipping point may cause dramatic and irreversible changes, but it does not necessarily result in a domino effect of one tipping point triggering another leading to ‘runaway’ climate change. What we do now has a real impact, and could be the difference between a reasonably liveable climate and catastrophic climate change. It may be for example that we go beyond one tipping point but just manage to reduce emissions enough to prevent another being triggered. This could make all the difference. So it is not too late, and although the issue of climate change can be fraught with difficulties and complications, one thing is clear: we need to reduce emissions as soon as we can, and this means moving away from fossil fuels, conventional and unconventional, as fast as we can.

Carbon Capture and Storage The idea of Carbon Capture and Storage (CCS) is often raised when discussing the issue of unconventional fossil fuels and greenhouse gas emissions. Fossil fuel industry spokespeople argue that the increased emissions associated with unconventional fossil fuels can be dealt with using CCS technologies. CCS is discussed in a separate factsheet in this report, but the simple message is that even if the huge problems with the CCS are overcome (and this seems extremely unlikely), it still would not change the fact that we need to move away from all forms of fossil fuel, as soon as possible. The promise of CCS being implemented in the future is being used as a smokescreen to allow the expansion of fossil fuel production. This has stalled the development of alternatives, and deflected attention away from approaches which tackle the underlying systemic causes of climate change and other ecological crises.

Water and other impacts As well as the effect on the global climate, the depletion of the ‘easiest to access’ resources also increases the other ecological impacts of fossil fuel extraction.9 Harder to access resources not only require more energy to extract, they also require more water and land and produce more waste.10 For example in Alberta, Canada, the area of land required per barrel of oil produced increased by a factor of 12 between 1955 and 2006.11 If the expansion of unconventional fossil fuels continues, this trend will be replicated around the world, since unconventional fossil fuel resources are spread over much greater areas. This means a much greater impact on wildlife and far more local communities being exposed to the impacts of extraction, such as water and air pollution. The effects on water resources are particularly profound. Globally, freshwater is becoming more and more scarce. The UN predicts that by 2025 two thirds of the world’s population could be living

under water-stressed conditions. The development of unconventional fossil fuels will dramatically increase global water consumption and leave enormous volumes of contaminated water. For example the U.S. Environmental Protection Agency estimates that fracking in the US uses 70 to 140 billion gallons (265 – 531 billion litres) of water per year, equivalent to the total amount of water used each year in a city of 2.5 - 5 million people.12 The huge poisonous lakes created by the tar sands industry now cover an area of 176km2.13 In 2002, the oil shale-fired power industry used a staggering 91% of all the water consumed in Estonia.14 At a time when we should be doing all we can to conserve our water resources and share them equitably, developing unconventional fossil fuels will consume huge additional amounts of water. Since many regions where unconventional fossil fuels occur are already facing water scarcity, it will also often be taken from those who need it most.

Conclusion Fundamentally the development of unconventional fossil fuels represents a continuation of ‘business as usual’. It allows the same systems to exploit natural and human resources, and the same companies to extract their profits, while avoiding the social change that would be required to to seriously address our

addiction to increasing consumption. However, some changes are taking place. The move towards unconventional fossil fuels is already having global political consequences. It is resulting in huge geopolitical impacts, as fossil fuels

are developed in new locations and relations shift between the countries supplying and consuming them. Old alliances based on the flow of oil are starting to crumble with the potential for regional destabilisation and increases in conflict.

have enormous potential, but ultimately we have to radically change our whole attitude to energy. We need to understand the wider social, political and ecological contexts of energy production and consumption rather than approaching them as isolated issues.

But the shift to unconventional fossil fuels is also resulting in some unexpected, even positive, political consequences. Around the world people are resisting, from the first nations communities in North America to Romanian villagers, people are rising up against the exploitation of their land and people. Unconventional fossil fuels are connecting local struggles to those fighting for broader environmental and social justice. They have given the climate justice movement a new focus, bringing the here and now to what can sometimes be a diffuse and hard to place struggle. However, in order build the resistance far more people need to be aware of the nature and scale of the problem. It is with this mind that we have produced this report, in the hope of providing ‘information for action’.

Recognising that we need to change our attitudes to energy and other resources and that we need to consume much less, often leads to the accusation that environmentalists either want or are risking humanity’s return ‘back to the Stone Age’. The argument goes that it is only through the marvels of capitalism, technological advance and economic growth that we have lifted people out of grinding perpetual poverty and that if we change course all this ‘progress’ will be lost.

The perennial question posed to anyone opposing the exploitation of the world’s environment and people is: what’s the alternative? Without exploring the complexities of an apparently simple question, and with apologies for presenting an almost equally familiar response, it is not the purpose of this report to spell out a future technological path to sustainable energy consumption and production, or a political manifesto for the social change needed to bring it about (see end notes for further reading in this area).15 Having said that, its worth sketching out some broad principles that should help guide where we go from here. Climate change, and the other interrelated global ecological crises we are facing (including for example biodiversity loss and ocean acidification), are not primarily technical or scientific problems. Science and technology will play an incredibly important role in our search for solutions, but fundamentally the answers lie in how we relate to one another, how we organise our societies and even how we place ourselves philosophically in the universe. To put things in slightly less existential terms, one thing is certain: we are going to have to use much less energy. Energy efficiency measures can go some way to reducing consumption, and renewable energies

But regardless of your view on the path to, and nature of, modern ‘civilisation’ we simply cannot continue as we have been. However politically unpalatable some may find it, we have to change. To use a much abused and almost completely co-opted term, we need sustainability, and what we have now is indisputably unsustainable. However addressing our resource consumption, our attitudes to the environment and our understanding of ecology can go hand in hand with the move towards more equitable, socially just societies. In fact, in our view, it is a necessity. So, this is all pretty big stuff, pretty daunting. Things are pretty bad, and bringing about global revolution is kind of a big job, right? Well one source of hope is the fact that it is not just the climate system that contains positive feedbacks and tipping points, they also exist within social systems. If we can resist unconventional fossil fuels wherever their development is attempted we can add new powerful front-lines, broadening and strengthening the many existing social and environmental struggles around the world. This could help trigger the tipping point we need to bring about a global movement for systemic change. We live in interesting times, the actions of those alive today will define the existence of many generations to come and the future health of life on our planet. It is up to us and it is not going to be easy, but in the words of ecologist Murray Bookchin: “If we do not do the impossible, we shall be faced with the unthinkable.”

A note on numbers

Numbers and units used in the report:

The report contains various figures such as the amounts of a type of fossil fuel that can be found around the world, or how much carbon dioxide is emitted to the atmosphere as a result of its use. We have tried to be consistent throughout the report with quoting the units used in the source (be it barrels, cubic feet etc.) along with a metric conversion where appropriate.

1 trillion = 1,000,000,000,000 = 1,000 billion = 1,000,000 million (or 1 million million)

However, there is disagreement over many of the resource size figures, and some of them are not entirely reliable due to political factors. For example, Saudi Arabia’s oil reserves have, somewhat suspiciously, stayed almost exactly the same for more than 30 years despite producing millions of barrels of oil per day throughout this period. As a result all figures quoted should be used as a guide rather than exact amounts. The interested reader will be able to find more detail and discussion around the various figures in the references used in the report.

Volume 1 US barrel of oil (‘barrel’ in the report) = 0.16 cubic metres = 159 litres = 5.61 cubic feet = 42 US Gallons 1 Gigabarrel (1Gb) = 1 billion barrels Emissions 1 Gigatonne carbon (GtC) = 1 billion tonnes carbon = 3.7 billion tonnes CO2 (Used for the weight of carbon in a fuel or the weight of carbon in the atmosphere) Weight 1 tonne = 1000 kg =1.1 tons Power 1 Mega Watt (MW) = 1 million watt (power is energy per unit time)

Reserves and resources. The world of fossil fuels is full of statistics on various resources and reserves so it is important to explain the difference between these terms. ‘Resource estimates’ are measures of the amounts that exist that either are or may be valuable in the future (sometimes called the ‘in place’ resources). ‘Technically recoverable resources’ refers to how much of this can recovered using existing technology, regardless of price. Reserves on the other hand are the amounts that are currently economically extractable. So if the cost of exploiting a particular deposit is more than the price the resulting product can be sold for, it is not included in reserve estimates. In short: Resource = how much there is Reserve = how much can currently be extracted

Endnotes 1 ‘Energy use (kg of oil equivalent per capita), based on 2011 figures ‘. World Bank data <http://data. worldbank.org/indicator/EG.USE.PCAP.KG.OE> 2 Hall, Charles A. S., Stephen Balogh, and David J.R. Murphy. ‘What Is the Minimum EROI That a Sustainable Society Must Have?’ Energies 2, no. 1 (23 January 2009): 25–47. doi:10.3390/en20100025. <http://www.mdpi.com/1996-1073/2/1/25> 3 Murphy, David J., and Charles A. S. Hall. ‘Year in Review-EROI or Energy Return on (energy) Invested: Review: Energy Return on Investment’. Annals of the New York Academy of Sciences 1185, no. 1 (January 2010): 102–118. doi:10.1111/j.17496632.2009.05282.x. <http://onlinelibrary.wiley. com/doi/10.1111/j.1749-6632.2009.05282.x/ abstract> 4 ‘Human influence on climate clear, IPCC report says’. IPCC press release, 27 September 2013. <http://www.ipcc.ch/news_and_events/docs/ ar5/press_release_ar5_wgi_en.pdf> 5 ‘What is climate change?’. Met office website. Accessed March 2014. <http://www.metoffice. gov.uk/climate-guide/climate-change> 6 Hansen, James, Pushker Kharecha, Makiko Sato, Valerie Masson-Delmotte, Frank Ackerman, David J. Beerling, Paul J. Hearty,

12 ‘Draft Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources’. US EPA (Feb 2011). <http:// yosemite.epa.gov/sab/sabproduct.nsf/0/ D3483AB445AE61418525775900603E79/$File/ Draft+Plan+to+Study+the+Potential+Impacts+ of+Hydraulic+Fracturing+on+Drinking+Water+R esources-February+2011.pdf> 13 Erin Flanagan and Jennifer Grant. ‘Losing Ground, why the problem of oilsands tailings waste keeps growing’. Pembina Institute (Aug 2013). <http:// www.pembina.org/pub/2470> 14 Raukas, Anto (2004). “Opening a new decade”. Oil Shale, A Scientific-Technical Journal (Estonian Academy Publishers) 21 (1): 1–2. ISSN 0208-189X. Retrieved May 2008. <http://www.kirj.ee/public/ oilshale/1_ed_page_2004_1.pdf> 15 For some research exploring the subject of sustainable economies try: Zero Carbon Britain <http://zerocarbonbritain.com/>, Research & Degrowth <http://www.degrowth.org/>, New Economics Foundation, the Great Transition <http://www.neweconomics.org/publications/ entry/the-great-transition> and Tim Jackson’s Prosperity without Growth <http://www.sdcommission.org.uk/publications.php?id=914>.

Our carbon budget

The graphic shows estimates for the global carbon content in each of the types of conventional and unconventional fossil fuel*, along with the limit that we can still add to the atmosphere while avoid the most serious impacts and the risk of irreversible and uncontrollable changes to the climate. It also shows the maximum amount that could be stored by 2050 using Carbon Capture Storage technologies.

EMISSIONS TO DATE (GtC)

RESERVES (GtC)

CONVENTIONAL FOSSIL FUELS

TOTAL

369 GtC

TOTAL

805 GtC

OIL

GAS

COAL

OIL

GAS

COAL

136 GtC

51 GtC

183 GtC

162 GtC

102 GtC

541 GtC

TECHNICALLY RECOVERABLE RESOURCES (GtC) CONVENTIONAL FOSSIL FUELS TOTAL

12,832 GtC

UNCONVENTIONAL GAS

TOTAL

692 GtC **

UNCONVENTIONAL OIL

TOTAL

711 GtC

CONVENTIONAL OIL

CONVENTIONAL GAS

325 GtC

277 GtC

COAL

12,230 GtC

TIGHT GAS

METHANE HYDRATES

SHALE GAS

COAL BED METHANE

ARTIC GAS

DEEP WATER GAS

211 GtC

163 GtC

138 GtC

130 GtC

28 GtC

22 GtC

OIL SHALE

TAR SANDS

SHALE OIL

HEAVY OIL

295 GtC

264 GtC

42 GtC

44 GtC

(TIGHT OIL)

EXTRA-HEAVY DEEP WATER CRUDE OIL

37 GtC

18 GtC

ARTIC OIL

11 GtC

‘SAFE’ EMISSIONS LIMIT

CARBON CAPTURE AND STORAGE

130 GtC

34 GtC

Total remaining GtC allowance to avoid the most serious impacts and the risk of irreversible and uncontrollable changes to the climate***

Maximum possible carbon stored by 2050 using carbon capture and storage technologies****

TOTAL

14,236 GtC

* Carbon content estimates were calculated by taking averages from a variety sources and using conversion factors where appropriate (for example from a resource’s volume in barrels to the weight in carbon). As there is significant disagreement over the various resource estimates, some judgement had to be used in which figures to include in the calculations. For details of how the estimates were made go to <http://www.corporatewatch.org/uff/carbonbudget>. ** This is a minimum estimate. Other sources estimate that the technically recoverable resource for unconventional gas could be greater than 2,000 GtC. *** Limit taken from: ‘Assessing “Dangerous Climate Change”: Required Reduction of Carbon Emissions to Protect Young People, Future Generations and Nature’. Hansen et al (2013). <http://www.plosone.org/article/info%3Adoi%2F10.1371%2Fjournal.pone.0081648> **** Figure from: ‘Unburnable Carbon 2013: Wasted capital and stranded assets’. Carbon Tracker & The Grantham Research Institute, LSE (2013). <http://www.carbontracker.org>.

Summary table

p19

p27

shale gas tar sands Gas ( Tight

)

p35

Coalbed

Methane

p43

Underground CoalGasification

Fuel Description Natural gas trapped underground in shale rock which must be fractured to extract the gas

Climate change

Tar sands or oil sands consist of a thick, dense type of oil called bitumen mixed with sand, water and clay

Extracting methane from coal seams by drilling large numbers of wells. Usually involves pumping out very large volumes of groundwater to get the gas to flow and often involves hydraulic fracturing (fracking)

Burning coal seams underground and extracting the resulting gas to use as fuel

Global resources: 264 GtC

Global resources: 130 GtC

‘safe’ emission limit: 130GtC

Coal reserves = 500+ GtC

Extracting tar sands requires enormous amounts of energy and water, releases vast amounts of greenhouse gases and other pollutants and is devastating huge tracts of boreal forest and wetlands in Canada

Poses a serious risk of groundwater pollution, and causes significant greenhouse gas emissions, primarily through methane leakage

Very high water consumption, catastrophic groundwater contamination, dramatically increases accessible coal resources with severe implications for climate change

70% in Canada, with the next largest deposits in Kazakhstan (42 billion barrels of bitumen reserves), and Russia (28 billion barrels). Exploration and test projects have been carried out in Russia, Madagascar, Congo (Brazzaville), Utah in USA and Trinidad and Tobago

Extraction is widespread in the US (over 55,000 wells), Canada (over 17,000 wells), Australia (over 5000 wells) and China (thousands of wells). India also began commercial production in 2007 and now has hundreds of wells, and there are a handful of wells in the UK. Around 40 other countries are looking into exploiting their CBM resources

South Africa, Australia, China. Demonstration projects and studies are also currently under way in the USA, Western and Eastern Europe, Japan, Indonesia, Vietnam, India and Russia

(GtC = Gigatonnes of Carbon)

Global resources: Shale gas: 138 GtC Tight gas: 211 GtC ‘safe’ emission limit: 130GtC

UCG Would give access to even greater coal resources

Problems Extraction results in water pollution and methane leakage with serious consequences for climate change

Where it is found? Main countries (amounts in trillion cubic feet): 1 China 1,115 2 Argentina 802 3 Algeria 707 4 US 665 5 Canada 573 6 Mexico 545 7 Australia 437 8 South Africa 390 9 Russia 285 10 Brazil 245

p51

Oilshale

p59

shaleOil ( Tight oil)

Climate change

Crude oil found in shale or other rock where it is tightly held in place and does not flow easily

p71

Coaland gas to Liquids

Methane Hidrates

Turning coal or natural gas into liquid fuels

Methane (natural gas) and water trapped as an icy substance under the sea floor and in the Arctic permafrost

( Synthetic Liquid Fuels)

Fuel Description oily rock that can be burned, or processed to produce a liquid fuel

p67

(GtC = Gigatonnes of Carbon)

Global resources: 295GtC

‘safe’ emission limit: 130GtC

‘safe’ emission limit: 130GtC Coal reserves = 500+ GtC gas resources = 277GtC converting to liquid would add even more carbon to the atmosphere

Global resources: 163GtC

Requires use of fracking with risk of water pollution and worsens climate change

Process wastes a lot of energy and has serious consequences for water resources and climate change

Vast store of carbon, which if released would have devastating consequences for climate change

Economically recoverable shale oil reserves (International Energy Agency estimates in billions of barrels) Russia: 75 United States: 48 to 58 China: 32 Argentina: 27 Libya: 26 Venezuela: 13 Mexico: 13 Pakistan: 9 Canada: 9 Indonesia: 8

South Africa, US, Qatar, Uzbekistan and China

Several countries are investigating the possibilities of extraction, including the US, Japan, China, Germany, Norway, India, South Korea, UK,Taiwan, New Zealand, Brazil and Chile

Global resources: 42GtC

‘safe’ emission limit: 130GtC

Problems Extremely inefficient as a fuel, results in very high greenhouse gas emissions and serious water pollution

Where it is found? Estonia has a well developed oil shale industry, Oil shale is also exploited on an industrial scale in China (which is rapidly expanding its capacity), Brazil and less so in Russia, Germany and Israel. By far the largest deposits are found in the US

ends OF to

the

earth

Factsheets:

endsOFtheearth

the

Tight Gas

Tight gas refers to natural gas reservoirs trapped in highly impermeable rock, usually non- porous sandstone and sometimes limestone. It is found in different geological formations from shale gas (although according to some definitions shale gas is a form of tight gas). Over time, rocks are compacted and undergo cementation and recrystallisation, reducing the permeability of the rock. As with shale gas, directional drilling is used and fracking is necessary to break up the rock and allow the gas to flow. In addition to fracking, acidisation is also sometimes used. This is where the well is pumped with acid to dissolve the rock that is obstructing the flow of gas.

shale gas ( Tight Gas)

SHALE GAS IS NATURAL GAS THAT IS TRAPPED UNDERGROUND IN SHALE ROCK WHICH MUST BE FRACTURED TO EXTRACT THE GAS. EXTRACTION CAUSES WATER POLLUTION AND METHANE LEAKAGE WITH SERIOUS CONSEQUENCES FOR CLIMATE CHANGE.

While many of the problems posed by tight gas, such as water pollution and contributing to climate change, are similar to those of shale gas, there are some differences. For example the differing natural carbon content in tight gas means that it stores different kinds of contaminants and therefore produces different pollutants. Shale gas is also generally harder to extract, being even less permeable and requiring more fracking.

how is it extracted?

Shale gas has been known about for a long time. The first commercial gas well in the USA, drilled in New York State in 1821, was in fact a shale gas well. However, it is only since around 2005 that it has been exploited on a large-scale. This has been driven by the huge rise in energy prices resulting from declining fossil fuel reserves and the development of two new technologies, horizontal drilling and advanced hydraulic fracturing, which have opened up reserves previously inaccessible by conventional drilling.

Natural gas is mainly methane and is usually extracted from oil or gas fields and coal beds (see coal bed methane), but it can also be found in shale formations.

Hydraulic fracturing, often just referred to as fracking, is used to free gas trapped in rock by drilling into it and injecting pressurised fluid which creates cracks which release the gas. The fracking fluid consists of water, sand and a variety of chemicals which are added to aid the extraction process such as by dissolving minerals, killing bacteria that might plug up the well, or reducing friction.

Shale is a form of sedimentary rock formed from deposits of mud, silt and clay. Normally natural gas is extracted from sandstone or carbonate reserves, where the gas flows fairly easily once the rock is drilled into. However shale is relatively impermeable, meaning that it is harder for the gas to escape. It is only with the development of horizontal drilling and advanced hydraulic fracturing (see below) that shale gas extraction has become possible.

The fracking process also produces a large volume of waste water, containing a variety of contaminants both from the fracking fluid, and toxic/radioactive substances which are leached out of the rocks (see below).

what is it?

Production from shale gas wells declines very quickly and so new wells must be drilled constantly. This process of continual drilling and fracking means that huge areas of land are covered with well pads where thousands of wells are drilled, with each well requiring millions of litres of water.

"to replace the UK's

current gas imports

with local shale gas would require up to 20,000 wells to be drilled in the next 15 years" Climate change Natural gas, whether it comes from shale or conventional sources, is a fossil fuel and when it is burned it releases significant greenhouse gas emissions (GHG). It is sometimes argued that as burning natural gas produces less GHG emissions than coal it can be used as a ‘bridging’ or ‘transition’ fuel, replacing coal while renewable energy technologies are developed and implemented. This argument is widely used by governments and industry to promote gas as a low carbon energy option. However as long as energy demand increases, additional sources of fossil fuels such as shale gas are likely to supplement rather than replace other existing ones such as coal. This has happened in the US where the shale gas boom, instead of reducing coal extraction, has simply resulted in more of it being exported and used elsewhere.1 When comparing fuel types it is important to look at ‘lifecycle’ GHG emissions, the total emissions generated by developing and using the fuel. In the case of shale gas these include direct emissions from end-use consumption (e.g. from burning gas in power plants), indirect emissions from fossil fuels used to extract, develop and transport the gas, and methane from ‘fugitive’ emissions (leaks) and venting during well development and production. There is a lot of debate about how much gas escapes as fugitive methane emissions in the process of extracting and transporting natural gas. The gas industry is particularly reluctant to investigate this, which is partly why it is hard to find reliable figures. However various studies have found significant leakage, and since methane is a more potent GHG that CO2, even if just a small percentage of the gas extracted escapes to the atmosphere it can have a serious impact on the climate.

Some studies have concluded that fugitive emissions from shale gas could be between 3.6% and 7.9% particularly when the gas vented during flow-back is included.2 34 . This would make the GHG contribution from shale gas similar to or even worse than coal in terms of contributing to climate change. The shale gas industry attacked the findings and although there is ongoing dispute over the figures,5 6 recent hard data estimated methane leakage rates in some areas to be 6 to 12%, 7 up to 9%,8 or even as high as 17%.9 Methane is a powerful greenhouse gas, particularly in terms of its short term influence on the atmosphere. If more than 3.2% of methane is lost to the atmosphere then switching from coal to gas will result in no immediate benefits in terms of contribution to climate change.10

325 GtC TIGHT GAS

CONVENTIONAL GAS

277 GtC

211 GtC SHALE GAS

In order to 138 GtC stay within this limit we have to leave the vast majority of the remaining conventional oil, coal and gas in the ground. Estimates vary significantly, but remaining conventional coal reserves alone are well over 500GtC.13

Exploiting the world’s shale gas resources would add around 138 GtC to the atmosphere (with tight gas adding a further 211GtC).14 This is a huge amount and is clearly incompatible with staying within the limit outlined above. All of this means that, far from making things better, the development of shale and tight gas is dramatically worsening the problem of climate change.

Shale gas and Carbon Capture and Storage (CCS) There has been some discussion about the possibility of using exhausted shale gas formations as a storage location for CO2. Injecting CO2 into fracked shale deposits is also being considered as a way of both storing CO2 and extracting more gas at the same time (so called Enhanced Gas Recovery -see ‘Other Unconventional Fossil fuels’ factsheet). However, their viability as CO2 storage sites is questionable, and there are currently no shale gas sites being used to store CO2. In addition there are concerns that fracking may be compromising other potential CO2 storage sites, as the fracked shale formations are no longer impermeable and would therefore not keep CO2 trapped in the deep saline aquifers below them.15 In addition fracking, the underground injection of fracking waste water (see below), and even the injection of CO2 itself have been shown to cause earthquakes, which reveal a major flaw in CCS technology.16 17

Proponents of unconventional fossil fuels often argue that with CCS technologies, these new energy sources could be exploited at the same time as reducing GHG emissions. However, even if the huge problems with CCS technology are overcome (and this currently looking extremely unlikely), it would not change the fact that we need to move away from all forms of fossil fuel, conventional and unconventional, as soon as possible. In the most optimistic (and highly implausible) scenario, CCS could be used to reduce a small proportion of emissions from fossil fuels. In reality, the promise of CCS being implemented in the future is being used to allow the continued expansion of fossil fuel production, to prevent alternatives from being developed, and to deflect attention away from approaches which tackle the underlying systemic causes of climate change and other ecological crises. Ultimately CCS is a smokescreen, allowing the fossil fuel industry to continue profiting from the destruction of the environment. (see ‘Carbon Capture Storage’ factsheet for more information).

Other social and environmental issues Water use

Fracking requires huge volumes of water, which once used is contaminated and cannot be returned to the water table. The amount of water needed varies from well to well, but will be somewhere between about 3 million and 40 million litres. 18 In 2011, the U.S. Environmental Protection Agency estimated that 70 to 140 billion gallons (265 – 531 billion litres) of water was being used to fracture 35,000 wells in the United States each year.19 Sourcing water for fracking is a major problem. Because of the transportation costs of bringing water from great distances, drillers in the US usually extract on-site water from nearby streams or underground water supplies. This puts pressure on local water resources which can lead to the worsening of droughts and competition with farmers for irrigation water.20

Water and air pollution

to avoid stricter mandatory reporting requirements. Although the specific mix of chemicals used varies significantly, a US House of Representatives Committee on Energy and Commerce report found 750 different chemicals had been used in fracking fluids, including many known human carcinogens and other toxic compounds such as benzene and lead.21 Chemicals found to be most commonly used in fracking fluids such as methanol and isopropyl alcohol are also known air pollutants. A variety of chemicals are also added to the ‘muds’ used to drill well boreholes in order to reduce friction and increase the density of the fluid. Analysis of drilling mud has also found that they contain a number of toxic chemicals. 22 23 Increasing numbers of studies analysing water quality in drinking wells near natural gas extraction sites have also found increased levels of contamination, 24 25 26 and several studies have suggested possible pathways through which contaminants could reach drinking water aquifers from fractured shale. 27 Another area of controversy is that of methane pollution of local water supplies. Footage of people living close to fracking sites setting light to the water coming out of their tap has rapidly spread across the internet.

The industry was quick to respond, saying that these were just cases of supplies that were already prone to natural gas contamination. However, a leaked 2012 US Environmental Protection Agency presentation suggests that methane could be migrating more widely to water supplies as a result of fracking, a conclusion that was censored by the Obama administration.28 Other research has also found evidence of methane and other contamination of water supplies due to fracking,29 including a 2011 peer-reviewed study which found â&#x20AC;&#x153;systematic evidence for methane contaminationâ&#x20AC;? of drinking water associated with shale gas extraction.30 There is, however, currently a lack of research on the health impacts of long-term exposure to methane in drinking water.31 Leakage of both methane and other chemicals involved in fracking is a huge problem. Despite industry claims that leakage is due to bad well design, research has shown that some leakage is an inevitability and that fracking only exacerbates the problem.32 Wells routinely lose their structural integrity and leak methane and other contaminants outside their casings and into the atmosphere and water wells. Even research by oil services company Schlumberger suggests that half of all gas wells will be leaking within 15 years (see climate change section for more on leakage of methane to the atmosphere). 33 Local air pollution at shale gas sites is also a serious concern. This includes emissions from vehicle traffic, flaring and venting during drilling and completion, on-site machinery such as compressors, and processing and distribution, where gas can leak from pipes and at compressor stations. Local air pollution from these sources includes BTEX (benzene, toluene, ethylene and xylene), NOx (mono oxides of nitrogen), VOCs (volatile organic compounds), methane, ethane, sulphur dioxide, ozone and particulate matter.34

Research has shown that air pollution caused by extraction may contribute to acute and chronic health problems for those living near natural gas drilling sites,35 and there is a growing body of research identifying the health impacts of fracking and unconventional gas extraction. 36 37 38

Waste water

The fracking process produces large volumes of waste water, contaminated by fracking fluids, and naturally occurring chemicals leached out of the rock. These can include dissolved solids (e.g., salts, barium, strontium), organic pollutants (e.g., benzene, toluene) and normally occurring radioactive material (NORM) such as the highly toxic Radium 226. 39 This leaves the problem of how to dispose of this waste water. In many cases, the waste water is re-injected back into the well, a process that has been shown to trigger earthquakes (see earthquake section). In the US, there have been numerous cases in which drilling cuttings have been dumped and waste water stored in open evaporation pits. In some cases waste water has even been disposed of by spreading it on roads under the guise of dust control or de-icing. Treatment of fracking waste water is expensive and energy intensive, and still leaves substantial amounts of residual waste that then also has to be disposed of. In addition, the waste water from most sites would have to transported large distances to specialised treatment plants. The sheer volumes of waste water generated and the kinds of contaminants it contains makes treating and disposing of it safely extremely challenging. All stages of the waste water disposal process are of course prone to accidents, which could have serious environmental and human health consequences.

Human and animal health

It is difficult to assess the health effects of fracking sites, as many impacts will take time to become apparent and there is a lack of background data and official studies. Despite this there is mounting evidence linking fracking activities to local health impacts on humans and animals. 40 41 42

Industrialisation of countryside Diagram of fracking operations

Unlike conventional gas, exploiting shale gas requires large numbers of wells to be drilled. As shale is impermeable the gas cannot easily flow through it and wells are needed wherever there is gas. In some cases up to sixteen wells per square mile have been drilled.43

In addition to the wells, extensive pipeline networks and compressor stations are required. In the US tens of thousands of shale wells have been drilled leading to widespread industrialisation of the landscape in some states. Similarly, to replace the UK’s current gas imports with local shale gas would require up to 20,000 wells to be drilled in the next 15 years.44 Apart from the noise, light pollution and direct impact on local wildlife and ecosystems due to the well pads, shale gas extraction also results in large increases in traffic for transportation of equipment, waste water and other materials. It has been estimated that fracking requires 3,950 truck trips per well during early development of the well field.45 A single well pad could generate tens of thousands of truck journeys over its lifetime. 46

Earthquakes

Underground fluid injection has been proven to cause earthquakes, and there are instances in the UK where fracking has been directly linked to small earthquakes.47 The injection of waste water from fracking back in to wells has also been shown to cause earthquakes.48 Although these earthquakes are usually relatively small, they can still cause minor structural damage and of particular concern is the possibility of damaging the well casings thus risking leakage. This did in fact happen after the earthquake at Cuadrilla’s site in Lancashire, UK. The company failed to report the damage and were later rebuked by the then UK energy minister, Charles Hendry, for not doing so. Occasionally larger earthquakes are triggered. A 2013 study in prestigious journal Science linked a dramatic increase in seismic activity in the midwestern United States to the injection of waste water. It also catalogues the largest quake associated with waste water injection, which occurred in Prague on November 6, 2011. This measured 5.7 on the Richter scale, and destroyed fourteen homes, buckled a highway and injured two people.49 It should be noted that mining and conventional gas and oil extraction can also cause earthquakes.

Jobs

Those trying to promote shale gas often cite the employment that it will generate as an argument in its favour. In practice much of the employment related to fracking will come from outside the area where the gas is extracted, and any boost to the local economy is relatively short-lived as the industry moves on once wells are depleted. Industry backed studies have been

found to routinely exaggerate estimates of the number of jobs fracking will create. 50

Economic issues

The rate at which a resource can be extracted strongly influences its value as a fuel source. Estimates of reserves containing ‘so many years worth’ of a country’s gas supply ignore the fact that it will take many years and thousands of wells drilled before production rates rise sufficiently to provide significant amounts of fuel. This counteracts the argument that shale gas can be used as a ‘bridging fuel’ in the short term while renewables are developed. 51 In the US, which is largely isolated from the world gas market due to transport issues, the shale gas boom has coincided with a recession, which has led to a reduction in energy demand and gas prices. This has actually made it uneconomical to produce shale gas, and has stalled drilling. Well production rates have also declined faster than expected, and spending on new sites has reduced as shale gas assets have lost value.52 For these and other reasons to do with more integrated gas markets, shale gas is unlikely to make a significant impact on the price of gas in Europe and Asia, and promises of cheaper fuel prices for consumers are unlikely to be realised. Natural gas can be converted to Liquefied Natural Gas (LNG), which can then be transported in specialised ships rather than pipelines. This is one way for the US to export shale gas to other markets. However, the processes of liquification, tanker transportation and gassification mean that using LNG requires significantly more energy and results in greater GHG emissions.53 As the most productive shale plays and their ‘sweet spots’ are exploited first, it becomes increasingly more expensive, both in terms of money and energy, to maintain production levels.54 There are predictions that the shale gas boom in the US may have already peaked.55 There have also been suggestions that much of the investment into shale gas in the US was based on over estimation of reserve sizes and underestimation of the costs involved.56 Concerns that the same kind of financial practices that led to the US housing bubble were used to provide investment (with the prospect of profitable merger and acquisition deals attracting the financial sector) have led some to predict that the financial bubble behind the US shale boom will burst, possibly instigating another global economic crisis.57

Where and how Much?

Shale gas deposits occur across the globe, but there are significant variations in the estimates of how much shale gas exists and how much of it can be extracted, partly due to the variations in geology from region to region. In 2013 the US Energy Information Administration put the global amount of technically recoverable shale gas as 7299 trillion cubic feet (tcf),58 or 207 trillion cubic metres (tcm), with the top 10 countries in terms of resources (in tcf) as:

1 China 1,115 2 Argentina 802 3 Algeria 707 4 US 665 5 Canada 573 6 Mexico 545 7 Australia 437 8 South Africa 390 9 Russia 285 10 Brazil 245

In 2013 the World Energy Council made slightly lower estimates, with global resources of 16,110 tcf (456 tcm), of which 6444 tcf (182 tcm) is expected to be technically recoverable. 59

The industry is by far most advanced in the US, where there has been a boom in shale gas with tens of thousands of wells drilled. Other countries with large reserves are at various stages of exploration and production. China has the largest shale gas resources in the world, but the geology of its shale formations, particularly their depth, may make extraction much more difficult than in the US. Activity in China is mainly at

the exploration and test well stage, but production capacity is rapidly increasing.60 In Argentina, which has the second largest resources, several contracts have been awarded and exploration and test wells have been drilled by a number of companies. A host of other countries are exploring shale gas production including, Australia, Austria, Canada, Germany, Hungary, India, New Zealand, Poland, South Africa, Sweden and the UK.

companies involved In the US, the shale gas industry is not dominated by the multinational super-majors such as Exxon, Shell and Total. Instead variously sized American companies operate, anywhere from tiny start-ups to mid sized companies worth tens of billions. Notable US shale companies include Chesapeake Energy, Continental Resources, Marathon Oil, Occidental Petroleum, Pioneer Natural Resources, Apache, Whiting Petroleum, Hess, EOG Resources, ConocoPhillips. That said, some large multinational oil companies have now also acquired significant stakes

in North American shale gas including Exxon, Total, Shell, CNP and Reliance Industries. In places where the shale gas industry is yet to gain a foothold, sometimes small exploratory companies carry out the initial drilling and testing. These are then acquired by larger gas companies if economically recoverable deposits are found. This serves to protect the risk to bigger companies if testing is unsuccessful. However large oil multinationals are also involved in exploratory drilling in a number of regions, including China, Europe and South America.

Resistance Shale gas extraction, and particularly fracking, has met widespread resistance around the world. In the US, spurred on by the 2010 documentary film Gasland, a national anti-fracking movement is now active across the country. Following protests, various countries and regions have introduces moratoriums or outright bans on fracking. These include France, Bulgaria, Romania and the Czech Republic (see <http://keeptapwatersafe. org/global-bans-on-fracking/> for an updated list of countries and regions).

Adrian Kinloch

A number of countries have seen protesters using direct action and civil disobedience to oppose fracking. Australia’s ‘Lock the Gate’ movement has involved environmental activists joining Adam Welz for CREDO Action forces with local communities to prevent exploration, with widespread use of blockades. Despite violent repression from the police, the villagers of Pungesti, Romania have put up strong resistance to Chevron’s plans to frack the area, removing and sabotaging their testing equipment. The indigenous Elsipogtog First Nation along with other local residents blockaded a road near Rexton, New Brunswick, Canada, preventing South Western Energy from carrying out tests at a potential shale gas site. In the UK dozens have been arrested in community blockades of exploration sites , such as in Balcombe and Barton Moss.

For more information on resistance see the Corporate Watch website (corporatewatch.org/uff/resistance)

Endnotes 1 Broderick, J., and K. Anderson. ‘Has US shale gas reduced CO2 emissions? Examining recent changes in emissions from the US power sector and traded fossil fuels (Technical Report)’. Manchester: Tyndall Centre (2012).<http://tyndall. ac.uk/publications/technical-report/2012/ has-us-shale-gas-reduced-co2-emissions> 2 Howarth, R. W., R. Santoro, and A. Ingraffea. ‘Methane and the greenhouse gas footprint of natural gas from shale formations’. Climatic Change Letters (2011), DOI: 10.1007/s10584-011-0061-5. <http://link.springer.com/ article/10.1007%2Fs10584-011-0061-5> 3 (estimates also within the 3.6% to 7.9% range) Pétron, G. et al. J. Geophys. Res. 117, D04304 (2012) 4 (estimates also within the 3.6% to 7.9% range) ‘Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990–2010’ (Chapter 3: Energy). US EPA (2012). <http://epa.gov/climatechange/Downloads/ ghgemissions/US-GHG-Inventory-2012-Chapter-3Energy.pdf> 5 Howarth, Robert W., Renee Santoro, and Anthony Ingraffea. ‘Venting and Leaking of Methane from Shale Gas Development: Response to Cathles et Al.’ Climatic Change 113, no. 2 (1 February 2012): 537–549. doi:10.1007/s10584-012-0401-0. <http://www.eeb. cornell.edu/howarth/publications/Howarthetal2012_ Final.pdf> 6 ‘New Study Shows Total North American Methane Leaks Far Worse than EPA Estimates’. DeSmogBlog. Accessed 28 February 2014. <http://www.desmogblog. com/2014/02/14/new-study-shows-total-northamerican-methane-leaks-far-worse-epa-estimates> 7 Karion, Anna, Colm Sweeney, Gabrielle Pétron, Gregory Frost, R. Michael Hardesty, Jonathan Kofler, Ben R. Miller, et al. ‘Methane Emissions Estimate from Airborne Measurements over a Western United States Natural Gas Field: CH4 EMISSIONS OVER A NATURAL GAS FIELD’. Geophysical Research Letters 40, no. 16 (28 August 2013): 4393–4397. doi:10.1002/

grl.50811. <http://onlinelibrary.wiley.com/doi/10.1002/ grl.50811/abstract> 8 Tollefson, Jeff. ‘Methane Leaks Erode Green Credentials of Natural Gas’. Nature 493, no. 7430 (2 January 2013): 12–12. doi:10.1038/493012a. <http://www.nature.com/news/methane-leakserode-green-credentials-of-natural-gas-1.12123#/ b1> 9 Peischl, J., T. B. Ryerson, J. Brioude, K. C. Aikin, A. E. Andrews, E. Atlas, D. Blake, B. C. Daube, J. A. de Gouw, E. Dlugokencky, G. J. Frost, D. R. Gentner, J. B. Gilman, A. H. Goldstein, R. A. Harley, J. S. Holloway, J. Kofler, W. C. Kuster, P. M. Lang, P. C. Novelli, G. W. Santoni, M. Trainer, S. C. Wofsy, D. D. Parrish. ‘Quantifying sources of methane using light alkanes in the Los Angeles basin, California’. J. Geophys. Res. Atmos., doi:10.1002/jgrd.50413, 2013. <http://www.esrl. noaa.gov/csd/news/2013/140_0514.html> 10 Alvarez, R. A., Pacala, S. W. Winebrake, J. J., Chameides, W. L. & Hamburg, S. P. Proc. Natl Acad. Sci. USA 109, 6435–6440 (2012). <http://www.pnas. org/content/109/17/6435> 11 Hansen, James, Pushker Kharecha, Makiko Sato, Valerie Masson-Delmotte, Frank Ackerman, David J. Beerling, Paul J. Hearty, et al. ‘Assessing “Dangerous Climate Change”: Required Reduction of Carbon Emissions to Protect Young People, Future Generations and Nature’. Edited by Juan A. Añel. PLoS ONE 8, no. 12 (3 December 2013): e81648. doi:10.1371/journal.pone.0081648. <http://www. plosone.org/article/info%3Adoi%2F10.1371%2Fjournal. pone.0081648> 12 Ibid 13 Ibid 14 <http://www.corporatewatch.org/uff/carbonbudget> 15 Elliot, T. R., and M. A. Celia. ‘Potential Restrictions for CO2 Sequestration Sites Due to Shale and Tight Gas Production’. Environmental Science & Technology

46, no. 7 (3 April 2012): 4223–4227. doi:10.1021/ es2040015.<http://pubs.acs.org/doi/abs/10.1021/ es2040015> 16 Verdon, J. P., J.- M. Kendall, A. L. Stork, R. A. Chadwick, D. J. White, and R. C. Bissell. ‘Comparison of Geomechanical Deformation Induced by Megatonne-Scale CO2 Storage at Sleipner, Weyburn, and In Salah’. Proceedings of the National Academy of Sciences 110, no. 30 (8 July 2013): E2762–E2771. doi:10.1073/pnas.1302156110. <http://www.pnas.org/ content/early/2013/07/03/1302156110.abstract> 17 Gan, W., and C. Frohlich. ‘Gas Injection May Have Triggered Earthquakes in the Cogdell Oil Field, Texas’. Proceedings of the National Academy of Sciences 110, no. 47 (4 November 2013): 18786–18791. doi:10.1073/ pnas.1311316110. <http://www.pnas.org/content/ early/2013/10/31/1311316110> 18 Cooley, H, Donnelly, K. ‘Hydraulic Fracturing and Water Resources: Separating the Frack from the Fiction’. Pacific Institute (June 2012). <http://www.pacinst.org/ wp-content/uploads/2013/02/full_report35.pdf> 19 ‘Draft Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources’. US EPA. (Feb 2011).<http://yosemite.epa.gov/sab/sabproduct. nsf/0/D3483AB445AE61418525775900603E79/ $File/Draft+Plan+to+Study+the+Potential+ Impacts+of+Hydraulic+Fracturing+on+Drinking+Water +Resources-February+2011.pdf> 20 ‘A Texan tragedy: ample oil, no water’. Guardian website (Retrieved Feb 2014). <http://www. theguardian.com/environment/ 2013/aug/11/texas-tragedy-ample-oil-no-water> 21 ‘Chemicals used in hydraulic fracturing’. United States House of Representatives, Committee on Energy and Comerce Minority Staff (April 2011). <http://democrats.energycommerce.house.gov/ sites/default/files/documents/Hydraulic-FracturingChemicals-2011-4-18.pdf>

22 Colborn, Theo et al. ‘Natural Gas Operations from a Public Health Perspective’. International Journal of Human and Ecological Risk Assessment. September-October 2011, p. 11. <http://cce.cornell.edu/ EnergyClimateChange/NaturalGasDev/Documents/ PDFs/fracking%20chemicals%20from%20a%20 public%20health%20perspective.pdf> 23 ‘Toxic Chemicals in the Exploration and Production of Gas from Unconventional Sources’. National Toxics Network (April 2013). <http://www.ntn.org.au/wp/wpcontent/uploads/2013/04/UCgas_report-April-2013. pdf> 24 Fontenot, Brian E., Laura R. Hunt, Zacariah L. Hildenbrand, Doug D. Carlton Jr., Hyppolite Oka, Jayme L. Walton, Dan Hopkins, et al. ‘An Evaluation of Water Quality in Private Drinking Water Wells Near Natural Gas Extraction Sites in the Barnett Shale Formation’. Environmental Science & Technology 47, no. 17 (3 September 2013): 10032–10040. doi:10.1021/es4011724. <http://pubs.acs.org/doi/abs/10.1021/es4011724> 25 ‘EPA Releases Draft Findings of Pavillion, Wyoming Ground Water Investigation for Public Comment and Independent Scientific Review’. US EPA press release (12/08/2011). <yosemite.epa.gov/opa/ admpress.nsf/20ed1dfa1751192c8525735900400c30/ ef35bd26a80d6ce3852579600065c94e!OpenDocument> 26 ‘Canadian authorities: Fracking operation contaminated groundwater’. National Resource Defence Council website (Posted December 20, 2012). <http://switchboard.nrdc.org/blogs/amall/ canadian_authorities_leaked_fr.html> 27 Myers, Tom. ‘Potential Contaminant Pathways from Hydraulically Fractured Shale to Aquifers’. Ground Water 50, no. 6 (November 2012): 872–882.doi:10.1111/ j.1745-6584.2012.00933.x.<http://onlinelibrary.wiley. com/doi/10.1111/j.1745-6584.2012.00933.x/abstract> 28 ‘Inside the Censored EPA Fracking Water Study’. Counterpunch.org (August 06, 2013). <http://www. counterpunch.org/2013/08/06/inside-the-censoredepa-pennsylvania-fracking-water-contamination-study > 29 Jackson, R. B., A. Vengosh, T. H. Darrah, N. R. Warner, A. Down, R. J. Poreda, S. G. Osborn, K. Zhao, and J. D. Karr. ‘Increased Stray Gas Abundance in a Subset of Drinking Water Wells near Marcellus Shale Gas Extraction’. Proceedings of the National Academy of Sciences 110, no. 28 (24 June 2013): 11250–11255. doi:10.1073/pnas.1221635110. <http://www.pnas.org/ content/110/28/11250.full > 30 Osborn, S. G., A. Vengosh, N. R. Warner, and R. B. Jackson. ‘Methane Contamination of Drinking Water Accompanying Gas-Well Drilling and Hydraulic Fracturing’. Proceedings of the National Academy of Sciences 108, no. 20 (9 May 2011): 8172–8176. doi:10.1073/pnas.1100682108. <http://www.pnas.org/ content/108/20/8172.long> 31 Jackson RB, et al. ‘Research and policy recommendations for hydraulic fracturing and shalegas extraction’. Durham, NC: Duke University, Center on Global Change 2011. <http://www.nicholas.duke.edu/ cgc/HydraulicFracturingWhitepaper2011.pdf> 32 ‘Wellbore Leakage Potential in CO2 Storage or EOR’. Fourth Wellbore Integrity Network Meeting, Paris, France. March 19, 2008. <http://www.ieaghg.org/docs/ wellbore/Wellbore%20Presentations/4th%20Mtg/19. pdf> 33 ‘From Mud to Cement—Building Gas Wells ‘. Oilfield review (Autumn 2003) <http://www.slb.com/~/media/ Files/resources/oilfield_review/ors03/aut03/p62_76. pdf>

34 ‘Environmental water and air quality issues associated with shale gas development in the Northeast’. Environmental water and air quality working group, NYS Water Resources Institute, Cornell University. <http://wri.eas.cornell.edu/MSARC%20Env%20 H2O%20Air%20Group%20Revised%20071012.pdf> 35 McKenzie, Lisa M., Roxana Z. Witter, Lee S. Newman, and John L. Adgate. ‘Human Health Risk Assessment of Air Emissions from Development of Unconventional Natural Gas Resources’. Science of The Total Environment 424 (May 2012): 79–87. doi:10.1016/j. scitotenv.2012.02.018. <http://cogcc.state.co.us/library/ setbackstakeholdergroup/Presentations/Health%20 Risk%20Assessment%20of%20Air%20Emissions%20 From%20Unconventional%20Natural%20Gas%20-%20 HMcKenzie2012.pdf> 36 McDermott-Levy, By Ruth, Nina Kaktins, and Barbara Sattler. ‘Fracking, the Environment, and Health:’ AJN, American Journal of Nursing 113, no. 6 (June 2013): 45–51. doi:10.1097/01.NAJ.0000431272.83277.f4. <http://lgdata.s3-website-us-east-1.amazonaws.com/ docs/350/860804/Article_4.pdf> 37 Witter RZ. ‘Use of health impact assessment to help inform decision making regarding natural gas drilling permits in Colorado’. Glenwood Springs, CO: Garfield County (CO) Board of County Commissioners; 2010 Oct 4. <http://www.garfield-county.com/ public-health/documents/BOCC_Draft_HIA_ Presentation_10_4_10%5B1%5D.pdf> 38 R Witter, Colorado School of Public Health. ‘Use of Health Impact Assessment to Help Inform Decision Making Regarding Natural Gas Drilling Permits In Colorado’. Presentation to, Board of County Commissioners, Garfield County (October 4, 2010). <http://www.garfield-county.com/ public-health/documents/BOCC_Draft_HIA_ Presentation_10_4_10%5B1%5D.pdf> 39 Mielke E, Anadon LD, Narayanamurti V. ‘Water Consumption of Energy Resource Extraction, Processing, and Conversion’. Harvard Kennedy School, Belfer Center for Science and International Affairs. October 2010. <http://belfercenter.ksg.harvard.edu/ files/ETIP-DP-2010-15-final-4.pdf> 40 ‘Statement on Preliminary Findings from the Southwest Pennsylvania Environmental Health Project Study’. Press Release, Concerned Health Professionals of New York (27 Aug 2013) <http://concernedhealthny. org/statement-on-preliminary-findings-from-thesouthwest-pennsylvania-environmental-healthproject-study/ > 41 Steinzor N, Septoff A. ‘Gas Patch Roulette, How Shale Gas Development Risks Public Health in Pennsylvania’. EarthWorks (Oct 2012). <http://www.earthworksaction. org/library/detail/gas_patch_roulette_full_report#. UwzG187xHSe> 42 Slatin, Craig, and Charles Levenstein. ‘An Energy Policy That Provides Clean and Green Power’. NEW SOLUTIONS: A Journal of Environmental and Occupational Health Policy 23, no. 1 (1 January 2013): 1–5. doi:10.2190/NS.23.1.a. <http://www. prendergastlibrary.org/wp-content/uploads/2013/03/ New-Solutions-23-1-Binder.pdf> 43 Draft Scoping Document for Horizontal Drilling and High Volume Hydraulic Fracturing to Develop Shale and Other Low Permeability Gas Reservoirs. New York Sate Department of Environmental Conservation, Division of Mineral Resources (Sep 2009). <ftp://ftp. dec.state.ny.us/dmn/download/OGdSGEISFull.pdf> 44 ‘UK shale gas no “get out of jail free card”’. Bloomburg New Energy Finance (21 February 2013). <http://about.bnef.com/press-releases/ uk-shale-gas-no-get-out-of-jail-free-card/>

45 ‘Revised Draft SGEIS on the Oil, Gas and Solution Mining Regulatory Program (September 2011)’ New York State Department of Environmental Conservation (2011). <http://www.dec.ny.gov/energy/75370.html> 46 ‘How many tanker trucks does it take to supply water to and remove waste from a horizontally drilled and hydrofracked wellsite’. un-naturalgas. org. <http://www.un-naturalgas.org/Rev%201%20 Truckloads+to+service+a+well+pad+-+DJC.pdf> 47 ‘Fracking and Earthquake Hazard’, British Geological Survey website (accessed Feb 2014). <http:// earthquakes.bgs.ac.uk/research/earthquake_hazard_ shale_gas.html> 48 ‘Man-Made Earthquakes Update’ US geological survey website (Posted on 17 Jan, 2014). <http:// www.usgs.gov/blogs/features/usgs_top_story/ man-made-earthquakes/> 49 Van der Elst, N. J., H. M. Savage, K. M. Keranen, and G. A. Abers. ‘Enhanced Remote Earthquake Triggering at Fluid-Injection Sites in the Midwestern United States’. Science 341, no. 6142 (11 July 2013): 164–167. doi:10.1126/ science.1238948. <http://www.sciencemag.org/ content/341/6142/164.abstract> 50 ‘Exaggerating the Employment Impacts of Shale Drilling: How and Why’ Multi-State Shale Research Collaborative (Nov 2013). <http://www.multistateshale. org/shale-employment-report> 51 Hughes D J. ‘Drill, Baby, Drill: Can Unconventional Fuels Usher in a New Era of Energy Abundance?’. Post Carbon Institute (Mar 2013). <http://www.postcarbon. org/drill-baby-drill/> 52 ‘Shale Grab in U.S. Stalls as Falling Values Repel Buyers’. Bloomberg. Accessed 25 February 2014. <http://www.bloomberg.com/news/2013-08-18/shalegrab-in-u-s-stalls-as-falling-values-repel-buyers. html> 53 Jaramillo, Paulina, W. Michael Griffin, and H. Scott Matthews. ‘Comparative Life-Cycle Air Emissions of Coal, Domestic Natural Gas, LNG, and SNG for Electricity Generation’. Environmental Science & Technology 41, no. 17 (September 2007): 6290–6296. doi:10.1021/es063031o. <http://pubs.acs.org/doi/ abs/10.1021/es063031o> 54 Op.Cit. (Hughes et al. 2013) 55 Ibid 56 ‘Fracking and the Shale Gas “Revolution”‘. Global Research website. Accessed 25 February 2014. <http://www.globalresearch.ca/ fracking-and-the-shale-gas-revolution/5345815> 57 D Rogers. ‘Shale and wall street: was the decline in natural gas prices orchestrated?’. Energy Policy Forum (Feb 2013). <http://shalebubble.org/wall-street/> 58 ‘Technically Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries Outside the United States’. U.S. Energy Information Administration (June 2013). <http://www. eia.gov/analysis/studies/worldshalegas/pdf/overview. pdf> 59 ‘World Energy Resources: 2013 Survey’. World Energy Council (2013). <http://www.worldenergy.org/ publications/2013/world-energy-resources-2013survey > 60 ‘China’s 2013 Shale Gas Output Rises to 200 Million Cubic metres’. Bloomberg. Accessed 25 February 2014. <http://www.bloomberg.com/news/2014-01-08/chinas-2013-shale-gas-output-rises-to-200-million-cubicmetres.html>

endsOFtheearth

the

a guide To unconventional fossil fuels

Corporate Watch

endsOFtheearth

the

how is it extracted?

Tar sands can be extracted and processed using a variety of techniques which can be classified as ‘surface mining’, where the tar sands are dug out and transported for crushing and processing, or in-situ (underground) techniques, where the oil is made to flow by injecting steam, solvents and/or hot air into the sands. In shallower deposits, surface strip mining with huge shovels and trucks can be used. The resulting mixture of bitumen, sand and water is then taken to a crusher. Once broken up the bitumen is separated from water and other materials.

tar sands TAR SANDS OR OIL SANDS CONSIST OF A THICK, DENSE TYPE OF OIL CALLED BITUMEN MIXED WITH SAND, WATER AND CLAY. EXTRACTION REQUIRES ENORMOUS AMOUNTS OF ENERGY AND WATER, RELEASES VAST AMOUNTS OF GREENHOUSE GASES AND OTHER POLLUTANTS AND IS DEVASTATING HUGE TRACTS OF BOREAL FOREST AND WETLANDS IN CANADA.

Deeper deposits, below around 225ft (69m), are extracted using various in-situ techniques. The most commonly used, Steam Assisted Gravity Drainage (SAGD) and Cyclic Steam Stimulation (CSS) involve injecting the deposit with steam, which heats the bitumen to make it flow. The bitumen is then pumped out and transported for further processing. Of the two methods, SAGD is cheaper and has been widely adopted by the tar sands industry. Other in-situ processes have been experimented with, such as using solvents instead of steam, and Toe to Heel Air Injection (THAI), where the bitumen is ignited underground. Once the bitumen has been extracted and separated from the sand and water it is then either diluted with light oil or natural gas liquids to make ‘dilbit’ (diluted bitumen) which can be piped to refineries, or ‘upgraded’, where it is partially refined to produce ‘syncrude’ (synthetic crude). All forms of tar sands extraction require huge amounts of energy and water, and are highly carbon intensive. However, in-situ processes, which will be increasingly required to access most of the tar sands deposits, use even more resources than surface mining, and have resulted in oil spills as heated, pressurised bitumen escapes into the environment (see ‘Oil Spills’ section below).

what is it?

Tar sands, also known as oil sands or bituminous sands, are a mixture of sand, water and clay with a dense, sticky, semi-solid form of crude oil called bitumen. Although very similar in appearance, technically bitumen is not the same as tar, which is a man made product. Bitumen needs to be heated or diluted to make it flow, which distinguishes it from 'extra-heavy crude', another form of high density unconventional oil, the largest deposits of which occur in Venezuela's Orinoco Belt (see 'Extra heavy oil' in 'Other Unconventional Fossil Fuels' factsheet).

Most of the world's tar sands are found in Canada where extraction is taking place on an enormous scale, with devastating effects on the local environment and critical implications for climate change. Most of the Canadian tar sands are in three major deposits in Northern Alberta which together cover more than 140,000 km2, an area larger than England. In 2011, Alberta's bitumen production reached over 1.7 million barrels (270,278 m3) per day.1 Tar sands also occur in other parts of the world, with the next largest deposits in Kazakhstan and Russia. Exploration and test projects have been carried out in Russia, Madagascar, Congo (Brazzaville), and Utah in the USA.

Upgrading and Petcoke Tar sands require much more processing than conventional crude oil to convert them into useful products such as petroleum. In many cases an upgrading process, which involves taking out impurities and adding hydrogen, takes place near to where the tar sands are extracted. This ‘hydro-processing’ converts the bitumen into synthetic crude, which can then be transported to refineries for further processing. The upgrading of tar sands produces ‘petcoke’ (petroleum coke)’, a coal-like substance which is also a by-product of oil refining. At least 15 % of bitumen (by volume) ends up as petcoke.2 Canadian petcoke production at upgraders in Alberta and Saskatchewan alone (excluding petcoke produced at Canadian refineries) was nearly 9 million tonnes in 2011. This has led to huge stockpiles forming. At the end of 2011, 72.3 million tonnes of petcoke was stockpiled in Alberta, an amount that is growing by about 4.4. million tonnes a year.3

Petcoke can be burned for energy, and it is mostly used alongside coal in power plants and to provide energy for cement production. However, when used as fuel it has been estimated to produce about 7% more CO2 per unit of energy than coal, making it a highly carbon-intensive energy source.4 In addition, some pollutants, such as heavy metals, become more concentrated in the petcoke.5 This means that when it is used with coal for power generation it increases the already substantial toxic emissions that result from burning coal. The increased production of petcoke from the processing of bitumen and heavy oils in the last decade has led to a sharp rise in its use in coal power stations. This has had the effect of both making the highly polluting coal power stations more economical to run, and further increasing their already massive CO2 emissions. Aside from tar sands, petcoke produced from conventional oil refining is a serious global issue, and huge volumes of it are being burned in China for energy.6

Climate change

The extraction of tar sands produces three to four times the greenhouse gas (GHG) emissions of conventional oil extraction,7 making its total lifecycle emissions (including all emissions generated in extraction, transportation and end use) 8% to 37% higher than conventional oil.8 These may well be underestimates, as a full ‘well to wheels’ analysis should include emissions from all sources, some of which, such as methane emissions from tailing ponds, land-use change (particularly wetlands) and the emissions from refining and upgrading (particularly downstream upgrading) are difficult to quantify and not included in some studies. The tar sands industry has been keen to point out that it has reduced emissions intensity (emissions per barrel). However, these reductions are mainly from switching to natural gas to fuel operations (which happened in the early 2000s), and it remains a highly carbon-intensive process. Overall emissions from tar sands have actually increased as reductions from intensity improvements are negated by increased production rates. In addition, as surface mining to remove the more easily accessible deposits is replaced by in-situ extraction, with higher CO2 emissions, the carbon-intensity of tar sands is starting to increase again.9 10 11 Regardless of how they compare to conventional crude, the Canadian tar sands represent a huge source of carbon which if fully exploited would result in billions of tonnes of CO2 being added to the atmosphere, putting us firmly on the path to irreversible catastrophic climate change. This has made the Canadian tar sands a major focus for climate campaigners across the world.

CONVENTIONAL OIL ‘SAFE’ EMISSIONS LIMIT 130 GtC

325 GtC TAR SANDS

264 GtC

CONVENTIONAL GAS

277 GtC

If we are to reduce carbon emissions to anything like the levels required to maintain a reasonably habitable planet we must move away from all forms of fossil fuel as fast as possible. Measuring from the start of the industrial revolution (around 1750), a maximum of 500 Gigatonnes of carbon (GtC) can be emitted to the atmosphere while still avoiding most serious impacts and the risk of irreversible and uncontrollable changes to the climate.12 Between 1750 and now (2014), we have already emitted about 370 GtC leaving a limit of 130 GtC that could be further added.13 In order to stay within this limit we have to leave the vast majority of the remaining conventional oil, coal and gas in the ground. Estimates vary significantly, but remaining conventional coal reserves alone are well over 500 GtC.14

Fully exploiting the tar sands would add around 264 GtC to the atmosphere.15 Therefore developing tar sands and releasing the enormous amounts of carbon they contain, is absolutely incompatible with staying below the limit outlined above.

"The Alberta Tar Sands cover more than 140,000 km2, an area larger than England" Julia Kilpatrick, the Pembina Institute

The tar sands and Carbon Capture and Storage (CCS)

Proponents of unconventional fossil fuels often argue that with CCS technologies, these new energy sources could be exploited at the same time as reducing greehouse gas (GHG) emissions. However, even if the huge problems with CCS technology are overcome (and this currently looking extremely unlikely), it would not change the fact that we need to move away from all forms of fossil fuel, conventional and unconventional, as soon as possible. In the most optimistic (and highly implausible) scenario, CCS could be used to reduce a small proportion of emissions from fossil fuels. In reality, the promise of CCS being implemented in the future is being used to allow the continued expansion of fossil fuel production, to prevent alternatives from being developed, and to deflect attention away from approaches which tackle the underlying systemic

causes of climate change and other ecological crises. Ultimately CCS is a smokescreen, allowing the fossil fuel industry to continue profiting from the destruction of the environment. (see ‘Carbon Capture Storage’ factsheet for more information). In particular, CCS has been cited by tar sands companies as a means of avoiding criticism over GHG emissions. For example, Shell’s Quest project in Alberta, Canada aims to do precisely this. The CCS project at Shell’s Scotford Upgrader is used to boast about the company’s commitment to the environment yet the company nevertheless exploits the Albertan tar sands, perhaps the most environmentally destructive extractive project on the planet. Despite supposed industry enthusiasm for the technology, research shows there are fundamental limits on the GHG emissions reductions that can be offered by using CCS in tar sands production. This is partly because most of the emissions

from tar sands, such as from trucks used in mining, or waste gas from burning natural gas, are not well suited to CCS.16 Even the most optimistic industry estimates have suggested that overall reductions from upstream operations could be in the 10 – 30% range at only the best locations by 2020, and 30 – 50% by 2050, whereas reductions of around 85% would be required to make tar sands emissions comparable with the average for conventional oil production.17 Considering there are 264 Gt of carbon locked up in tar sands, even with the most optimistic reductions from CCS there would still be more than enough carbon released to easily blow the 130 Gt remaining budget (see climate section above). On top of this CCS would not be ready to be fully implemented for decades to come, far too late to effectively reduce emissions. With or without CCS, tar sands development is disastrous for the global climate.

Other social and environmental issues Water Tar sands extraction is extremely water intensive, requiring about three barrels of water to produce a barrel of tar sands using surface mining techniques18 and more than a barrel for in-situ techniques.19 Canadian tar sands production in 2011 used around 170 million cubic metres, 20 almost none of which can be returned to the water cycle.21 Production of the Athabascan Tar Sands in Canada also draws large volumes of water from the Athabasca river basin and there are concerns that this may already be over taxing the river system and that there will not be sufficient water to support future expansion.22 23 Contaminated water from tar sands production is either pumped back underground, or stored in enormous tailings lakes (‘tailings’ refers to waste material suspended in water). These lakes now cover an area of 176km², with an estimated 11,000 cubic metres of contaminated water seeping from tailings lakes into adjacent surface and groundwater each day. Liquid tailings are expanding at a rate of 200 million litres every day.24 The tar sands industry currently has no plans for how to deal with liquid tailings. Waste from tar sands production contains a number of toxic and carcinogenic substances including naphthenic acids, polycyclic aromatic hydrocarbons (PAHs), phenolic compounds, ammonia and mercury.25 There is strong evidence demonstrating how these substances are entering the environment. Independent research has found that levels of PAHs have dramatically increased in lake sediments since the production of tar sands began,26 and that PAHs and heavy metals such as mercury, arsenic and lead from tar sands production have been polluting rivers.27 Federal research has confirmed that toxic chemicals in water from tailings lakes are leaching into groundwater and seeping into the Athabasca River.28

Air pollution As well as GHG emissions, tar sands operations produce large volumes of air pollutants. These include nitrogen oxides and sulphur dioxide, which cause acid rain, volatile organic compounds (VOCs) and particulate matter which are known to affect human health.29 30 In 2014 a study published in the Proceedings of the

Julia Kilpatrick, the Pembina Institute

Athabasca region Healing Walk

National Academy of Sciences showed that production in the Athabasca oil sands region is leading to the airborne emissions of levels of polycyclic aromatic hydrocarbons (PAHs) one hundred to one thousand times greater than previously thought.31 Most air pollution from tar sands production comes from refineries used to upgrade bitumen, but other sources, such as emissions from vehicles, also cause significant pollution. The vast tailing lakes, where liquid waste from operations is stored, also pollute the air, as volatile organic compounds evaporate from the surface.

Natural gas use Tar sands production requires a huge amount of energy, most of which is currently provided by natural gas. In particular producing steam for in-situ techniques such as SAGD requires a lot of gas. According to the National Energy Board (NEB), it takes about 34 cubic metres (1200 cubic feet) of natural gas, enough to heat the average Canadian home for over 4 days, to produce one barrel of bitumen from in-situ projects.32 Natural gas consumption from tar sands production in Canada is estimated to increase to 45 million cubic metres per day in 2015 (1.6 billion cubic feet),33 enough to heat over 6 million Canadian homes.34 This is taking up a significant proportion of Canada’s natural gas supplies, and if projected increases in tar sands production take place, nuclear power or unconventional gas may be needed, further increasing the environmental impact of tar sands extraction.

Pipelines

The Albertan tar sands have already resulted in huge pipelines networks being built across Canada, with other major pipelines such as the Keystone XL and Energy East pipelines planned. Pipeline construction on such a scale has a significant direct impact on the local communities and environment, but there is also the risk of leakages and oil spills. In Alberta, the oil and gas industry averaged 762 pipeline failures per year between 1990 and 2005, for a total of 12,191 failures.35

Oil spills

Oil spills occur both at the sites of tar sands extraction, such as the spills at Cold Lake, Alta36 and along the routes of pipelines, with devastating effects on the local environment. The Kalamazoo tar sands disaster in 2010, where an Enbridge pipeline carrying diluted bitumen from the Canadian tar sands burst, was one of the largest and costliest onshore spills in US history. It resulted in well over a million US gallons (4.5 million litres) of oil flowing into Talmadge Creek,37 a tributary of the Kalamazoo River in Michigan, and cost over a billion dollars to clean up.38

Destruction of habitats and landscape

The areas of Canada where tar sands are found are covered in primary boreal forest and wetlands, home to sensitive ecosystems and a wide variety of wildlife. The Canadian boreal forests represent huge globally significant stores of carbon, and the greenhouse gasses released through deforestation and destruction of peatlands for tar sands production are unlikely to ever be recovered.39

Impact on Indigenous (First Nations) populations

Almost all the land on which tar sands extraction is occurring in Canada is on or near indigenous territories. This, along with associated projects such as the Northern Gateway pipeline and Keystone XL pipelines which also threaten indigenous lands, has seriously threatened the cultural heritage, land, ecosystems and health of Canadian First Nations peoples. Despite signing up to the UN Declaration of Rights of Indigenous People’s (UNDRIP), the Canadian government routinely ignores the right of ‘Free, Prior and Informed Consent’ (FPIC) of Indigenous People enshrined in the declaration. Many First Nation communities have responded with legal action and widespread protest and resistance (see ‘Resistance’ section below).

Impact on public health

The tar sands developments in Canada have raised various public health concerns related to water and air pollution (see ‘Water’ and ‘Air pollution’ sections) and worries over higher rates of rare cancers in areas polluted by tar sands production. In 2006, unexpectedly high rate of rare cancers were reported in the community of Fort Chipewyan. In 2009, an investigation by the Alberta Cancer Board found higher than expected rates of biliary cancers, but said that it was not enough to be a cause for concern and called for further monitoring.45 However, the report did not investigate any possible relationship with environmental exposures related to tar sands production.46 Serious concerns remain around the impact of tar sands operations on local public health.47

False industry promises

Tar sands extraction in Canada is leaving a toxic legacy of vast tracts of devastated habitats and huge toxic tailings lakes that will last long after the companies have left. Only a tiny percentage (0.15%)40 of the land affected by tar sands production has been certified as reclaimed41 and the certification of ‘reclaimed’ land itself has come under strong criticism.42 Many areas, such as boreal forests, will never recover to their previous state.43 In addition, the reclamation of peatlands (fens or bogs) in the Athabasca Boreal region has never been demonstrated to be possible44 and according to the Pembina Institute there is no demonstrated long term way to deal with liquid tailings.

Tar Sands Blockade

Syncrude oilsands facility

Where and how Much? Global oil in place: 2,511 billion barrels, natural bitumen reserves estimated at 250 billion barrels. 48 About 70% of the world’s tar sands reserves are in Canada (169 billion barrels), 49 most of which can be found in three major deposits in Northern Alberta: the Athabasca-Wabiskaw oil sands, the Cold Lake deposits, and the Peace River deposits. Together these cover more than 140,000 km², an area larger than England. Tar sands extraction in Canada is now a major industry, producing 1.7 million barrels of bitumen per day in 2011.50 However, while there are huge remaining resources, future production is currently limited by the country’s ability to export tar sands in crude form. Various pipelines aimed at increasing export capacity

Julia Kilpatrick, the Pembina Institute

are in construction or planned, such as the Keystone XL pipeline which would link the tar sands to the refineries in the Gulf Coast of the US, and there are plans to increase tanker exports to Asian markets by expanding ports. Tar sands also occur in other parts of the world, with the next largest deposits in Kazakhstan (42 billion barrels of bitumen reserves), and Russia (28 billion barrels).51 Exploration and test projects have been carried out in Russia, Madagascar, Congo (Brazzaville), Utah in USA, and Trinidad and Tobago.

companies involved A wide variety of companies are involved in tar sands projects, from small local producers, to multinational ‘supermajors’ such as Shell and BP. Notable tar sands companies include: Suncor Energy, Syncrude Canada, Canadian Oil Sands Limited, Canadian Natural Resources, Shell, BP, Exxon Mobil, Connoco Philips and Total.

Resistance Albertan tar sands

First Nations Canadians have been leading the resistance to tar sands operations in Alberta. Canada has treaty agreements that protect the First Nations people’s rights to use the land for traditional practices such as hunting and fishing in perpetuity. Many indigenous communities have attempted to use the courts to uphold their treaty rights and prevent tar sands extraction. However, bills introduced by the Canadian government, primarily aimed at expanding tar sands developments, ignored the treaties and have prompted a huge protest movement against them. The Idle No More movement aims for environmental protection and indigenous sovereignty and has resulted in a wave of direct action and solidarity protests around the world. The Keystone XL pipeline has become a major focus of protests in Canada and the US, with widespread civil disobedience and direct action targeting the project. Campaigners have identified it as a key strategic point of resistance, in an attempt to limit export capacity, and therefore further expansion of tar sands in Canada. Attempts to develop tar sands deposits in Utah, US have also been met with strong local opposition.

For more information on resistance see the Corporate Watch website (corporatewatch.org/uff/resistance)

Royal Dutch Shell, 2009

Endnotes 1 ‘Alberta Energy: Facts and Statistics’. Accessed 25 February 2014. <http://www.energy.alberta.ca/ OilSands/791.asp> 2 ‘Petroleum Coke: The Coal Hiding in the Tar Sands’. Oil Change International (Jan 2013). <http:// priceofoil.org/2013/01/17/petroleum-coke-thecoal-hiding-in-the-tar-sands/> 3 ‘ST39: Alberta Mineable Oil Sands Plant Statistics -2011’. Alberta Energy Regulator (2011). <http://www.aer.ca/data-and-publications/ statistical-reports/st39> 4 Op.Cit (Oil Change International, Jan 2013) 5 Pavone A, ‘Converting Petroleum Coke to Electricity. 14th National Industrial Energy Technology Conference, Houston, TX (April 22-23, 1992). <http://repository.tamu.edu/bitstream/

handle/1969.1/92212/ESL-IE-92-04-47.pdf> 6 ‘US Exports to China Increasing Barrels of Petcoke, a Fuel Dirtier Than Coal - Businessweek’. Accessed 25 February 2014. <http://www.businessweek. com/articles/2013-12-05/us-exports-to-chinaincreasing-barrels-of-petcoke-a-fuel-dirtierthan-coal> 7 ‘Development of Baseline Data and Analysis of Life Cycle Greenhouse Gas Emissions of PetroleumBased Fuels’. DOE/NETL-2009/1346 (2008), 13, table 2-4. <http://www.netl.doe.gov/energyanalyses/pubs/NETL%20LCA%20PetroleumBased%20Fuels%20Nov%202008.pdf> 8 ‘Setting the Record Straight: Lifecycle Emissions of Tar Sands’. Natural Resources Defense Council (2010). <http://docs.nrdc.org/energy/files/

ene_10110501a.pdf> 9 Marc Huot, Danielle Droitsch and P.J.Partington. ‘Canadian Oilsands and Greenhouse Gas Emissions: The Facts in Perspective’. The Pembina Institute (2010) 7. <http://www.pembina.org/pub/2057> 10 ‘Beneath the Surface’. The Pembina Institute (Jan 2013). <http://www.pembina.org/pub/2404> 11 ‘Canada’s Emission Trends (2012), 24 (table 5)’. Environment Canada. <http://www.ec.gc.ca/ Publications/253AE6E6-5E73-4AFC-81B79CF440D5D2C5/793-Canada%27s-EmissionsTrends-2012_e_01.pdf> 12 Hansen, James, Pushker Kharecha, Makiko Sato, Valerie Masson-Delmotte, Frank Ackerman, David J. Beerling, Paul J. Hearty, et al. ‘Assessing “Dangerous Climate Change”:

Required Reduction of Carbon Emissions to Protect Young People, Future Generations and Nature’. Edited by Juan A. Añel. PLoS ONE 8, no. 12 (3 December 2013): e81648. doi:10.1371/ journal.pone.0081648. <http://www.plosone. org/article/info%3Adoi%2F10.1371%2Fjournal. pone.0081648> 13 Ibid 14 Ibid 15 See <www.corporatewatch.org/uff/carbonbudget> 16 Standing Committee on the Environment and Sustainable Development, House of Commons, Canada, Evidence from Graham Thomson, March 30, 2010, Extracted from 40th Parliament, 3rd Session. <http://www2.parl.gc.ca/HousePublications/ Publication.aspxDocId=4402785&Language= E&Mode=1&Parl=40&Ses=3#Int-3071313 > 17 ‘Carbon capture and storage in the Alberta oil sands – a dangerous myth’. Cooperative Financial Services and WWF-UK (Oct 2009). <http://www. co-operative.coop/Corporate/PDFs/Tar%20 Sands%20CCS.pdf > 18 ‘Water use in Canada’s oil sands’. Canadian Association of Petroleum Producers (June 2012). <http://www.capp.ca/getdoc. aspx?DocId=193756> 19 J Kidd. ‘Running out of steam - A Workshop on Oil Sands Development and Water Use in the Athabasca River Watershed: Science and Market-Based Solutions’ Kidd Consulting (May 2007). <http://powi. ca/wp-content/uploads/2007/05/Final-Runningout-of-Steam-Meeting-Notes.pdf> 20 ‘Oil Sands Water Use’ Alberta Environment & Sustainable Resource Development, Oil Sands Information Portal (accessed January 18, 2013). <http://environment.alberta.ca/apps/osip/> 21 Mary Griffiths, Amy Taylor and Dan Woynillowicz. ‘Troubled Waters, Troubling Trends: Technology and Policy Options to Reduce Water Use in Oil and Oilsands Development in Alberta’. The Pembina Institute (2006). <http://www.pembina.org/ pub/612> 22 Mario LÓpez Alcalá, Doug Cogan, Dinah Koehler, Yulia Reuter, Dana Sasarean. ‘Canada’s Oil Sands: Shrinking Window of Opportunity’. RiskMetrics Group, Ceres, (May 2010). <http://www.ceres.org/ resources/reports/oil-sands-2010> 23 ‘Canada’s Oil Sands - Opportunities and Challenges to 2015: An Update - Questions and Answers’. National Energy Board (last modified July 2010). <http://www.neb.gc.ca/clf-nsi/rnrgynfmtn/ nrgyrprt/lsnd/pprtntsndchllngs20152004/ qapprtntsndchllngs20152004-eng.html> 24 ‘Losing Ground -Why the problem of oilsands tailings waste keeps growing’. Pembina Institute (Aug 2013). <http://www.pembina.org/pub/2470> 25 P. G. Nix and R. W. Martin. “Detoxification and Reclamation of Suncor’s Oil Sand Tailings Ponds”. Environmental Toxicology and Water Quality 7, no. 2 (1992) 26 Joshua Kurek, Jane L. Kirk, Derek C. G. Muir, Xiaowa Wang, Marlene S. Evans, and John P. Smol. ‘Legacy

of a half century of Athabasca oil sands development recorded by lake ecosystems’. Proceedings of the National Academy of Sciences of the United States of America, published online before print on January 7, 2013 (201217675). <http://www.pnas.org/content/ early/2013/01/02/1217675110.full.pdf+html> 27 Erin N. Kelly, Jeffrey W. Short, David W. Schindler, Peter V. Hodson, Mingsheng Ma, Alvin K. Kwan and Barbra L. Fortin. ‘Oil sands development contributes polycyclic aromatic compounds to the Athabasca River and its tributaries’. Proceedings of the National Academy of Sciences of the United States of America 107 (2009). <http://www.pnas.org/content/ early/2013/01/02/1217675110.full.pdf+html> 28 ‘River Metals Linked to Tar Sand Extraction’ . Nature News (Accessed 25 February 2014). <http:// www.nature.com/news/2010/100831/full/ news.2010.439.html> 29 ‘Environmental and Health Impacts of Canada’s Oil Sands Industry’. Royal Society of Canada (2009). <http://www.ianas.org/books/Environmental_ and_health_impacts_of_canadas_oil_sands%20 Industry.pdf> 30 ‘National Pollutant Release Inventory, 2007 Summary’ Environment Canada, section 3.1.1.1 “Criteria Air Contaminants” (accessed January 29, 2013) .<http://www.ec.gc.ca/inrp-npri/default. asp?lang=En&n=0D743E97-1> 31 Parajulee, A., and F. Wania. ‘Evaluating Officially Reported Polycyclic Aromatic Hydrocarbon Emissions in the Athabasca Oil Sands Region with a Multimedia Fate Model’. Proceedings of the National Academy of Sciences (3 February 2014). doi:10.1073/ pnas.1319780111. <http://www.pnas.org/content/ early/2014/01/29/1319780111> 32 ‘NEB - Energy Reports - Canada’s Oil Sands: Opportunities and Challenges to 2015 - Questions and Answers’ (Accessed 25 February 2014). <http://www.neb.gc.ca/clf-nsi/rnrgynfmtn/ nrgyrprt/lsnd/pprtntsndchllngs20152004/ qapprtntsndchllngs20152004-eng.html> 33 ibid 34 A rough approximation is that 100 GJs of energy – or 2,700 cubic metres or 94,800 cubic feet of natural gas – is required to heat a newly built average-sized single detached home in Canada for one year (from here: http://www.nrcan.gc.ca/energy/sources/ natural-gas/1233). 2700/365 = 7.4 cubic metres per day. 34 per barrel / 7.4 = 4.6 days. 45 million cubic metres per day / 7.4 cubic metres per home = 6 millions homes 35 Van Hinte, Tim, Thomas I. Gunton, and J. C. Day. ‘Evaluation of the Assessment Process for Major Projects: A Case Study of Oil and Gas Pipelines in Canada’. Impact Assessment and Project Appraisal 25, no. 2 (June 2007): 123–137. doi:10.3152/146155107X204491. <http://commdev. org/files/1710_file_s5.pdfIII.pdf> 36 ‘Leak at Oil Sands Project in Alberta Heightens Conservationists’ Concerns’. NYTimes.com. Accessed 25 February 2014. <http://www. nytimes.com/2013/08/09/business/global/ leak-at-oil-sands-project-in-albertaheightens-conservationists-concerns.

html?_r=0&adxnnl=1&adxnnlx=1393357691QGkbMuiFkuI+tJEnqTQlpQ> 37 ‘EPA Response to Enbridge Spill in Michigan’. US EPA. Accessed 25 February 2014. <http://www.epa. gov/enbridgespill/> 38 ‘Application for a Certificate of Need for a Crude Oil Pipeline’. Enbridge Energy (Before the Minnesota Public Utilities Commission). Revised 16 Aug 2013. <https://www.edockets.state.mn.us/ EFiling/edockets/searchDocuments.do?meth od=showPoup&documentId={F1B13575-3D714CAA-A86A-05CE1EBBCA38}&documentTit le=20138-90363-03> 39 Lee P and R Cheng. ‘Bitumen and Biocarbon: Land use changes and loss of biological carbon due to bitumen operations in the boreal forests of Alberta, Canada’. Global Forest Watch Canada (2009), p.30 40 ‘Oilsands 101: Reclamation’. Pembina Institute. Accessed 25 February 2014. <http:// www.pembina.org/oil-sands/os101/ reclamation#footnote1_x43kjjk> 41 ‘Reclamation Illusions in Oil Sands Country’. Parkland Post. Accessed 25 February 2014. <http://parklandinstitute.ca/post/story/ reclamation_illusions_in_oil_sands_country/> 42 Jennifer Grant, Simon Dyer, Dan Woynillowicz. ‘Oil Sands Myths: Clearing the Air’. Pembina Institute, June 2009, p.23. <http://www.pembina.org/ pub/1839> 43 Op. Cit. ‘Oilsands 101: Reclamation’. Pembina Institute 44 Op. Cit. ‘Oil Sands Myths: Clearing the Air’. Pembina Institute, June 2009 45 ‘Fort Chipewyan Cancer Study Findings Released’. Alberta Health Services. Accessed 25 February 2014. <http://www.albertahealthservices.ca/500.asp> 46 Ian Urquhart. ‘Between the Sands and a Hard Place?: Aboriginal Peoples and the Oil Sands’. Buffett Center for International and Comparative Studies Working Paper No. 10-005: Energy Series, Department of Political Science, University of Alberta, November 2010, pp.9,12,13 47 ‘Alberta MD: Canada “Lying” About Tar Sands Health Impacts’. Environment News Service. Accessed 7 March 2014. <http://ens-newswire. com/2014/02/27/alberta-md-canada-lyingabout-tar-sands-health-impacts/> 48 ‘Survey of Energy Resources 2010’. World Energy Council. <http://www.worldenergy.org/ publications/3040.asp> 49 Ibid 50 ‘Alberta Energy: Facts and Statistics’. Accessed 25 February 2014. <http://www.energy.alberta.ca/ OilSands/791.asp> 51 Op. Cit. (WEC 2010)

endsOFtheearth

the

a guide To unconventional fossil fuels 34

Corporate Watch

endsOFtheearth

the

what is it?

Coalbed methane (CBM), also known as coal-seam gas (CSG) in Australia, refers to methane found in coal seams (underground layers of coal, also called ‘coal beds’). It occurs when methane is absorbed into coal and is trapped there by the pressure from the weight of the rocks that overlie the coal-seams. CBM is formed and trapped during the geological process that forms coal (coalification). It is commonly found during conventional coal mining where it presents a serious hazard (see ‘Coal Mine Methane’ below). As well as methane, CBM is typically made up of a few percent carbon dioxide (CO2), carbon monoxide (CO) and nitrogen (N2) and traces of other hydrocarbons such as propane, butane and ethane.

Coalbed

Methane

EXTRACTING METHANE FROM COAL SEAMS BY DRILLING LARGE NUMBERS OF WELLS. USUALLY INVOLVES PUMPING OUT VERY LARGE VOLUMES OF GROUNDWATER TO GET THE GAS TO FLOW AND OFTEN INVOLVES HYDRAULIC FRACTURING (FRACKING). POSES A SERIOUS RISK OF GROUNDWATER POLLUTION, AND CAUSES SIGNIFICANT GREENHOUSE GAS EMISSIONS, PRIMARILY THROUGH METHANE LEAKAGE.

The amount of methane in a coal seam varies according to the geological conditions, particularly the type of coal and depth of the seam, with higher quality and deeper coal containing more methane.1 CBM is usually found at depths of 300-2000 metres below ground.2 At shallower depths (less than about 300 metres) the CBM concentration tends to be very low as the pressure is not high enough to hold the gas in place. At greater depths, while the gas concentrations are generally higher, the high pressures and the lower permeability of higher quality coals (e.g. bituminous coals and anthracite) make extraction less efficient. Studies of the major coal-bearing basins of the world suggest that more than 50% of the estimated CBM is found in coals at depths below 1500 metres.3 Methane has been removed from coal mines for a long time, but it was not until the 1980s following a tax break in the US, that commercial production of CBM began.4 The industry continued to expand almost exclusively in the US and by 2000 Australia was the only other country to have commercial production, although on a very small scale. There is now widespread CBM extraction, both from coal mines (see Coal Mine Methane below) and from ‘stand-alone’ CBM operations, in the US, Canada, Australia and China, and a handful of production wells in the UK.

Coal Mine Methane

CBM often accumulates in the working areas of underground coal mines. In this context, CBM is commonly referred to as coal-mine methane (CMM) and presents a serious explosive and suffocation hazard. Miners used canaries (and later Davy’s lamps) to warn them of the presence of methane and other dangerous gases. CMM is commonly vented into the atmosphere or flared (controlled combustion) and both of these processes release significant amounts of greenhouse gasses (GHGs) into the atmosphere. Increasingly CMM is being used as an energy source and is extracted in manner very similar to CBM (see below). While the CBM industry is keen to promote this as a way of reducing GHG emissions from venting or flaring, exploiting CMM results in the same environmental problems associated with CBM.

"countries that have carried out CBM activities have experienced numerous

blow-outs, spillages and other accidents"

how is it extracted? To extract CBM, wells are drilled into the coal seam and groundwater is pumped out (known as de-watering). This reduces the water pressure within the bed, releasing the methane trapped in the coal. The gas then migrates along fractures in the coal and is pumped out of the well. The process involves removing large amounts of groundwater from the coal bed, especially in the initial phases where mainly water is produced and only small amounts of gas. About 7,200 to 28,800 gallons (27,255 to 109,020 litres) per day are initially pumped from a coal bed methane well to release the Coal bed methane equipment

methane.5 As production continues, the amount of water extracted reduces, and the amount of gas extracted increases until it peaks and declines. Typically a well peaks in production after one or two years. In order to maintain production rates from a seam more and more wells are needed to keep the gas flowing. There are a variety of methods used to extract the methane, depending on the characteristics of the coal seam being exploited. In the most permeable seams, found at shallower depths, water is pumped out and the gas simply flows after it. Most seams are less permeable, and fracking or cavitation is sometimes used to break up the coal and allow the gas to flow more readily (see ‘Fracking’ and ‘Cavitation’ sections below). Other technologies such as multilateral wells (where one well exploits a number of seams) and horizontal drilling are also utilised. Occasionally de-watering is not required and wells produce gas immediately. This can be as a result of previous production or for wells completed in coal seams where water has been removed during mining operations. Although producing Coal Mine Methane (CMM) can involve simply extracting the gas that has accumulated in old coal mines (in which case a CBM-air mixture is recovered, from which the methane can be separated), in practice, many of the same drilling extraction techniques used in CBM extraction, such as fracking, are also used.

Climate change It is sometimes argued that since burning natural gas produces less greenhouse gas (GHG) emissions than coal it can be used as a ‘bridging’ or ‘transition’ fuel, replacing coal while renewable energy technologies are developed and implemented. This argument is used by governments and industry to promote gas as a low carbon energy option. However, natural gas, whether it comes from shale or conventional sources, is a fossil fuel and when it is burned it releases significant GHG emissions. Further, as long as energy demand increases additional sources of fossil fuels such as coal bed methane are likely to supplement rather than replace existing ones such as coal. When comparing fuel types it is important to use lifecycle GHG emissions, the total GHG emissions generated by developing and using the fuel. In the case of CBM these include direct CO2 emissions from end-use consumption (e.g. from burning gas in power plants), indirect CO2 emissions from fossil fuel derived energy used to extract, refine and transport the gas, and methane from ‘fugitive’ emissions (leaks) and venting during well development and production. The gas industry is particularly reluctant to investigate how much gas escapes as fugitive methane emissions in the process of extracting and transporting natural gas. However various studies have found significant leakage, and as methane is such a powerful GHG, even a small percentage of the gas extracted escaping to the atmosphere can have a serious impact on the climate. Lifecycle emissions from CBM are similar to those of shale gas, but there are a number of factors that could mean either slightly greater or lower emissions. For example CBM requires lots of wells to be drilled into the seam to keep the gas flowing, all of which need to be connected to a central processor. This means additional sources of fugitive emissions from the wells and connecting pipes. During the initial phases when water is pumped from the coal seam, any gas that comes out with it is either flared (where gas is burned off) or vented directly to the atmosphere, but there is generally less gas flared or vented during these initial phases than with shale gas. Fracking is

also normally used less with CBM than shale gas, which could mean lower fugitive emissions. An investigation by Southern Cross University into atmospheric methane at a CBM field in Australia, found methane levels to reach 6.9 parts per million (ppm), compared to background levels of lower than 2 ppm outside the gas fields, suggesting significant leakage.6 It has been estimated that leakage rates may be as high as 4.4%.7 Methane is a powerful greenhouse gas, particularly its short term influence on the atmosphere. This means that if more than 3.2% of extracted methane is lost to the atmosphere then switching from coal to gas will result in no immediate benefits in terms of contribution to climate change. 8

CONVENTIONAL OIL ‘SAFE’ EMISSIONS LIMIT 130 GtC

325 GtC COAL BED METHANE

130 GtC

CONVENTIONAL GAS

277 GtC

If we are to reduce carbon emissions to anything like the levels required to maintain a reasonably habitable planet we must move away from all forms of fossil fuel as fast as possible. Measuring from the start of the industrial revolution (around 1750), a maximum of 500 Gigatonnes of carbon (GtC) can be emitted to the atmosphere while still avoiding most serious impacts and the risk of irreversible and uncontrollable changes to the climate.9 Between 1750 and now (2014), we have already emitted about 370 Gt leaving a limit of 130Gt that could be further added.10 In order to stay within this limit we have to leave the vast majority of the remaining conventional oil, coal and gas in the ground. Estimates vary significantly, but remaining conventional coal reserves alone are well over 500GtC.11

Exploiting the world’s CBM would add around 130 GtC to the atmosphere.12 This is a huge amount and is clearly incompatible with staying within the limit outlined above. This means that rather than being part of the solution, the development of CBM is dramatically worsening the problem of climate change.

CBM and Carbon Capture and Storage (CCS)

Those involved in the CBM industry say it is ideally suited for CCS, as the coal seams that hold the methane will also readily take up CO2. However in practice technical and economic problems have prevented the use of CCS at CBM sites. Only certain highly permeable coal seams would be appropriate for injecting CO2, and not all CBM sites fit this criterion. Another problem with CCS in coal seams is the fact that the coal expands and reduces in permeability as it absorbs CO2, meaning that injection becomes more and more difficult. CBM is also trapped in the coal and held in place by water pressure rather than by a layer of impermeable ‘cap rock’ above the seam (as is the case with conventional gas). As CO2 dissolves in water much more readily than methane it is less likely to be held in place by water pressure. Injecting CO2 into the coal seam is also used as a way to eke-out the remaining gas (see ECBM below). Proponents of unconventional fossil fuels often argue that with CCS technologies, these new energy sources could be exploited at the same time as reducing GHG emissions. However, even if the huge problems with CCS technology are overcome (and this currently looking

extremely unlikely), it would not change the fact that we need to move away from all forms of fossil fuel, conventional and unconventional, as soon as possible. In the most optimistic (and highly implausible) scenario, CCS could be used to reduce a small proportion of emissions from fossil fuels. In reality, the promise of CCS being implemented in the future is being used to allow the continued expansion of fossil fuel production, to prevent alternatives from being developed, and to deflect attention away from approaches which tackle the underlying systemic causes of climate change and other ecological crises. Ultimately CCS is a smokescreen, allowing the fossil fuel industry to continue profiting from the destruction of the environment. (see ‘Carbon Capture Storage’ factsheet for more information).

Enhanced Coal Bed Methane (ECBM)

ECBM is the process of injecting CO2 into a coal seam containing CBM in order to extract more gas. The CO2 pushes out the remaining methane, and is intended to stay trapped in the coal. While the industry argues that this is a way of making CCS economical, in reality it is just a way to extract more methane [See enhanced recovery section Other Unconventional Fossil Fuels factsheet].

Other social and environmental issues Fracking

Fracking, or hydraulic fracturing, is used to free gas trapped in rock by drilling into it and injecting pressurised fluid, creating cracks and releasing the gas. The fracking fluid consists of water, sand and a variety of chemicals which are added to aid the extraction process e.g. by dissolving minerals, killing bacteria that might plug up the well, or reducing friction. Fracking is sometimes used in CBM extraction and often takes place before water is pumped out from the coal bed. This means that most of the fracking fluid will be extracted along with the groundwater, adding further contaminants to the waste water. In Australia about a tenth of CBM sites have been hydraulically fractured to date, but this expected to grow to 40% or more, since there is a tendency to target the seams that are easiest to exploit first. A much higher proportion of CBM wells in the US are fracked.

As the coal seams are generally shallower and closer to aquifers CBM fracking poses a greater risk of contamination than when it is used to extract shale or tight gas and oil. Fracking can both create connections to aquifers and lead to cross-contamination between aquifers. There has been a great deal of controversy over the chemicals contained in fracking fluids. In the US many companies have resisted revealing the recipes for their fracking mixes, claiming commercial confidentiality, or have adopted voluntary reporting measures in order to avoid stricter mandatory reporting requirements. Although the specific mix of chemicals used varies significantly, a US House of Representatives Committee on Energy and Commerce report found 750 different chemicals had been used in fracking fluids, including many known human carcinogens and other toxic compounds such as benzene and lead.13 Chemicals found to

be most commonly used in fracking fluids such as methanol and isopropyl alcohol are also known air pollutants. A variety of chemicals are also added to the ‘muds’ used to drill well boreholes in order to reduce friction and increase the density of the fluid. Analysis of drilling mud has also found that they contain a number of toxic chemicals.14 15

Water use and waste water

Aside from climate change, the main environmental issues with CBM concern its impact on water resources. Extracting CBM involves removing large volumes of groundwater, and also results in large volumes of contaminated waste water. The contaminants in the waste water arise both from fracking chemicals, if they have been used, and from higher concentrations of harmful substances naturally present in coal-seams and coalseam waters. Waste water from CBM varies greatly depending on the geology of the coal seam, with deeper seams usually containing saltier water. It can be saline (with high concentrations of dissolved salt), or sodic (with high concentrations of sodium) or both. Highly saline or sodic waters damage soils and affect plant growth.16 As the water is pumped out it brings along the naturally occuring contaminants stored in the coal seam. These can typically include heavy metals,17 radioactive material,18 and hydrocarbons,19 including carcinogenic organic compounds. Waste water is dealt with in a variety of ways, either directly disposing of it into streams and rivers, discharging onto land or roads, storing in surface ‘impoundments’ and sending it to be processed, or re-injecting it into the coal seam or the rock below. All of these disposal methods have associated problems. Surface impoundments are often unlined, meaning that subsurface water can be contaminated and accidents can lead to surface water contamination. Evaporation from impoundments can also further concentrate pollutants in CBM waste water.20 Disposal on land or into streams and rivers pollutes the local environment,21 and re-injection can lead to pollution of aquifers. Re-injection is also only possible in certain high-porosity formations located below saline aquifers, and risks contaminating ground water. Treatment of the contaminated water is extremely difficult due to the volumes involved, the salinity of the water, and the variety of containments present, particularly radioactive material.22

Effects on groundwater and aquifers

In some places coal seams are adjacent to or are themselves important aquifers, and both pumping out water for CBM extraction and re-injecting waste water can seriously affect local drinking water sources. Extracting water for CBM production also affects pressures and flows of surrounding groundwater and can result in lowered water levels in aquifers, making water more difficult or impossible to access from wells and springs.23 Water levels several miles away from the CBM site can be reduced by tens of feet and levels can take years or even decades to recover.24 The changes in water pressure can also mobilise naturally occurring pollutants, and enable any remaining fracking fluids to flow in to surrounding groundwater. Methane released in the process can also contaminate groundwater. Research on the health impacts on those living near CBM sites is now starting to emerge.25 26

Well failure and methane leakage

Methane can naturally leak from coal seams into surrounding aquifers. However, de-watering the coal seam for CBM extraction releases the methane and significantly increases the risk of seepage to aquifers, water wells and surface soil.27 Methane pollutes drinking water and if it reaches soil it displaces oxygen, killing vegetation. Failure of CBM well casings also increases the risk of leakage and contamination. Despite industry claims that leakage of methane and fracking chemicals is due to bad well design, research has shown that some leakage is inevitable and that fracking only exacerbates the problem.28 Wells routinely lose their structural integrity and leak methane and other contaminants outside their casings and into the atmosphere and water wells. Even research by oil services company Schlumberger suggests half of conventional gas wells will be leaking within 15 years.29 Failure rates for some CBM wells could be even higher due to fracking activities. Well failure is a problem as it contributes to both groundwater pollution and greenhouse gas emissions (see climate change section for more on methane leakage rates).

Cavitation

Cavitation or Open-Hole Cavity Completion involves injecting a very high pressure foamy mixture of air and water into the coal seam, then suddenly releasing the pressure, causing an explosive release of coal, water and rock from the well, a bit like shaking up a bottle of fizzy drink and taking the lid off. The violent process of liquid, foam and fragments of rock flowing out the well, sometimes know as ‘surging’ can last up to fifteen minutes and is extremely noisy. The cavitation process is repeated dozens of times over about a two week period,30 expanding the diametre of the initial bore hole. It also connects the natural fractures in the coal, creating channels for gas to flow. Gas produced by the process is vented or flared off, creating huge flames. Cavitation also produces significant quantities of coal and other solid waste which is burned or stored on-site. Caviataion is used as an alternative to fracking to increase permeability of coal seams, but is very unclear how frequently it is used, in what situations and how its use is evolving with time.

Industrialisation of countryside

In order to be economically viable CBM requires an ever expanding networking of wells, pipelines, compressor stations and roads to be built, leading to widespread industrialisation of the countryside. Equipment also needs to be monitored in future, meaning that the impact will last long after the wells have stopped producing gas. The various stages of CBM extraction also generate significant noise, through heavy traffic, drilling, gas compressors and other industrial equipment, flaring and explosions. CBM operations have a very high density of wells (boreholes), typically varying between 1 to 3 wells per square kilometre.31

Underground fire risk

The process of removing water from the coal-seams during CBM extraction from old or operating mines increases the risk of underground fires, as oxygen from shafts and tunnels can replace the water and come into contact with the coal, resulting in spontaneous coal combustion. The lowering of the water table can also increase the fire risk to nearby seams. Underground coal fires pose a serious risk of groundwater contamination and are also a source of significant CO2 emissions.

Kate Ausburn 2012

Air pollution As well as GHG emissions, CBM extraction produces various sources of local air pollution, including increased vehicle traffic, venting and flaring, and pollutants from compressor stations. Air pollutants from CBM operations are likely to be similar to those of shale gas extraction including BTEX (benzene, toluene, ethylene and xylene), NOx (mono oxides of nitrogen), VOCs (volatile organic compounds), methane, ethane, sulphur dioxide, ozone and particulate matter.32

Subsidence

Removing large volumes of groundwater, particularly from shallow aquifers, can result in significant subsidence at the surface. This can damage infrastructure and put ground and surface water resources at risk. Depending on the site, removing water for CBM extraction can cause subsidence.33 Many CBM sites are in former coalfield areas, where de-watering will have significant impacts on surface stability; reactivating old subsidence f  aults, as well as creating new ones. Subsidence also increases the risk of fugitive emissions, creating new pathways for gasses to escape to the atmosphere.

Accidents

Despite industry claims of it being a safe, controlled process, countries that have carried out CBM activities have experienced numerous blow-outs, spillages and other accidents.34 35These have resulted in serious ground and surface water contamination.

Where and how Much?

Coal bed methane occurs around the world alongside coal resources, and although it is only currently extracted on a large scale in a few countries, it is being rapidly adopted in other places. Extraction is widespread in the US (over 55,000 wells), Canada (over 17,000 wells), Australia (over 5,000 wells) and China (thousands of wells). India also began commercial production in 2007 and now has hundreds of wells, and

there are a handful of wells in the UK. Around forty other countries are looking into exploiting their CBM resources.36 The global market for coal bed methane was estimated to be 2,932 billion cubic feet (bcf) or 894 billion cubic metres (bcm) in 2010 and is predicted to reach market volumes of 4,074 bcf (1,242 bcm) by 2018.37

1 Canada 17-92 2 Russia 17-80 3 China 30-35 4 Australia 8-14 5 US 4-11 6 Ukraine 2-12 7 India 0.85-4.0 8 Germany 3.0 9 Poland 3.0 10 UK 2.45

In 2006 global reserves were estimated to be 143 trillion cubic metres (or 143,000 billion cubic metres) by the IEA,38 with the following countries have the greatest reserves (in trillions of cubic metres):

companies involved Current major players in the industry include: Australia: QGC (BG Group), Santos, Origin Canada: Apache, Encana, MGV

US: Pioneer, CONSOL, Williams

UK: Dart, IGas (though they are tiny compared to companies in other countries)

Resistance Coal Bed Methane operations have been met with sustained resistance in the US and even more so in Australia, where the Lock the Gate movement has seen land owners, community groups and environmentalists join forces to prevent exploration and production of CBM (known as Coal Seam Gas in Australia). Lock the Gate Alliance 2012

Other companies involved include Arrow Energy, Baker Hughes, Far East Energy Corp, Queensland Gas, Sydney Gas, Sinopec and PetroChina. Many of the well known â&#x20AC;&#x2DC;super majorsâ&#x20AC;&#x2122; such as Royal Dutch Shell, ConocoPhillips, BP and ExxonMobil are also involved in CBM production.

For more information on resistance see the Corporate Watch website (corporatewatch.org/uff/resistance)

Endnotes 1 ‘Coalbed methane development: Boon or bane for Rural Residents’ Factsheet, Western Organization of Resource Councils (WORC) (2003).<http://www.worc. org/pdfs/CBM.pdf> 2 ‘World Energy Resources: 2013 Survey’. World Energy Council (2013). <http://www.worldenergy.org/ publications/2013/world-energy-resources-2013survey > 3 Larry Thomas. ‘Coal Geology’ (West Sussex, England: John Wiley & Sons Ltd.), 2002 4 Rogers, R.E. ‘Coalbed Methane: Principles and Practice’, 345. (Englewood Cliffs, New Jersey: Prentice Hall) 1994 5 ‘Oil and Gas Production Activities’. Accessed 25 February 2014. <http://teeic.anl.gov/er/oilgas/ activities/act/index.cfm> 6 ‘Australian Scientists Find Excess Greenhouse Gas near Fracking’. Los Angeles Times. Accessed 25 February 2014. <http:// articles.latimes.com/2012/nov/17/world/ la-fg-wn-australia-fracking-leakage-20121116> 7 ‘Fugitive Greenhouse Gas Emissions from Coal Seam Gas Production in Australia’. CSIRO (Feb 2013). <http://www.csiro.au/Outcomes/Energy/FugitiveGreenhouse-Gas-Emissions-from-Coal-SeamGas-Production-in-Australia.aspx> 8 Alvarez, R. A., S. W. Pacala, J. J. Winebrake, W. L. Chameides, and S. P. Hamburg. ‘Greater Focus Needed on Methane Leakage from Natural Gas Infrastructure’. Proceedings of the National Academy of Sciences 109, no. 17 (9 April 2012): 6435–6440. doi:10.1073/pnas.1202407109. <http://www.pnas.org/ content/109/17/6435> 9 Hansen, James, Pushker Kharecha, Makiko Sato, Valerie Masson-Delmotte, Frank Ackerman, David J. Beerling, Paul J. Hearty, et al. ‘Assessing “Dangerous Climate Change”: Required Reduction of Carbon Emissions to Protect Young People, Future Generations and Nature’. Edited by Juan A. Añel. PLoS ONE 8, no. 12 (3 December 2013): e81648. doi:10.1371/ journal.pone.0081648. <http://www.plosone. org/article/info%3Adoi%2F10.1371%2Fjournal. pone.0081648> 10 Ibid 11 Ibid 12 See <www.corporatewatch.org/uff/carbonbudget> 13 Chemicals used in hydraulic fracturing’. United States House of Representatives, Committee on Energy and Comerce Minority Staff (April 2011). <http:// democrats.energycommerce.house.gov/sites/ default/files/documents/Hydraulic-FracturingChemicals-2011-4-18.pdf> 14 Colborn, Theo et al., “Natural Gas Operations from a Public Health Perspective.” International Journal of Human and Ecological Risk Assessment. September-October 2011, p. 11. <http://cce.cornell.

edu/EnergyClimateChange/NaturalGasDev/ Documents/PDFs/fracking%20chemicals%20 from%20a%20public%20health%20perspective. pdf> 15 ‘Toxic Chemicals in the Exploration and Production of Gas from Unconventional Sources’. National Toxics Network April (2013). <http://www.ntn.org.au/wp/ wp-content/uploads/2013/04/UCgas_reportApril-2013.pdf> 16 ‘The Basics of Salinity and Sodicity Effects on Soil Physical Properties’. Accessed 25 February 2014. <http://waterquality.montana.edu/docs/methane/ basics_highlight.shtml> 17 Atkinson, C.M. ‘Environmental Hazards of Oil and Gas Exploration’. Report prepared for National Parks Association NSW Inc (August 2002) 18 ‘Oil and Gas Production Wastes’. Radiation Protection. US EPA. Accessed 25 February 2014. <http://www. epa.gov/radiation/tenorm/oilandgas.html> 19 Fisher, J. B., A. Santamaria. ‘Dissolved Organic Constituents in Coal-Associated Waters and Implications for Human and Ecosystem health’. 9th Annual International Petroleum Environmental Conference, 2002 October 22-25 20 ‘Coalbed Methane Extraction: Detailed Study Report (4.3.2.)’. United States Environmental Protection Agency (Dec 2010) <http://water.epa.gov/scitech/ wastetech/guide/304m/upload/cbm_report_2011. pdf> 21 Ibid (see 4.1 to 4.3) 22 Ibid [see 3.4) 23 John Wheaton, John Metesh. Potential Groundwater Drawdown and Recovery from Coalbed Methane Development in the Powder River Basin, Montana. US Bureau of Land Management (May 2003). <http://www.mt.blm.gov/mcfo/cbm/eis/ CBM3DGWReport.pdf> 24 Ibid 25 Lloyd-Smith M, Senjen R. ‘Hydraulic Fracturing in Coal Seam Gas Mining: The Risks to Our Health, Communities, Environment and Climate’. National Toxics Network [Internet]. 2011. Accessed July 2013. <http://ntn.org.au/wp/wp-content/ uploads/2012/04/NTN-CSG-Report-Sep-2011.pdf > 26 ‘Report Details Health Concerns for Residents Affected by CSG’. Sunshine Coast Daily. Accessed 25 February 2014. <http://www. sunshinecoastdaily.com.au/news/report-detailshealth-concerns-residents-affected-/1862076/> 27 Tim Jones ‘(draft) Wyong hydrogeological report’. Northern Geoscience (Jan 2005). <http://wage.org.au/documents/doc-41wyonghydrogeologicalreport.pdf> 28 ‘Wellbore Leakage Potential in CO2 Storage or EOR’. Fourth Wellbore Integrity Network Meeting,

Paris, France. March 19, 2008. <http://www. ieaghg.org/docs/wellbore/Wellbore%20 Presentations/4th%20Mtg/19.pdf> 29 ‘From Mud to Cement—Building Gas Wells ‘. Oilfield review (Autumn 2003) <http://www.slb.com/~/ media/Files/resources/oilfield_review/ors03/ aut03/p62_76.pdf> 30 ‘Northern San Juan Coal Basin Methane Project Draft Environmental Impact Statement. Appendix E. “Well Field Development Activities Common to All Alternatives,” p. E15.’. Bureau of Land Management (June 2004) 31 Jenkins, C.D. and Boyer, C.M. ‘Coalbed- and shale-gas reservoirs. Distinguished Author Series’. Journal of Petroleum Technology, February Issue, 92-99, SPE 103514 (2008) 32 ‘Environmental water and air quality issues associated with shale gas development in the Northeast’. Environmental water and air quality working group, NYS Water Resources Institute, Cornell University. <http://wri.eas.cornell.edu/ MSARC%20Env%20H2O%20Air%20Group%20 Revised%20071012.pdf> 33 M.A. Habermehl. ‘Summary of Advice in Relation to the Potential Impacts of Coal Seam Gas Extraction in the Surat and Bowen Basins, Queensland’. Geoscience Australia (29 September 2010). <http://www.environment.gov.au/epbc/notices/ pubs/gladstone-ga-report.pdf> 34 ‘Contaminated-sites-and-accidents-relatedspecifically-to-CSG-in-Australia’. coalseamgasnews. org. Accessed 25 February 2014. <http:// coalseamgasnews.org/wp-content/ uploads/2012/10/Contaminated-sites-andaccidents-related-specifically-to-CSG-inAustralia.pdf > 35 ‘CSG Myth Busting - Lock the Gate Alliance’. Accessed 25 February 2014. <http://www.lockthegate.org.au/ csg_myth_busting > 36 ‘Coalbed Methane: Clean Energy for the World’. Oilfield Review, Vol. 21, Issue 2 (06/01/2009). <http://www. slb.com/~/media/Files/resources/oilfield_review/ ors09/sum09/coalbed_methane.pdf > 37 ‘Coal Bed Methane Market – Global Industry Size, Market Share, Trends, Analysis, and Forecast, 2010 – 2018’. Transparency Market Research. <http:// www.transparencymarketresearch.com/coal-bedmethane-market.html> 38 IEA Clean Coal Centre 2005 <http://www.iea-coal. org.uk/site/2010/publications-section/cct2005?>.

endsOFtheearth

the

a guide To unconventional fossil fuels 42

Corporate Watch

endsOFtheearth

the

what is it? Underground Coal Gasification (UCG) is a way of producing fuel from coal seams, generally those that are uneconomical to extract using conventional mining methods because they are too thin, too deep or too low-quality. Pairs of wells are drilled into the coal seam. One well is used to ignite the seam and control the flow of air, oxygen or steam, allowing the coal to be partially burned. The other well is used to extract the resulting gases which can then be separated at the surface into carbon dioxide, water, and syngas (see below). Prior to ignition, hydraulic fracturing (fracking), directional drilling, or various other techniques are used to connect the wells together and allow the gas to flow.

Underground CoalGasification BURNING COAL SEAMS UNDERGROUND AND EXTRACTING THE RESULTING GAS TO USE AS FUEL. VERY HIGH WATER CONSUMPTION, CATASTROPHIC GROUNDWATER CONTAMINATION, AND DRAMATICALLY INCREASES ACCESSIBLE COAL RESOURCES WITH SEVERE IMPLICATIONS FOR CLIMATE CHANGE.

The syngas (an abbreviation of synthesis gas) is made up of hydrogen, methane, carbon monoxide, and can be directly burned to generate electricity, or used to make other fuels and chemicals such as hydrogen, ammonia and methanol. The process is chemically similar to how town gas (also known as coal gas) used to be made from coal before the adoption of natural gas in the mid 20th century. Experiences with town gas should as serve as a warning. The industry left a legacy of highly contaminated industrial sites around the world. The UCG process results in similar pollutants, the main difference being that UCG takes place in the open environment instead of a sealed metal chamber, increasing the risk of contamination.

The idea of UCG has been around for a long time, and experiments have been carried out since the 1912 in the UK,1 with further experiments in the 1930s. The use of the technology peaked in the 1960s in the Soviet Union, with up to 14 industrial-scale UCG fired power plants operating at different times between the 1950s and 1960s. Except for the Angren plant still operating in Uzbekistan, all the USSRâ&#x20AC;&#x2122;s plants were closed down by the end of the 1960s, following significant natural gas discoveries. Initially projects exploited shallow, easily accessible coal seams, but recent technology such as directional drilling, means that deeper and harder to reach seams can now also be accessed.

Recent pilot projects have been carried out in Australia, China, New Zealand, South Africa, New Zealand, Canada and the US, and one commercial plant has been operating in Uzbekistan (Angren) for over 40 years.2 A host of other countries are developing projects including the UK, Hungary, Pakistan, Poland, Bulgaria, Chile, China, Indonesia, India, and Botswana. Most UCG projects aim to produce electricity at the same site where extraction and gasification takes place. There are also plans to create liquid fuels from syngas using the Fischer-Tropsch process (so-called â&#x20AC;&#x2DC;coal to liquidâ&#x20AC;&#x2122; technology â&#x20AC;&#x201C; see separate factsheet).

Diagram of UCG operations

Test projects have been plagued by accidents, and have resulted in massive long term groundwater pollution. The implications for climate change are disastrous, as the technology produces large greenhouse gas emissions and would give access to vast previously inaccessible coal resources.

Climate change Whether in coal power stations or using UCG, burning coal produces more greenhouse gas emissions (GHG) than almost any other fossil fuel. UCG is particularly inefficient as energy is wasted heating the rock surrounding the chamber where the gasification takes place (known as the gasifier or combustion chamber). Other processes, such as removing hydrogen sulphide from exhaust gasses also require large amounts of

energy. Altogether around 40% of the energy from burning the coal is lost in the process.3 This wasted energy, combined with the high CO2 content and relatively low energy content of the syngas, mean that UCG produces large greenhouse gas emissions. Reliable figures are difficult to find, but it has been estimated that UCG would have CO2 emissions comparable with that from a conventional coal power station.4

Damage from coal seam fire in Glenwood springs, U.S.

"UCG projects around the world have been plagued with accidents, including examples of catastrophic groundwater contamination" 44

Another issue is the amount of coal that UCG would allow to be accessed. Global coal resource figures vary significantly, but it has been estimated that there are still around 860 billion tonnes of coal remaining that can be accessed with conventional mining techniques,5 possibly enough to last over a hundred years. However, using UCG technologies, coal seams that are uneconomical to mine can be exploited, giving access to even more coal, conservatively estimated as an extra 600 billion tonnes.6 The real figure could be much higher, as the total global coal resources (which includes coal that cannot be accessed with current technology) have been estimated to be in the trillions of tonnes. 7

Carbon Capture and Storage (CCS)

Proponents of UCG say that the technology is ideally suited for combination with CCS as it is relatively easy to remove the concentrated CO2 and inject it back into the exhausted coal seam. The argument then goes that CO2 could be removed directly from the UCG gas, or from the flue gas after combustion. However, there are significant concerns over the viability of CCS and UCG technologies, and there are no demonstrated projects where they work in combination. Despite industry claims that exhausted gasifiers would be ideal storage sites for CO2 produced during the process, there are in fact a number of serious problems that make them unsuitable. The expected collapse of the rock layer above gasifier means that the integrity of any potential ‘cap rock’ is likely to have been compromised, allowing CO2 to escape. High pressures and temperatures during and after gasification may also cause fracturing and changes in the permeability of the rock surrounding the gasifier, creating pathways through which CO2 could escape.11 There is also no guarantee that there is any ‘cap rock’ present above the coal-seam since, unlike oil and gas, coal seams don’t need impermeable rock above them to hold the coal in place. Due to high underground pressures, UCG carried out on deep coal seams would mean that the CO2 would

If we are to reduce carbon emissions to anything like the levels required to maintain a reasonably habitable planet we must move away from all forms of fossil fuel as fast as possible. Measuring from the start of the industrial revolution (around 1750), a maximum of 500 Gigatonnes of carbon (GtC) can be emitted to the atmosphere while still avoiding most serious impacts and the risk of irreversible and uncontrollable changes to the climate.8 Between 1750 and now (2014), we have already emitted about 370 GtC leaving a limit of 130 GtC that could be further added.9 In order to stay within this limit we have to leave the vast majority of the remaining conventional oil, coal and gas in the ground. Estimates vary significantly, but remaining conventional coal reserves alone are well over 500 GtC.10 Clearly developing UCG and giving access to enormous further coal resources, is absolutely incompatible with staying below this limit.

have to be stored in a ‘supercritical’ fluid state (a state in which the CO2 has the density of a liquid but flows like a gas). If this supercritical fluid escapes to shallower depths where pressures are lower, the CO2 would turn into gas, leading it to rapidly expand and become much more mobile. This could result in a sudden release of CO2 gas to aquifers or even to the surface. CO2 stored in the seam is also likely to react with pollutants and make them more mobile. It can also react with water and ash to make carbonic and sulphuric acid which can leach further contaminants from the rock, and reduce the sites’ ability to store CO2.12 Due to these and other factors, investigations into UCG have concluded that “it is considered unlikely therefore, that sequestration in an exhausted gasifier could provide a secure long term repository of CO2”13 and that there “remains substantial scientific uncertainty in the environmental risks and fate of CO2 stored this way”.14 CO2 storage in adjacent coal seams is also being considered, however this would only be possible in the highest permeability seams. There are also numerous critical problems with CCS itself, which remains a largely unproven technology, especially at the enormous scale that would be required (see CCS factsheet).

Other social and environmental issues Groundwater pollution

The various UCG projects that have been carried out around the world have been plagued with accidents, including examples of catastrophic groundwater contamination.15 Studies in the Soviet Union in the 1960s revealed that UCG could result in widespread groundwater contamination.16 In the 1970s a project at Hoe Creek, Wyoming, USA resulted in massive groundwater contamination.17 Potable groundwater was polluted with benzene, requiring an expensive long-term clean up operation.18 In 2011, Brisbane based company Cougar Energy was ordered to shut down its trial underground coal gasification project at Kingaroy due to environmental concerns over benzene contamination.19 The gasification cavity is a source of both gas and liquid pollutants that risk contaminating nearby groundwater. These include mercury, arsenic and selenium,20 coal tars containing phenols, BTEX (benzene, toluene, ethyl benzene, xylene) and other volatile organic compounds, and polycyclic aromatic hydrocarbons (PAHs).21 22 Of particular concern are benzene and phenols, as they are water soluble, can be transported by other chemicals, and are more likely to float upwards due to their low molecular weight. Altogether, one hundred and thirty-five compounds that might pollute the local groundwater sources near UCG sites have been identified.23 There have been instances of contaminants being forced out into groundwater due to high pressures in the gasifier. The industry claims that by maintaining pressures lower than those in the

surrounding grounwater they can eliminate the risk of contamination, as water will flow towards the gasifier rather than away from it. However, in practice controlling the pressures has proven difficult, and operating at lower pressures can result in less efficiency and more contamination.24 The Chinchilla test site in Australia claimed to have prevented contamination by controlling pressures, however others described it as

James St John 2012

Damage from an underground coal fire in Centralia, U.S.

“rather unsuccessful”.25 In addition, during previous test projects gasses escaped from the gasifier, finding the paths of least resistance, and carrying liquid pollutants along with them against the direction of groundwater flow.26 Any large open fissures or faults, the presence of which could be impossible to predict, would create emission pathways that could not be controlled by changing the pressures. Coal seams typically contain many natural fractures.

In many demonstration projects in shallow seams the area above the combustion chamber collapsed, and it is assumed at deeper sites that this will always happen. This can cause surface subsidence (see below), but also creates fractured pathways around the collapsed chamber for contaminants to leak into the groundwater. There is also the possibility of so called ‘cross contamination’ where already poor quality groundwater around the coal seam can flow to good quality ground water areas due to the changes in rock structures and water pressures caused by the UCG process. Another issue is the fact that the heat generated by gasification causes groundwater above the gasifier to rise, carrying contaminants with it. The contaminated ash left in the exhausted coal seam will remain there more or less indefinitely, meaning that it is a potential source of groundwater contamination decades or even centuries after gasification. Due to the depth of the coal seams where most UCG would be likely to take place it would also be extremely difficult to deal with any water contamination problems.

Water consumption, waste and surface water

Several aspects of the UCG process (such as initial mining, operation, then flushing and venting once gasification has finished) require injecting and extracting water from the gasifier. This means that the process consumes large volumes of water and produces large volumes of contaminated water. Waste water will vary significantly in terms of the contaminants present, as different coal seams and different stages of the process will generate different pollutants. This makes treating the waste water particularly difficult. There is also the risk of surface spillage from waste water storage facilities and transportation, and pollutants being released to the environment due to accidents at the site. In Australia, Carbon Energy was charged in 2011 with not reporting a series of “very serious” incidents involving spills and disposal of waste water.27

Syngas and air pollution

The burning of UCG syngas at the surface to produce electricity is known to generate air pollution, including oxides of sulphur and nitrogen, hydrogen sulphide, particulates and heavy metals such as mercury and arsenic.28 The syngas also contains contaminants which create problems for processing and transportation. These contaminants include dust, soot and tars which can clog up pipes and equipment; oxygen, from air or poor combustion control, which can potentially result in explosive mixtures; chlorine and chlorine compounds which can corrode equipment.29

Subsidence

As the reaction burns through the coal seam in the gasification chamber, it leaves a hole behind it filled with ash. The roof area directly above this hole usually collapses, which can result in subsidence at the surface, potentially damaging roads and buildings. The risk and extent of surface subsidence is greater the shallower the exploited coal-seam is, the larger the dimensions of the combustion chamber are and the weaker the rock is above the coal-seam. Underground and resulting surface subsidence can also affect the drainage patterns of surface water, the movement of ground water, with the potential to increase contamination, and can damage UCG injection and production wells. Rueter

A burning coal seam

Explosions and accidents

The high temperature and pressure flammable gases created by UCG, along with the blockages which can result from tar and soot contaminants mean there is the potential for explosions. This happened at the European UCG trial in Thulin, Belgium (1979-87), intended to test the feasibility of UCG on deeper coal seams. The trial had to be halted after one of the supply tubes to the burner became blocked leading to an underground explosion which damaged the injection well.30 In 1984, another test project in France was stopped due to tar and particles blocking the production well.31 During tests in the 1990s in Spain, an attempt to restart a UCG operation caused the accumulation of methane underground resulting in an explosion which damaged the production well.32 The injection and production wells are also prone to being damaged, as the gasification process results in extreme temperatures and pressures, and creates (as discussed above) cavities that are likely to collapse and compromise the integrity of the wells.

Scale

UCG plants produce a relatively small amount of power. The European trial in Tremedal, Spain in the 1990s only sustained gasification for a few days

at a time, and briefly peaked to produce gas with the equivalent of 8 Mega Watts (MW)of power.33 Eskomâ&#x20AC;&#x2122;s trial project in South Africa has a similar output of about 9 MW.34 A small coal fired power station produces well over a hundred times this much power and gets through as much coal in a day as many of the test projects burned in a year. Taking into account the energy lost from producing and burning the syngas, this means hundreds, possible even thousands of UCG plants could be required in order to replace just one coal power station. Considering the greenhouse gas emissions and the impact on groundwater resources experienced in test projects, scaling up UCG technology to provide a significant proportion of our energy would have a devastating impact on local environments and the global climate.

Industrialisation of countryside

UCG sites also require industrial equipment at the surface including drilling rigs, wellheads, connecting pipework, and plants for handling and processing the injection and production gases. As operations continue, additional wells and pipelines will be required, progressing further away from surface plants to access new coal supplies. There will also be a substantial increase in traffic volumes, in order to transport equipment and waste. Damage from an underground coal fire in Centralia, U.S.

Uncontrolled burns

Coal seams sometimes start burning naturally as a result of lightning, forest fires or spontaneous combustion following exposure to oxygen in air. These fires can continue to burn for decades or even centuries. When close to the surface, oxygen from the atmosphere fuels the fire, with subsidence from the burning seam often providing more air as the burn continues. In uncontrolled burns at greater depths, such as old deep coal mines, the oxygen usually

comes from ventilation shafts. Coal seam fires can have serious consequences. For example, in Centralia, Pennsylvania, US an uncontrolled mine fire beneath the borough that has been burning since 1962 has resulted in the population dwindling from over 1,000 residents in 1981 to 10 in 2010.35 Even with UCG of deeper coal seams there is a risk of uncontrolled burns as forgotten mine shafts, boreholes, damaged wells or geological faults could provide a source of air

Where, how Much and Who? In recent years there has been renewed interest in UCG. There are about 30 projects using underground coal gasification in various phases of preparation in China and the Indian government has plans to use UCG to access the countryâ&#x20AC;&#x2122;s huge remaining coal reserves.36

Hungarian government to develop UCG projects.

South African companies Sasol and Eskom both have UCG pilot facilities that have been operating for some time. In Australia, Linc Energy has the Chinchilla site, which first started operating in 2000. Demonstration projects and studies are also currently under way in the USA, Western and Eastern Europe, Japan, Indonesia, Vietnam, India, Australia and China.37 The Chukotka autonomous district in Russiaâ&#x20AC;&#x2122;s Far East looks set to be the first place in the country to implement the technology,38 and Eon has signed a memorandum of understanding with the

Other notable companies around the world involved in the development of UCG include: Swan Hills Synfuels in Alberta, Virginia, USA, Santos in New South Wales, Australian and Carbon Energy and Portman Energy which have developed UCG techniques.

In the UK Cluff Natural Resources have plans to implement the first UK UCG site in Warwickshire. Another UK company, Clean Coal Ltd, had planned to carry out the first UK test project under Swansea Bay in Wales.

In addition, the Underground Coal Gasification Association,39 an industry membership organisation, has been playing a key role in promoting the technology.

For more information on resistance see the Corporate Watch website (corporatewatch.org/uff/resistance)

Endnotes 1 Klimenko, Alexander Y. ‘Early Ideas in Underground Coal Gasification and Their Evolution’. Energies 2, no. 2 (24 June 2009): 456–476. doi:10.3390/en20200456. <http:// www.mdpi.com/1996-1073/2/2/456> 2 ‘Viability of Underground Coal Gasification with Carbon Capture and Storage in Indiana’. School of public and environmental affairs, Indiana University (2011). <http://www. indiana.edu/~cree/pdf/Viability%20of%20 Underground%20Coal%20Gasification%20 Report.pdf> 3 ‘European UCG case study’. UCGP training course March 2011, UCG Partnership (2011). <http://repository.icse.utah.edu/dspace/ bitstream/123456789/11029/1/European%20 UCG%20Case%20Study%20MBGreen2011. pdf> 4 Laughlin K and Summerfield I. ‘Environmental Impact of Underground Coal Gasification’. Report prepared by the CRE Group Ltd for the Coal Authority (2000) 5 ‘Survey of Energy Resources 2010’. World Energy Council. <http://www.worldenergy. org/publications/3040.asp> 6 ‘Survey of Energy Resources 2007’. World Energy Council (2007). <http://www. worldenergy.org/publications/survey_of_ energy_resources_2007/coal/634.asp> 7 ‘Resources to Reserves 2013’. International Energy Agency (2013). <http://www.iea.org/ Textbase/npsum/resources2013SUM.pdf> 8 Hansen, James, Pushker Kharecha, Makiko Sato, Valerie Masson-Delmotte, Frank Ackerman, David J. Beerling, Paul J. Hearty, et al. ‘Assessing “Dangerous Climate Change”: Required Reduction of Carbon Emissions to Protect Young People, Future Generations and Nature’. Edited by Juan A. Añel. PLoS ONE 8, no. 12 (3 December 2013): e81648. doi:10.1371/journal. pone.0081648. <http://www.plosone.org/ article/info%3Adoi%2F10.1371%2Fjournal. pone.0081648> 9 Ibid 10 Ibid 11 ‘CCTR Basic Facts File # 12 - Underground Coal Gasification’. Indiana Center for Coal Technology Research (Oct 2008). <http://www.purdue. edu/discoverypark/energy/assets/pdfs/cctr/ outreach/Basics12-UCG-Oct08.pdf> 12 Ibid 13 ‘Review of Environmental Issues of Underground Coal Gasification’. UK Department of Trade and Industry, Report No. COAL R272 DTI/Pub URN 04/1880 (November 2004). <http://webarchive.

nationalarchives.gov.uk/+/http:/www.dti. gov.uk/files/file19154.pdf> 14 Friedmann, S. Julio, Ravi Upadhye, and Fung-Ming Kong. ‘Prospects for Underground Coal Gasification in Carbon-Constrained World’. Energy Procedia 1, no. 1 (February 2009): 4551–4557. doi:10.1016/j.egypro.2009.02.274. <http://wenku.baidu.com/view/ a76810f64693daef5ef73dc2.html > 15 Kapusta, Krzysztof, and Krzysztof Stańczyk. ‘Pollution of Water during Underground Coal Gasification of Hard Coal and Lignite’. Fuel 90, no. 5 (May 2011): 1927–1934. doi:10.1016/j.fuel.2010.11.025. <http://www. sciencedirect.com/science/article/pii/ S001623611000640X> 16 Liu Shu-qin, Li Jing-gang, Mei Mei and Dong Dong-lin. ‘Groundwater Pollution from Underground Coal Gasifiacation’. Journal of China University of Mining & Technology 17, 4 (2007) 17 Shafirovich, Evgeny, and Arvind Varma. ‘Underground Coal Gasification: A Brief Review of Current Status’. Industrial & Engineering Chemistry Research 48, no. 17 (2 September 2009): 7865–7875. doi:10.1021/ie801569r. <http:// pubs.acs.org/doi/abs/10.1021/ie801569r> 18 ‘Fire in the Hole’. Science and Technology Review, April 2007. Accessed 26 February 2014. <https://www.llnl.gov/str/April07/ Friedmann.html> 19 ‘Cougar Energy to Drop Law Suit against Government’. ABC News (Australian Broadcasting Corporation). Accessed 26 February 2014. <http://www.abc.net.au/ news/2013-07-27/energy-company-to-droplaw-suit-against-government/4847704> 20 Liu, S, Y Wang, L Yu, and J Oakey. ‘Volatilization of Mercury, Arsenic and Selenium during Underground Coal Gasification’. Fuel 85, no. 10–11 (July 2006): 1550–1558. doi:10.1016/j.fuel.2005.12.010. <http://www. sciencedirect.com/science/article/pii/ S0016236105004904> 21 ‘Environmental Issues in Underground Coal Gasification (with Hoe Creek example)’. Lawrence Livermore National Laboratory (under the auspices of the U.S. Department of Energy). <http://fossil.energy.gov/international/ Publications/ucg_1106_llnl_burton.pdf> 22 Smoliński, Adam, Krzysztof Stańczyk, Krzysztof Kapusta, and Natalia Howaniec. ‘Chemometric Study of the Ex Situ Underground Coal Gasification Wastewater Experimental Data’. Water, Air, & Soil Pollution 223, no. 9 (22 September 2012): 5745–5758. doi:10.1007/s11270012-1311-5. <http://www.ncbi.nlm.nih.gov/ pmc/articles/PMC3487001/>

23 Stuermer, D.H., J.N. Douglas, and C.J. Morris. ‘Organic contaminants in groundwater near an underground coal gasification site in northeastern Wyoming’. Environmental Science and Technology 16: 582-587 (1982) 24 Op cit ‘Review of Environmental Issues of Underground Coal Gasification’. UK DTI (Nov 2004) 25 Coal Insights, vol.6 iss.8 (28 Mar 2012). <http:// ezines.mjunction.in/coalinsights/28032012/ pdf/pagetemp.pdf > 26 Op cit ‘Review of Environmental Issues of Underground Coal Gasification’. UK DTI (Nov 2004) 27 ‘Carbon Energy Fined Over UCG Spill’. Accessed 26 February 2014. <http://www.brisbanetimes. com.au/queensland/charges-laid-over-ucgspill-20110712-1hbvu.html> 28 Op. Cit. ‘Review of Environmental Issues of Underground Coal Gasification’. UK DTI (Nov 2004) 29 ‘Underground Coal Gasification (UCG), its Potential Prospects and its Challenges’. Duncan and Seddon Associates. <http://www. duncanseddon.com/underground-coalgasification-ucg-potential-prospects-andchallenges/> 30 Op. Cit. (‘European UCG case study’ 2011) 31 Op Cit. (‘Viability of Underground Coal Gasification with Carbon Capture and Storage in Indiana’ 2011) 32 Op. Cit. (Shafirovich and Varma 2009) 33 Op. Cit. (‘European UCG case study’ 2011) 34 ‘South Africa’s Eskom Unveils Ambitious UCG Plans’. www.worldfuels.com. Accessed 26 February 2014. <http://www.worldfuels.com/ wfExtract/exports/Content/de47011b-2bd543ef-ba29-8b42fca895f4.html> 35 ‘Profile of General Population and Housing Characteristics: 2010: 2010 Demographic Profile Data’. U.S. Census Bureau. Retrieved 26 February 2013. <http://factfinder2.census.gov/ faces/tableservices/jsf/pages/productview. xhtml?src=bkmk> 36 Op. Cit. [WEC 2013] 37 Op. Cit. [WEC 2013] 38 ‘Russia’s First Coal Gasification Project Could Begin in Chukotka’. The Moscow Times. Accessed 26 February 2014. <http://www. themoscowtimes.com/news/article/russiasfirst-coal-gasification-project-could-beginin-chukotka/484534.html> 39 <http://www.ucgassociation.org/>

endsOFtheearth

the

a guide To unconventional fossil fuels 50

Corporate Watch

endsOFtheearth

the

what is it? Sometimes known as “the rock that burns”, oil shale is sedimentary rock that is rich in kerogen, a solid tar-like material, which becomes a liquid when heated. It can be burned in its rocky form straight from the ground, or oil and gas can be extracted using a process called ‘retorting’. This is done either after the oil shale has been mined, where it is crushed up and refined, or ‘in-situ’ (in place) underground by directly heating the deposit and extracting the resulting liquid, which then requires further processing. The ‘oil’ produced from oil shale, sometimes referred to as synthetic crude, synfuel or shale oil (see below) is of lower quality and contains less energy than conventional crude oil. Global resources are estimated at 4.8 trillion barrels.1

Oilshale OILY ROCK THAT CAN BE BURNED, OR PROCESSED TO PRODUCE A LIQUID FUEL. EXTREMELY INEFFICIENT AS A FUEL, RESULTS IN VERY HIGH GREENHOUSE GAS EMISSIONS AND SERIOUS WATER POLLUTION.

Oil shale or shale oil?

Oil shale has been used as a fuel for thousands of years, initially burned directly as a source of heat and later to produce steam and electricity. It was not until the mid 19th century in France and Scotland that it was used to produce oil on an industrial scale. As crude oil extraction increased after the Second World War, oil shale became less attractive as a fuel source. Production of synthetic crude from oil shale peaked following the 1973 oil crisis and then fell sharply. It is only recently, with high oil prices, increasing scarcity of conventional crude, and countries’ increasing concern over energy security, that there has been a resurgence in interest in oil shale. Oil shales vary significantly in terms of the quantity of kerogen and the other substances they contain, some of which can be commercially extracted along with the oil shale. Uranium, vanadium, zinc, alumina, phosphate, sodium carbonate minerals, ammonium sulphate, and sulphur are all sometimes found in oil shales.2

Confusingly, ‘shale oil’ can refer to the liquid fuel extracted from ‘oil shale’ by heating it (this was always the traditional meaning of the term), or to oil extracted from shale rock using techniques such as fracking. The second definition began being used when the US boom in shale gas resulted in shale formations also being exploited for oil (see separate ‘Shale Oil’ factsheet for more information). A great deal of confusion and disagreement persists, but many have started to use the term ‘tight oil’ to refer to oil extracted from shale formations using horizontal drilling and fracking. Even more confusingly, the term ‘oil shale’, which usually means the oily rock rich in kerogen being discussed in this factsheet, is also sometimes used to refer to shale formations which contain oil. Baffled? Well, you’re not alone!

Shell’s experimental freeze wall oil shale installation

how is it extracted?

Oil shale can be burned in its rocky form, or can be processed, to produce a form of oil. This processing can either be done after the oil shale has be mined, or can take place underground using in-situ techniques. The raw oil shale is usually extracted using surface mining techniques, such as open pit or strip mining, but underground mining can also be used. When burned directly, oil shale is usually used to generate electricity. In Estonia, which has by far the most developed oil shale industry, 90% of the country’s electricity is provided by oil shale fuelled power stations.3 However, currently the most financially attractive feature of oil shales is that they can be used to produce liquid fuel. There are a variety of ‘surface retorting’ techniques used to extract liquid after mining. These involve crushing up the mined oil shale, heating it to around 450°C which converts the kerogen into liquid which is then removed and processed. Surface retorting methods have been around for a long time and are currently used on a commercial scale in various countries including China and Estonia. Surface retorting results in high greenhouse gas emissions, uses large amounts of water and

creates large amounts of solid waste (the shale actually expands during the processing, meaning there is more volume of waste than was dug out the ground).4 Various techniques have either been experimented with or considered for underground in-situ retorting.5 Methods of heating include placing gas powered fuel cells below the oil shale to heat it; drilling into the deposit and injecting it with super-heated air, steam or gas; using electrical resistance heaters; and heating using radio or microwaves which can penetrate into the deposit instead of slowly heating from the outside. The heating process usually takes a number of years before the liquid can be extracted. Many methods of in-situ extraction also require breaking up the oil shale to allow fluids to flow more

Wikipedia user: PjotrMahh1 2005

An oil shale excavator

easily. Some include the use of ‘fracking’ (hydraulic fracturing), explosives, or partially mining the deposit (in the 1960s, nuclear explosions were even considered as a way of breaking up the oil shale!). Fracking is a controversial technology also used in shale gas extraction, which involves drilling into rock and injecting pressurised fluid, creating cracks that allow trapped gasses and liquids to flow. The fracking fluid consists of water, sand and a variety of chemicals which are added for various purposes, such as dissolving minerals, killing bacteria that might plug up pipes and wells, or reducing friction. Other proposed methods of in-situ extraction include mining into the deposit then setting off explosives to turn the oil shale to rubble (known as rubblisation), then igniting part of the deposit and using the heat to convert kerogen into synthetic crude which is then extracted. Nuclear reactors have also been proposed as a heat source.6

Shell have also been experimenting with a ‘freeze wall’ technology, in which chilled liquid is circulated through a system of pipes, freezing water in the surrounding rock to form a wall of ice. This freeze wall is intended to both keep groundwater away from the area where retorting takes place, and to stop pollutants from the process contaminating groundwater. Oil shale gas is also produced during retorting and can be either separated and sold off, used as a fuel to provide heat for retorting, or heated and injected underground to convert kerogen to liquid during in-situ retorting. Many of these techniques have been demonstrated on small scale test sites. However, experiments have been plagued with difficulties and there is currently no in-situ oil shale extraction taking place on a commercial scale. So far it has simply proven to be too difficult, too expensive and too environmentally damaging.

Climate change The amount of CO2 produced from using oil shale for energy varies significantly depending on composition of the oil shale, the method of extraction and how it is used to generate energy. However, regardless of the deposit exploited or method used, oil shale is a highly greenhouse gas intensive energy source. A major problem with using oil extracted from oil shale as an energy source is the amount of energy input needed in order to get energy out (known as Energy Return On Investment or EROI). A 1984 study estimated the EROI of the various known oil shale deposits as varying between 0.7–13.3;7 The World Energy Outlook 2010 estimated the EROI of ex-situ processing as around 4 to 5 and in-situ processing as low as two.8 The true value could be even lower: a review by Western Resource Advocates found that the most reliable studies, which include self-energy (energy released by the oil shale conversion process that is used to power that operation), suggest an EROI for liquid fuel from oil shale between one and two, but could not guarantee that it was greater than one.9 These all compare badly with current conventional oil and wind energy which both have an EROI of about 25.10 11 Whatever the exact figure, it is clear that oil shale is an extremely inefficient fuel source.

Part of the reason for the low EROI values for liquid fuels derived from oil shale is that kerogen is like an immature form of crude oil, and it requires significant further processing (particularly heating) to make up for the final stage of geological processing that produces oil. Burning mined oil shale directly to generate electricity produces significantly higher amounts of CO2 than conventional fossil fuels. Using current methods it produces about one and a half the CO2 per unit of energy of coal, and even with technological improvements would still result in the same greenhouse gas emissions as coal.12 One reason for this is that oil shales contain a relatively small proportion of useful fuel (organic material) and carbonate in the oil shale is also burned which adds to the CO2 produced without providing more energy. Extracting liquid fuel from oil shale also results in large amounts of CO2 emissions. A recent study of the full lifecycle carbon dioxide (CO2) emissions from oil shale derived liquid fuels estimated them to be 25 to 75% higher than those from conventional liquid fuels, depending on the process used.13 The various sources of greenhouse gas emissions include

generating heat for retorting, high temperature decomposition of carbonates, methane release and upgrading and refining of the shale oil crude.14 The oil shale industry claims that new in-situ retorting methods will reduce greenhouse gas emissions, however the main sources of emissions will remain, and some methods even create additional sources, such as the huge amount of energy required to create the refrigerated barrier in Shell’s ‘freezewall’ method. It has been estimated that the full-fuel-cycle emissions for fuels derived using the Shell process are 21%-47% larger than those from conventionally produced petroleum-based fuels.15 Regardless of how oil shales compare to coal or conventional oil as an energy source, they represent a vast source of carbon which we cannot afford to develop.

If we are to reduce carbon emissions to anything like the levels required to maintain a reasonably habitable planet we must move away from all forms of fossil fuel as fast as possible. Measuring from the start of the industrial revolution (around 1750), a maximum of 500 Gigatonnes of carbon (GtC) can be emitted to the atmosphere while still avoiding most serious impacts and the risk of irreversible and uncontrollable changes to the climate.16 Between 1750 and now (2014), we have already emitted about 370 GtC leaving a limit of 130 GtC that could be further added.17 In order to stay within this limit we have to leave the vast majority of the remaining conventional oil, coal and gas in the ground. Estimates vary significantly, but remaining conventional coal reserves alone are well over 500 GtC.18 CONVENTIONAL OIL ‘SAFE’ EMISSIONS LIMIT 130 GtC

325 GtC OIL SHALE

295 GtC

CONVENTIONAL GAS

277 GtC

Exploiting the world’s oil shale would add around 295 GtC to the atmosphere.19 This is an enormous amount and is absolutely incompatible with staying below the limit outlined above.

Carbon Capture and Storage (CCS)

There have been investigations into the possiblity of using waste ash from oil shale fuelled power stations to store CO2. However, even if it works the proportion of CO2 emissions absorbed would be small (10 – 11%) and it would still be an extremely carbon intensive energy source.20 Proponents of unconventional fossil fuels often argue that with CCS technologies, these new energy sources could be exploited at the same time as reducing GHG emissions. However, even if the huge problems with CCS technology are overcome (and this currently looking extremely unlikely), it would not change the fact that we need to move away from all forms of fossil fuel, conventional and unconventional, as soon as possible. In the most optimistic (and highly implausible) scenario, CCS could be used to reduce a small proportion of emissions from fossil fuels. In reality, the promise of CCS being implemented in the future is being used to allow the continued expansion of fossil fuel production, to prevent alternatives from being developed, and to deflect attention away from approaches which tackle the underlying systemic causes of climate change and other ecological crises. Ultimately CCS is a smokescreen, allowing the fossil fuel industry to continue profiting from the destruction of the environment. (see ‘Carbon Capture Storage’ factsheet for more information).

Other social and environmental issues Water consumption

Although estimates of the exact amounts vary widely, producing liquid fuel from oil shale requires a lot of water. Using surface retorting requires between about 2 and 5 barrels of water for every barrel of oil produced.21 For in-situ methods the amount of water required is anywhere between 1 and 12 barrels per barrel of oil.22 When you consider that globally there are trillions of barrels of oil shale resources, that adds up to a lot of water being used. In 2002, in Estonia, where oil shale provides 90% of the countryâ&#x20AC;&#x2122;s electricity,23 the oil shale-fired power industry used 91% of the total water consumed in the country.24 In addition to water directly consumed during operations, underground oil shale mining could also disrupt groundwater flow, as large volumes of water will need to be extracted, potentially reducing water levels in shallow aquifers. The heat required for in-situ extraction is also likely to disrupt groundwater flows, and hot gases escaping during the process could fracture the rock and create new pathways for water (and contaminants) to flow.

Water contamination

Oil shale extraction and processing involves serious risk of water contamination. For mining and surface retorting, this is mainly a result of the used oil shale left after it has been retorted. The waste shale contains various salts and toxic substances such as arsenic and selenium.25 This is often used to fill the space left after mining (see waste section below). As groundwater comes into contact with spent shale it can leach out the contaminants, polluting the water. Research in China found evidence of soil and groundwater contamination by heavy metals and carcinogenic hyrdocarbons which were traced back to an oil shale waste site.26 Other potential sources of water pollution from mining and surface retorting include mine drainage, discharges from surface operations associated with solids handling, retorting, upgrading, and plant utilities. Oil shale processing results in waste waters that contain phenols, tar and several other toxic substances.27 There is a lack of research into effects of in-situ oil shale production on groundwater, however water pollution is a serious concern. The heat from the process will create and release contaminants from

KiviĂľli Oil Shale Processing & Chemicals Plant in ida-Virumaa, Estonia

"In 2002, in Estonia, the oil shale-fired power industry used 91% of the total water consumed in the country" 55

the surrounding rock and as a result retort waters are likely to have high concentrations of soluble organic materials, along with very high concentrations of ammoniacal nitrogen, alkalinity, chlorides, and sulfates.28 Past studies have found that in-situ production processes could leak contaminated water into adjacent aquifers and surface water.29 30 31

Air pollution

Oil shale operations, (mining, burning, refining etc.) can result in a variety of air pollutants. These can include hydrogen sulphide, sulphur oxides, nitrogen oxides, particulates, ozone precursors, and carbon monoxide.32 Small amounts of other pollutants may also be produced, such as arsenic, mercury, cadmium and selenium compounds.33 To take the example of Estonia again, in 2002, 97% of air pollution came from the power industry, the vast majority of which is fuelled by oil shale.34 In short, if the oil shale industry were to be developed on a global scale it would create serious and widespread local air pollution problems.

Other waste

Oil shale production creates large amounts of solid waste. Burning oil shale produces toxic ash, which is sometimes partially ‘backfilled’ into the cavity that it was mined from, risking groundwater contamination. Surface retorting also produces large volumes of waste, according to the European Academies Science Advisory Council (EASAC) producing a barrel of shale oil can generate 1.5 tons (1.4 tonnes) of spent shale, which occupies 15 25% greater volume than the original shale, due to ‘popcorn’ like expansion during the process.35 Waste material can include several pollutants including sulfates, heavy metals, and polycylic aromatic hydrocarbons (PAHs), some of which are carcinogenic.36 37

Oil shale

Industrialisation of countryside

Oil shale is often found in remote areas without existing major roads and pipelines, and significant new infrastructure would accompany any oil shale extraction operations. Surface facilities would be required for upgrading, storage and transportation. Roads, power plants, power distribution systems, pipelines, water storage and supply facilities, construction staging areas, hazardous materials handling facilities, and various other buildings would also be required. In addition there would be significant impact on the landscape from associated surface and underground mining. As an example, if quarried in open pits, a single full scale processing plant with an output of 100 000 barrels per day, would require a mining operation similar in size to the largest of the vast brown-coal mines in Germany.38 Using in-situ methods still has widespread and serious impacts. The landscape would be dotted with wells, heating holes and installations which will be in operation for 15 to 25 years.39 Wells would have to be drilled close to each other, and each would have to be connected to a treatment plant by a network of pipelines. It has been estimated that 15 to 25 heating holes per acre (per 0.004 square kilometres) would be required for in-situ production.40

Where and how Much? There is a well developed oil shale industry in Estonia, which currently consumes the majority of the world’s oil shale production to generate electricity. Many are also trying to profit from exporting this expertise to other countries. Oil shale is also exploited on an industrial scale in China (which is rapidly expanding its capacity), Brazil and to a lesser extent in Russia, Germany and Israel. By far the largest deposits are found in the US, with one deposit alone, the Green River formation, containing the equivalent of 3 trillion barrels of oil, over 60% of the total oil shale resources found in the world.41 There have been several failed attempts at commercial development of oil shale in the US. For example Exxon invested $5billion in the 1970s, but pulled out in 1982 when oil prices fell again.42 Oil prices have also largely driven global production, which peaked following the 1973 oil crisis and then fell with the price of oil. It is only recently, with high oil prices, conventional crude becoming more scarce, and countries’ increasing concern over energy security, that there has been a resurgence in interest in oil shale. In 2003, an oil shale development program restarted in the United States. Having lifted a previous moratorium, Australia is similarly beginning to re-start oil shale

companies involved Several of the multinational ‘super major’ oil companies are involved in oil shale development in the US, particularly Shell, Chevron and Exxon. Many ‘national’ or semi public oil companies, such as Petrobras in Brazil, PetroChina in China and Jordan Oil Shale Energy Company are leading development in their respective countries.

activities. Many other countries are also currently investigating or have plans to exploit their oil shale resources. Jordan for example has signed memorandums of understanding with various companies and has plans to rapidly develop its resources.43 Israel and Morocco also have plans to develop oil shale industries aiming to achieve greater energy security or even independence. Mongolia has shown interest in the resource and several companies including Total now have an oil shale presence in the country. Despite this recent interest, difficulties remain. For example, Chevron stopped its oil shale research in Rio Blanco County, Colorado, US in February 2012,44 and Shell recently closed its experimental oil shale plant, saying it planned to focus on other activities.45 One factor hindering the industry in the US is the surge in domestic tight oil production which has made oil shale less economically attractive (see above for an explanation of the terms ‘oil shale’, ‘shale oil’ and ‘tight oil’). Despite the enormous total global oil shale resources (estimated at 4.8 trillion barrels),46 there is still a great deal of uncertainty over the exact amount and what proportion of it could be economically extracted, as much of it is found in found in extremely low grade rock.

Resistance Grassroots opposition to oil shale extraction in Australia resulted in a 20-year moratorium on development of the McFarlane oil shale deposit. However, the government recently announced that it will allow the development of a commercial oil shale industry in Queensland.47 Development in the US has also been met with resistance from environmental groups.48

For more information on resistance see the Corporate Watch website (corporatewatch.org/uff/resistance)

Endnotes 1 ‘World Energy Resources: 2013 Survey’. World Energy Council (2013). <http://www. worldenergy.org/publications/2013/worldenergy-resources-2013-survey > 2 ‘Oil Shale: A fuel lifeline’. Oil Shale Information Centre. Accessed 26 Feb 2014. <http://www. oilshale.co.uk/oilshaleguide.pdf> 3 Francu, Juraj; Harvie, Barbra; Laenen, Ben; Siirde, Andres; Veiderma, Mihkel. A study on the EU oil shale industry viewed in the light of the Estonian experience. A report by EASAC to the Committee on Industry, Research and Energy of the European Parliament. European Academies Science Advisory Council. pp.14–15; 45 (May 2007). Retrieved 2011-05-07. <http://www.easac.org/fileadmin/ PDF_s/reports_statements/Study.pdf> 4 [ibid] 5 ‘An Assessment of Oil Shale Technologies’. Office of Technology Assessment, Congress of the United States (June 1980). <http://www.princeton. edu/~ota/disk3/1980/8004_n.html> 6 ‘Nuclear energy proposed for production of shale oil’. Oil and Gas Journal (07/10/2006). <http:// www.ogj.com/articles/print/volume-104/ issue-26/general-interest/nuclear-energyproposed-for-production-of-shale-oil.html> 7 Cleveland, C. J., R. Costanza, C. A. S. Hall, and R. Kaufmann. ‘Energy and the U.S. Economy: A Biophysical Perspective’. Science 225, no. 4665 (31 August 1984): 890–897. doi:10.1126/ science.225.4665.890. <http://www.sciencemag. org/content/225/4665/890 > 8 ‘World Energy Outlook 2010’. Paris: International Energy Agency, 2010. <http://www. worldenergyoutlook.org/media/weo2010.pdf> 9 ‘An Assessment of the Energy Return on Investment (EROI) of Oil Shale ‘. Western Resource Advocates (June 2010). <http://www. westernresourceadvocates.org/land/oseroi. php> 10 Kubiszewski, I., & Cleveland, C. ‘Energy return on investment (EROI) for wind energy’ (2013) <http:// www.eoearth.org/view/article/152560> 11 ‘Oil Sands Mining Uses Up Almost as Much Energy as It Produces’. Inside Climate News. Accessed 26 February 2014. <http://insideclimatenews.org/ news/20130219/oil-sands-mining-tar-sandsalberta-canada-energy-return-on-investmenteroi-natural-gas-in-situ-dilbit-bitumen> 12 Op cit (Francu et al 2007) 13 Adam R. Brandt et al. ‘Carbon Dioxide Emissions from Oil Shale Derived Liquid Fuels’. Chapter 11 in Oil Shale: A Solution to the Liquid Fuel Dilemma, pp.219-48 (2010). <http://pubs.acs.org/doi/ abs/10.1021/bk-2010-1032.ch011> 14 Op cit (Francu et al 2007) 15 Brandt, Adam R. ‘Converting Oil Shale to Liquid Fuels: Energy Inputs and Greenhouse Gas Emissions of the Shell in Situ Conversion Process’. Environmental Science & Technology 42, no. 19 (October 2008): 7489–7495. doi:10.1021/ es800531f. <http://pubs.acs.org/doi/abs/10.1021/ es800531f> 16 Hansen, James, Pushker Kharecha, Makiko Sato, Valerie Masson-Delmotte, Frank Ackerman, David J. Beerling, Paul J. Hearty,

et al. ‘Assessing “Dangerous Climate Change”: Required Reduction of Carbon Emissions to Protect Young People, Future Generations and Nature’. Edited by Juan A. Añel. PLoS ONE 8, no. 12 (3 December 2013): e81648. doi:10.1371/ journal.pone.0081648. <http://www.plosone. org/article/info%3Adoi%2F10.1371%2Fjournal. pone.0081648> 17 Ibid 18 Ibid 19 See <www.corporatewatch.org/uff/carbonbudget> 20 Uibu, Mai, Mati Uus, and Rein Kuusik. ‘CO2 Mineral Sequestration in Oil-Shale Wastes from Estonian Power Production’. Journal of Environmental Management 90, no. 2 (February 2009): 1253–1260. doi:10.1016/j.jenvman.2008.07.012. <http:// www.sciencedirect.com/science/article/pii/ S0301479708002053> 21 J. T. Bartis, T. LaTourrette, L. Dixon, D.J. Peterson, and G. Cecchine. ‘Oil Shale Development in the United States Prospects and Policy Issues’. RAND Corporation, MG-414-NETL (2005). <http:// www.rand.org/content/dam/rand/pubs/ monographs/2005/RAND_MG414.pdf> 22 ‘Impacts of Potential Oil Shale Development on Water Resources’. GAO, Energy Development and Water Use, GAO-11-929T, p.8 (August 24, 2011). <http://www.gao.gov/assets/130/126827.pdf> 23 Op cit (Francu et al 2007) 24 Raukas, Anto. ‘Opening a new decade’. Oil Shale. A Scientific-Technical Journal (Estonian Academy Publishers) 21 (1): 1–2. ISSN 0208-189X. (2004). <http://www.kirj.ee/public/oilshale/1_ ed_page_2004_1.pdf> 25 Op. Cit. (Francu et al 2007) 26 Ding, Aizhong, Jiamo Fu, Guoying Sheng, Puxin Liu, and P. J. Carpenter. ‘Effects of Oil Shale Waste Disposal on Soil and Water Quality: Hydrogeochemical Aspects’. Chemical Speciation and Bioavailability 14, no. 1 (10 November 2002): 79–86. doi:10.3184/095422902782775353. <http:// www.ingentaconnect.com/content/stl/ csb/2002/00000014/F0040001/art00010> 27 Kahru, A.; Põllumaa, L. ‘Environmental hazard of the waste streams of Estonian oil shale industry: an ecotoxicological review’. Oil Shale. A ScientificTechnical Journal (Estonian Academy Publishers) 23 (1): 53–93. ISSN 0208-189X (2006). <http:// www.kirj.ee/public/oilshale/oil-2006-1-5.pdf> 28 Harding, B.L., K.D. Linstedt, E.R. Bennet, and R.E. Poulson. ‘Study Evaluates Treatments for Oil Shale Retort Waters’. Industrial Wastes, Vol. 24, No. 5 (1978). 29 Amy, Gary, and Jerome Thomas. ‘Factors That Influence the Leaching of Organic Material From In-situ Spent Shale’. Proceedings of the Second Pacific Chemical Engineering Congress, Denver, CO (August 1977) 30 Parker, H.W., R.M. Bethea, N. Guven, M.N. Gazdar, and J.C. Watts. ‘Interactions Between Ground Water and In-situ Retorted Oil Shale’. Proceedings of the Second Pacific Chemical Engineering Congress, Denver CO (August 1977) 31 ‘White River Resource Area Resource Management Plan Final Environmental Impact Statement’. US Bureau of Land Management, pp. 4-5 (1996)

32 Op. Cit. (Francu et al 2007) 33 Ibid 34 Raukas, Anto. ‘Opening a new decade’. Oil Shale. A Scientific-Technical Journal (Estonian Academy Publishers) 21 (1): 1–2. ISSN 0208-189X. (2004). <http://www.kirj.ee/public/oilshale/1_ed_ page_2004_1.pdf> 35 Op. Cit. (Francu et al 2007) 36 Mölder, Leevi. ‘Estonian Oil Shale Retorting Industry at a Crossroads’. Oil Shale. A ScientificTechnical Journal (Estonian Academy Publishers) 21 (2): 97–98. ISSN 0208-189X. (2004). <http://www.kirj.ee/public/oilshale/1_ed_ page_2004_2.pdf> 37 Tuvikene A., Huuskonen S., Koponen K., Ritola O., Mauer U., Lindstrom-Seppa P. Oil shale processing as a source of aquatic pollution: Monitoring of the biologic effects in caged and feral freshwater fish. Environ. Health. Persp. 1999;107:745–752. doi:10.1289/ehp.99107745. <http://www.ncbi.nlm. nih.gov/pmc/articles/PMC1566439/> 38 Op cit (Francu et al 2007) 39 Ibid 40 ‘Oil Shale Research, Development, and Demonstration’ Bureau of Land Management, Environmental Assessment CO-110-2006-117 EA, p. 132. (November 2006). <http://www.co.blm.gov/ wrra/wrfo_os_eas.htm> 41 ‘Survey of Energy Resources 2010’. World Energy Council. <http://www.worldenergy.org/ publications/3040.asp> 42 ‘Oil Shale Never Stays down Long’. High Country News. Accessed 8 March 2014. http://www.hcn. org/wotr/oil-shale-never-stays-down-long/ print_view 43 ‘Karak International to Develop Oil Shale Projects’. ‘Jordan News Agency (Petra). Accessed 7 March 2014. <http://www.petra.gov.jo/ Public_News/Nws_NewsDetails.aspx?Site_ Id=1&lang=2&NewsID =140237&CatID=13&Type=Home&GType=1> 44 ‘Chevron Leaving Western Slope Oil Shale Project’ Denver Business Journal. Accessed 8 March 2014. <http://www.bizjournals.com/denver/ news/2012/02/28/chevron-leaving-westernslope-project.html?page=all> 45 ‘Shell Abandons Western Slope Oil Shale Project’. trib.com. Accessed 26 February 2014. <http:// trib.com/business/energy/shell-abandonswestern-slope-oil-shale-project/article_ f8e1dee8-a04f-5444-ba86-9585b3340f74. html> 46 Op. Cit. [WEC 2013] 47 ‘Newman Government Approves Oil Shale Industry’ The Queensland Cabinet and Ministerial Directory. Accessed 26 February 2014. <http:// statements.qld.gov.au/Statement/2013/2/13/ newman-government-approves-oil-shaleindustry> 48 for example see: http://www.tarsandsresist.org/ stopenefit/

endsOFtheearth

the

a guide To unconventional fossil fuels 58

Corporate Watch

endsOFtheearth

the

what is it? Shale oil, or tight oil, is a type of crude oil that is found in low permeability rock formations such as shale or tight sandstone. The â&#x20AC;&#x2DC;tightâ&#x20AC;&#x2122; refers to the fact that the oil is tightly trapped in the rock, unlike conventional oil formations where the oil flows relatively easily. Recent technologies used for shale gas extraction, such as fracking and horizontal drilling, have made it economical to extract shale and tight oil.

how is it extracted?

shale Oil ( Tight oil)

CRUDE OIL FOUND IN SHALE OR OTHER ROCK WHERE IT IS TIGHTLY HELD IN PLACE AND DOES NOT FLOW EASILY. REQUIRES USE OF FRACKING WITH RISK OF WATER POLLUTION AND WORSENS CLIMATE CHANGE.

Shale oil has been known about for a long time, but has only been exploited on a large-scale in the last ten years or so. This has partly been driven by the development of two technologies: horizontal drilling, which opens up deposits inaccessible by conventional vertical drilling, and advanced hydraulic fracturing, or fracking. Fracking is used to free oil or gas trapped in rock by drilling into it and injecting pressurised fluid, creating cracks and releasing the oil or gas. The fracking fluid consists of water, sand and a variety of chemicals which are added to aid the extraction process e.g. by dissolving minerals, killing bacteria that might plug up the well, or reducing friction. The fracking process produces a large volume of waste water, containing a variety of contaminants both from the fracking fluid, and toxic and radioactive materials which are leached out of the rocks. In addition to fracking, acidisation is also sometimes used. This is where the well is pumped with acid to dissolve the rock that is obstructing the flow of oil.

Production from shale oil wells declines very quickly and so new wells must be drilled constantly. This process of continual drilling and fracking means that huge areas of land are covered with well pads where thousands of wells are drilled, with each well requiring millions of litres of water. Shale and tight oil deposits are also highly heterogenous, meaning there is substantial variation within the formation in the qualities of the rock and the oil it contains. Even adjacent wells can have very different production rates. The oil that is extracted from shale is very similar to crude oil from conventional sources and does not require further processing before it can be refined.

Marcellus Protest

"US House of Representatives Committee on Energy and Commerce report found 750 different chemicals had been used in fracking fluids, including many known human carcinogens and other toxic compounds "

Oil shale or shale oil?

Confusingly, ‘shale oil’ can refer oil extracted from shale rock using techniques such as fracking, or to the liquid fuel extracted from ‘oil shale’ by heating it (see separate Oil Shale factsheet). The first definition began being used when the US boom in shale gas resulted in shale formations also being exploited for oil. A great deal of confusion and disagreement persists, but many have started to use the term ‘tight oil’ to refer to oil extracted from shale formations using horizontal drilling and fracking. Even more confusingly, the term ‘oil shale’, which usually means the oily rock rich in kerogen (discussed in a separate factsheet), is also sometimes used to refer to shale formations which contain oil. Baffled? Well, you’re not alone!

Climate change Oil, whether from shale or conventional sources, is a fossil fuel and releases significant greenhouse gas emissions when burned. As long as energy demand increases additional sources of fossil fuels such as shale oil are likely to supplement rather than replace other existing ones such as coal.

If we are to reduce carbon emissions to anything like the levels required to maintain a reasonably habitable planet we must move away from all forms of fossil fuel as fast as possible. Measuring from the start of the industrial revolution (around 1750), a maximum of 500 Gigatonnes of carbon (GtC) can be emitted to the atmosphere while still avoiding most serious impacts and the risk of irreversible and uncontrollable changes to the climate.1 Between 1750 and now (2014), we have already emitted about 370 GtC leaving a limit of 130 GtC that could be further added.2 In order to stay within this limit we have to leave the vast majority of the remaining conventional oil, coal and gas in the ground. Estimates vary significantly, but remaining conventional coal reserves alone are well over 500GtC.3

CONVENTIONAL OIL ‘SAFE’ EMISSIONS LIMIT 130 GtC

325 GtC 42 GtC

SHALE OIL (not including tight oil)

CONVENTIONAL GAS

277 GtC

Exploiting the world’s shale oil resources would add around 42 GtC to the atmosphere.4 This is certainly an underestimate as it excludes Russia, which is estimated to have the largest shale oil reserves, much of the Middle East, and tight oil formations other than shale. The carbon locked up in shale and tight oil represents a huge source of emissions which, given the limits outlined above, we clearly cannot afford to add to the atmosphere.

Carbon Capture and Storage (CCS) Proponents of unconventional fossil fuels often argue that with CCS technologies, these new energy sources could be exploited at the same time as reducing GHG emissions. However, even if the huge problems with CCS technology are overcome (and this currently looking extremely unlikely), it would not change the fact that we need to move away from all forms of fossil fuel, conventional and unconventional, as soon as possible. In the most optimistic (and highly implausible) scenario, CCS could be used to reduce a small proportion of emissions from fossil fuels. In reality, the promise of CCS being implemented in the future is being used to allow the continued expansion of fossil fuel production, to prevent alternatives from being developed, and to deflect attention away from approaches which tackle the underlying systemic causes of climate change and other ecological crises. Ultimately CCS is a smokescreen, allowing the fossil fuel industry to continue profiting from the destruction of the environment. (see ‘Carbon Capture Storage’ factsheet for more information).

There has been some discussion about the possibility of using exhausted shale oil formations as a place for storing carbon dioxide. Injecting CO2 into fracked shale formations is also being considered as a way of both storing carbon and extracting more oil at the same time (so called Enhanced Oil Recovery – see ‘Other Unconventional Fossil Fuels’ factsheet). However, their viability as CO2 storage sites is questionable, and there are currently no shale oil sites being used to store CO2. In addition there are concerns that fracking may be compromising other potential CO2 storage sites, as the fracked shale formations are no longer impermeable and would therefore not keep CO2 trapped in the deep saline aquifers below them.5 In addition fracking, the underground injection of fracking waste water (see below), and even the injection of CO2 itself have been shown to cause earthquakes, which reveal a major flaw in CCS technology.6 7

wikipedia user: Joshua Doubek 2011

Fracking equipment

Other social and environmental issues Water use

The fracking process uses huge volumes of water, which becomes contaminated and cannot be returned to the water table. Depending on the characteristics of the well, the amount of water needed will be somewhere between about 3 million and 40 million litres.8 Sourcing water for fracking is a major problem. Because of transportation costs of bringing water from great distances, drillers in the US usually extract on-site water from nearby streams or underground water supplies. This puts pressure on local water resources which can lead to the worsening of droughts.9 In 2011, the U.S. Environmental Protection Agency estimated that 70 to 140 billion gallons (265 â&#x20AC;&#x201C; 531 billion litres) of water are used to fracture 35,000 wells in the United States each year.10

Water pollution

There has been a great deal of controversy over the chemicals contained in fracking fluids. In the US many companies have resisted revealing the recipes for their fracking mixes, claiming commercial confidentiality, or have adopted voluntary reporting measures in order to avoid stricter mandatory reporting requirements. Although the specific mix of chemicals used varies significantly, a US House of Representatives Committee on Energy and Commerce report found 750 different chemicals had been used in fracking fluids, including many known human carcinogens and other toxic compounds such as benzene and lead.11 Chemicals found to be most commonly used in fracking fluids such as methanol and isopropyl alcohol are also known air pollutants. A variety of chemicals are also added to the â&#x20AC;&#x2DC;mudsâ&#x20AC;&#x2122; used to drill well boreholes in order to reduce friction and increase the density of the fluid. Analysis of drilling mud has also found that they contain a number of toxic chemicals.12 13

Waste water

Shale oil extraction results in large volumes of waste water contaminated by fracking fluids and naturally occurring chemicals leached out of the rock. These can include dissolved solids (e.g., salts, barium, strontium), organic pollutants (e.g., benzene, toluene) and normally occurring radioactive material (NORM) such as the highly toxic Radium 226.14 The volumes of waster water generated and the kinds of contaminants it contains makes treating and disposing of it safely extremely challenging. Treatment of waste water is expensive and energy intensive, and still leaves substantial amounts of residual waste that then has to be disposed of. In addition the waste water from most sites would have to transported large distances to specialised treatment plants. In many cases, the waste water is re-injected back into the well, a process that has been shown to trigger earthquakes (see earthquake section below). In the US, there have been numerous cases of dumping of drilling cuttings and storage of waste water in open evaporation pits. In some cases waste water has even been disposed of by spreading it on roads under the guise of dust control or de-icing. Any accidental spillages could have serious environmental and human health consequences.

Human and animal health

Air Pollution

Air pollution at shale oil sites includes emissions from vehicle traffic, flaring and venting during drilling and completion (where gas is burned off or released to the atmosphere) and on-site machinery. Local air pollution from these sources is likely to be similar to that of shale gas extraction, including BTEX (benzene, toluene, ethylene and xylene), NOx (mono oxides of nitrogen), VOCs (volatile organic compounds), methane, ethane, sulphur dioxide, ozone and particulate matter.18

Industrialisation of countryside

As shale is impermeable the oil cannot easily flow through it and wells are needed wherever there is oil. This means that, unlike conventional oil, exploiting tight oil requires large numbers of wells to be be drilled. In the US tens of thousands of shale wells have been drilled leading to widespread industrialisation of the landscape in some states. It has been estimated that fracking requires 3,950 truck trips per well during early development of the well field.19 A single well pad could generate tens of thousands of truck journeys over its lifetime20 In addition to these increases in traffic for transportation of equipment, waste water and other materials the site itself creates significant noise, light pollution and direct impact on local wildlife and ecosystems.

Earthquakes

Underground fluid injection has been proven to cause earthquakes, and there are instances in the UK where fracking has been directly linked to small earthquakes.21 The injection of waste water from fracking back in to wells has also been shown to cause earthquakes.22 Although these earthquakes are usually relatively small, they can still cause minor structural damage and of particular concern is the possibility of damaging the well casings thus risking leakage. This did in fact happen after the earthquake at Cuadrilla’s site in Lancashire, UK. The company failed to report the damage and were later rebuked by the then UK energy minister, Charles Hendry, for not doing so.

Occasionally larger earthquakes are triggered. A 2013 study in prestigious journal Science linked a dramatic increase in seismic activity in the midwestern United States to the injection of waste water. It also catalogues the largest quake associated with waste water injection, which occurred in Prague on November 6, 2011. This measured 5.7 on the Richter scale, and destroyed fourteen homes, buckled a highway and injured two people.23 It should be noted that mining and conventional gas and oil extraction can also cause earthquakes.

Jobs

In practice much of the employment for oil shale developments are from outside the area in which the oil is extracted, and any boost to the local economy is relatively short lived as the industry moves on once wells are depleted. This undermines the argument, often used by those trying to promote the industry, that it will generate large-scale employment.

Economic issues

It is sometimes argued that shale oil can be used as a ‘bridging fuel’ in the short term while renewables are developed.24 However, estimates of reserves containing so many years’ worth of a country’s oil supply ignore the fact that it will take many years and thousands of wells drilled before production rates rise sufficiently to provide significant amounts of fuel. In addition, as the most productive shale plays and their ‘sweet spots’ are used up first, it becomes increasingly more expensive, both in terms of money and energy, to maintain production levels and there are various predictions that the shale oil boom in the US may be short lived.25 Concerns that the same kind of financial practices that led to the US housing bubble were used to provide investment (with the prospect of profitable merger and acquisition deals attracting the financial sector) are leading some to predict that the financial bubble behind the US shale boom will burst, possibly even risking another global economic crisis.26

Where and how Much?

According to the International Energy Agency,27 economically recoverable shale oil reserves around the world are as follows (in billions of barrels):

1 Russia 75 2 United States 48-58 3 China 30-35 4 Australia 27 5 Libya 26 6 Venezuela 13 7 Mexico 13 8 Pakistan 9 9 Canada 9 10 Indonesia 8

World Total 335-345 billion barrels

However, these figures are only for shale rather than other tight oil formations, and do not include most of the Middle East or Russia, which is estimated to have the largest shale oil resources in the world. In the United States, where the industry has undergone rapid development over the last ten years or so, the Bakken, Eagle Ford, Niobrara and Permian fields hold large resources of shale oil. At least 4,000 new shale oil wells were brought online in the United States in 2012.28 Canada also has an advanced shale oil industry. Other countries are also now beginning to consider exploiting their shale oil resources. In particular China,

credo.fracking 2012

Mexico and Argentina are aggressively pursuing shale oil extraction. China and Mexico have been hampered by lack of expertise and difficulties with national oil and gas companies. In Argentina the industry is set to rapidly expand with a deal between the national oil and gas company YPF S.A. and Chevron to produce both shale gas and shale oil from the Vaca Muerta (Dead Cow) basin, believed to hold as much as 23 billion barrels of oil equivalent.29 Russia has the largest shale oil resources, but seems unlikely to exploit them in the near future, as it still has large reserves of other, easier to extract fossil fuels.30

Bosc dâ&#x20AC;&#x2122;Anjou 2011

companies involved In the US multinational super-major corporations such as Exxon, Shell and Total do not dominate the shale oil industry. Mostly the work is undertaken instead by American companies, ranging in size from tiny start-ups to mid-sized companies worth tens of billions. Notable US shale companies include Chesapeake Energy, Continental Resources, Occidental Petroleum, Pioneer Natural Resources, Apache, Whiting Petroleum, Hess, EOG Resources, ConocoPhillips and Chesapeake. Often small companies carry out the initial exploratory drilling and testing in places where the industry is in a fledgling stage. If the process is proved economically viable these companies are often bought up by larger companies. In this way, the bigger companies are protected from any loses, should the testing prove unsuccessful.

Resistance There has been widespread resistance to fracking wherever it has been conducted. The most active national movement is in the US, and many have been inspired by the film Gaslands. Protests have spurred various countries, including France, Bulgaria, Romania and the Czech Republic to adopt moratoriums or outright bans on fracking.31 Protesters in a number of countries have used direct action and civil disobedience to oppose fracking. The ‘Lock the Gate’ movement in Australia saw environmental activists and local communities linking together, using blockades in their attempts to prevent exploration. In the village of Pungesti, in Romania, the local community have managed to remove and sabotage Chevron’s equipment to test fracking, despite receiving violent police repression for doing so. Similarly, indigenous Elsipogtog First Nation and other local residents blocked a road near Rexton, New Brunswick in Canada successfully preventing South Western Energy from carrying out tests at a potential fracking site. In the UK there have been community blockades of potential fracking sites, for instance at Balcombe in Sussex and Barton Moss in Lancashire.

For more information on resistance see the Corporate Watch website (corporatewatch.org/uff/resistance)

Endnotes 1 Hansen, James, Pushker Kharecha, Makiko Sato, Valerie MassonDelmotte, Frank Ackerman, David J. Beerling, Paul J. Hearty, et al. ‘Assessing “Dangerous Climate Change”: Required Reduction of Carbon Emissions to Protect Young People, Future Generations and Nature’. Edited by Juan A. Añel. PLoS ONE 8, no. 12 (3 December 2013): e81648. doi:10.1371/journal.pone.0081648. <http://www.plosone.org/article/ info%3Adoi%2F10.1371%2Fjournal.pone.0081648> 2 Ibid 3 ibid 4 See <www.corporatewatch.org/uff/carbonbudget> 5 Elliot, T. R., and M. A. Celia. ‘Potential Restrictions for CO2 Sequestration Sites Due to Shale and Tight Gas Production’. Environmental Science & Technology 46, no. 7 (3 April 2012): 4223–4227. doi:10.1021/es2040015. <http://pubs.acs.org/doi/abs/10.1021/es2040015> 6 Verdon, J. P., J.- M. Kendall, A. L. Stork, R. A. Chadwick, D. J. White, and R. C. Bissell. ‘Comparison of Geomechanical Deformation Induced by Megatonne-Scale CO2 Storage at Sleipner, Weyburn, and In Salah’. Proceedings of the National Academy of Sciences 110, no. 30 (8 July

2013): E2762–E2771. doi:10.1073/pnas.1302156110. <http://www.pnas. org/content/early/2013/07/03/1302156110.abstract> 7 Gan, W., and C. Frohlich. ‘Gas Injection May Have Triggered Earthquakes in the Cogdell Oil Field, Texas’. Proceedings of the National Academy of Sciences 110, no. 47 (4 November 2013): 18786–18791. doi:10.1073/pnas.1311316110. <http://www.pnas.org/content/ early/2013/10/31/1311316110> 8 Cooley, H, Donnelly, K. ‘Hydraulic Fracturing and Water Resources: Separating the Frack from the Fiction’. Pacific Institute (June 2012). <http://www.pacinst.org/wp-content/uploads/2013/02/full_ report35.pdf> 9 ‘A Texan tragedy: ample oil, no water’. Guardian website (Retrieved Feb 2014). <http://www.theguardian.com/environment/2013/aug/11/ texas-tragedy-ample-oil-no-water> 10 ‘Draft Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources’ US EPA. (Feb2011). <http://yosemite.epa.gov/sab/sabproduct.nsf/0/ D3483AB445AE61418525775900603E79/$File/Draft+Plan+to+Stu

dy+the+Potential+Impacts+of+Hydraulic+Fracturing+on+Drinking +Water+Resources-February+2011.pdf> 11 Chemicals used in hydraulic fracturing’. United States House of Representatives, Committee on Energy and Comerce Minority Staff (April 2011). <http://democrats.energycommerce.house. gov/sites/default/files/documents/Hydraulic-FracturingChemicals-2011-4-18.pdf> 12 ‘Toxic Chemicals in the Exploration and Production of Gas from Unconventional Sources’, National Toxics Network April (2013). <http:// www.ntn.org.au/wp/wp-content/uploads/2013/04/UCgas_ report-April-2013.pdf> 13 Fontenot, Brian E., Laura R. Hunt, Zacariah L. Hildenbrand, Doug D. Carlton Jr., Hyppolite Oka, Jayme L. Walton, Dan Hopkins, et al. ‘An Evaluation of Water Quality in Private Drinking Water Wells Near Natural Gas Extraction Sites in the Barnett Shale Formation’. Environmental Science & Technology 47, no. 17 (3 September 2013): 10032–10040. doi:10.1021/es4011724. <http://pubs.acs.org/doi/ abs/10.1021/es4011724> 14 Mielke E, Anadon LD, Narayanamurti V. ‘Water Consumption of Energy Resource Extraction, Processing, and Conversion’. Harvard Kennedy School, Belfer Center for Science and International Affairs. October 2010. <http://belfercenter.ksg.harvard.edu/files/ETIP-DP-2010-15final-4.pdf> 15 ‘Statement on Preliminary Findings from the Southwest Pennsylvania Environmental Health Project Study’. Press Release, Concerned Health Professionals of New York (27 Aug 2013) <http://concernedhealthny. org/statement-on-preliminary-findings-from-the-southwestpennsylvania-environmental-health-project-study/ > 16 Steinzor N, Septoff A. ‘Gas Patch Roulette, How Shale Gas Development Risks Public Health in Pennsylvania’. EarthWorks (Oct 2012). <http://www.earthworksaction.org/library/detail/ gas_patch_roulette_full_report#.UwzG187xHSe> 17 Slatin, Craig, and Charles Levenstein. ‘An Energy Policy That Provides Clean and Green Power’. NEW SOLUTIONS: A Journal of Environmental and Occupational Health Policy 23, no. 1 (1 January 2013): 1–5. doi:10.2190/NS.23.1.a. <http://www.prendergastlibrary. org/wp-content/uploads/2013/03/New-Solutions-23-1-Binder. pdf> 18 ‘Environmental water and air quality issues associated with shale gas development in the Northeast’. Environmental water and air quality working group, NYS Water Resources Institute, Cornell University. <http://wri.eas.cornell.edu/MSARC%20Env%20H2O%20Air%20 Group%20Revised%20071012.pdf>

20 ‘How many tanker trucks does it take to supply water to and remove waste from a horizontally drilled and hydrofracked wellsite’. unnaturalgas.org. <http://www.un-naturalgas.org/Rev%201%20 Truckloads+to+service+a+well+pad+-+DJC.pdf> 21 ‘Fracking and Earthquake Hazard’, British Geological Survey website (accessed Feb 2014). <http://earthquakes.bgs.ac.uk/research/ earthquake_hazard_shale_gas.html> 22 ‘Man-Made Earthquakes Update’ US geological survey website (Posted on 17 Jan, 2014). <http://www.usgs.gov/blogs/features/ usgs_top_story/man-made-earthquakes/> 23 Van der Elst, N. J., H. M. Savage, K. M. Keranen, and G. A. Abers. ‘Enhanced Remote Earthquake Triggering at Fluid-Injection Sites in the Midwestern United States’. Science 341, no. 6142 (11 July 2013): 164–167. doi:10.1126/science.1238948. <http://www.sciencemag.org/ content/341/6142/164.abstract> 24 Hughes D J. ‘Drill, Baby, Drill: Can Unconventional Fuels Usher in a New Era of Energy Abundance?’. Post Carbon Institute (Mar 2013). <http://www.postcarbon.org/drill-baby-drill/> 25 ibid 26 D Rogers. ‘Shale and wall street: was the decline in natural gas prices orchestrated?’. Energy Policy Forum (Feb 2013). <http://shalebubble. org/wall-street/> 27 ‘Technically Recoverable Shale Oil and Shale Gas Resources: An Assessment of 137 Shale Formations in 41 Countries Outside the United States’. U.S. Energy Information Administration (June 2013). <http:// www.eia.gov/analysis/studies/worldshalegas/pdf/overview.pdf> 28 Maugeri, Leonardo. ‘The Shale Oil Boom: a US Phenomenon’. Harvard University, Geopolitics of Energy Project, Belfer Center for Science and International Affairs, Discussion Paper 2013-05. <http://belfercenter. ksg.harvard.edu/files/draft-2.pdf> 29 ‘The Shale Oil Boom Is Going Global (Starting With This Huge Deal in Argentina)’. moneymorning.com. Accessed 8 March 2014. <http:// moneymorning.com/2013/08/13/the-shale-oil-boom-is-goingglobal-starting-with-this-huge-deal-in-argentina/> 30 ‘Tight Oil Developments in Russia’. Oxford Institute for Energy Studies. Accessed 8 March 2014. <http://www.oxfordenergy.org/2013/10/ tight-oil-developments-in-russia/> 31 For an update list of countries and states see here: <http://keeptapwatersafe.org/global-bans-on-fracking>

19 ‘Revised Draft SGEIS on the Oil, Gas and Solution Mining Regulatory Program (September 2011)’ New York State Department of Environmental Conservation (2011). <http://www.dec.ny.gov/ energy/75370.html>

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what is it? Converting coal to a liquid fuel is known as coal liquefaction and can be done in two ways; direct liquification, where the coal is dissolved at high temperature and pressure and then refined; and indirect liquification, where it is ‘gasified’ to form a ‘syngas’ (a mixture of hydrogen and carbon monoxide), which is then condensed to make a liquid fuel. Both processes require large amounts of energy.

Coalandgas to Liquids ( Synthetic Liquid Fuels)

TURNING COAL OR NATURAL GAS INTO LIQUID FUELS. PROCESS WASTES A LOT OF ENERGY AND HAS SERIOUS CONSEQUENCES FOR WATER RESOURCES AND CLIMATE CHANGE.

Converting gas to liquids (GTL) can also be done using two methods, via direct conversion, or indirectly by converting first to syngas then using the Fisher-Tropsh process. The Fischer-Tropsch process was invented in the 1920s by two German chemists. The process was used to produce liquid fuel from coal during the Second World War as Germany lacked access to sufficient crude oil. The advent of cheap oil led to the technology being largely abandoned. Several direct conversion processes have been developed but have proven uneconomical. So far only indirect methods have been commercialised.1 Coal to liquids (CTL) technology was re-invigorated in the 1950s in South Africa when the country was isolated during apartheid, and it remains the only country with significant commercial CTL operations. However, as most transport infrastructure around the world is dependent on liquid fuels (particularly cars and planes), and with conventional oil reserves slowly running low, there is huge demand for alternative liquid fuels. Converting coal and gas to liquid fuels also means some countries can use their own resources for transportation fuel instead of being dependent on foreign imports. Another attractive feature of synthetic liquid fuels from coal and gas is that they can be used to create various chemicals traditionally made from crude oil.

Coal can also be converted to gas (coal gasification) using a process which is also very energy inefficient. This can be carried out underground, which results in serious greenhouse gas emissions, groundwater pollution, and other environmental problems (see Underground Coal Gasification factsheet for more information) Note that GTL technologies are different from Liquefied Natural Gas (LNG). LNG is where natural gas is cooled and pressurised so it condenses into a liquid. It needs to be maintained at the correct temperatures and pressure in order to remain in liquid form. The processes for making and transporting LNG also use large amounts of energy.

Sasol 2013

"total 'lifecycle' greenhouse gas emissions for liquid fuel from coal is about double that of fuel from refining conventional crude oil"

The ORYX GTL plant, Qatar

Climate change

The energy used in converting coal and natural gas to liquid fuels means that they result in higher greenhouse gas emissions than fuel from conventional crude oil. The total ‘lifecycle’ greenhouse gas emissions (which includes all emissions generated in extraction, processing, transportation etc.) for liquid fuel from coal is about double that of fuel from refining conventional crude oil.2 3 GTL fuels have been estimated to have about 30% higher lifecycle greenhouse gas emissions than fuel from refining conventional crude oil.4 5 The conversion process is usually powered by electricity, so greenhouse gas emissions from coal and gas to liquid technologies depend on how this electricity is generated. However, even if renewable sources are used, the process still wastes a lot of energy that could have been used for other purposes.

If we are to reduce carbon emissions to anything like the levels required to maintain a reasonably habitable planet we must move away from all forms of fossil fuel as fast as possible. Measuring from the start of the industrial revolution (around 1750), a maximum of 500 Gigatonnes of carbon (GtC) can be emitted to the atmosphere while still avoiding most serious impacts and the risk of irreversible and uncontrollable changes to the climate.6 Between 1750 and now (2014), we have already emitted about 370 GtC leaving a limit of 130 GtC that could be further added.7 In order to stay within this limit we have to leave the vast majority of the remaining conventional oil, coal and gas in the ground. Estimates vary significantly, but remaining conventional coal reserves alone are well over 500GT of carbon.8

It has been estimated that using a quarter of the world’s coal as CTL would increase atmospheric CO2 concentrations by approximately 300 parts per million (ppm) 9 which equates to 636GtC.10 This is a huge amount, far more than would result from burning all of the world’s conventional petroleum,11 and although there are disagreements about coal reserves and resources, with some claiming estimates are far too high, there is certainly enough conventional coal to go well beyond the carbon limit mentioned in the box above. The additional emissions that would result from developing coal and gas to liquid technologies only exacerbate the problem.

Carbon Capture and Storage (CCS) It has been estimated that CCS could only reduce CTL carbon emissions by a maximum of 50%, so they would still have high greenhouse gas emissions.12 There are also numerous critical problems with CCS itself, which remains a largely unproven technology, especially at the enormous scale that would be required (see CCS factsheet). Proponents of unconventional fossil fuels often argue that with CCS technologies, these new energy sources could be exploited at the same time as reducing GHG emissions. However, even if the huge problems with CCS technology are overcome (and this currently looking extremely unlikely), it would not change the fact that we need to move away from

all forms of fossil fuel, conventional and unconventional, as soon as possible. In the most optimistic (and highly implausible) scenario, CCS could be used to reduce a small proportion of emissions from fossil fuels. In reality, the promise of CCS being implemented in the future is being used to allow the continued expansion of fossil fuel production, to prevent alternatives from being developed, and to deflect attention away from approaches which tackle the underlying systemic causes of climate change and other ecological crises. Ultimately CCS is a smokescreen, allowing the fossil fuel industry to continue profiting from the destruction of the environment. (see ‘Carbon Capture Storage’ factsheet for more information).

Other social and environmental issues Converting CTL fuel consumes large amounts of water and creates substantial amounts of contaminated waste water and solid waste.13 A Greenpeace investigation into a Coal to Liquids plant in Ordos, China run by the company Shenhua, revealed how the project required 10 tons of fresh water to produce just 1 ton of end-product, while at the same time producing 9 tons of carbon dioxide and 4.8 tons of waste water (1 ton = 0.9 tonnes).14 The investigation also found a dramatic effect on local ground water levels, seriously impacting local farmers. Despite claims by the company of a “zero-discharge system” and that “the actual number of pollutants entering the water cycle is zero”, independent analysis of waste water leaking into the environment found high levels of harmful substances including carcinogens.15

A further problem with coal and gas to liquid technologies is that they require increased coal mining and natural gas extraction, with all the associated social and environmental problems.

The Sasol coal-to-liquids plant in Secunda

Remigiusz Józefowicz 2007

Where, how Much and Who?

The South African energy and chemical company Sasol has a number of CTL and GTL projects around the world. As well as plants in South Africa (where CTL provides about 30% of the country’s gasoline and diesel),16 there are coal or gas to liquid projects in the US, Qatar and Uzbekistan. China is rapidly developing its coal to liquids capacity,17 and has the largest CTL plant in the world in Inner Mongolia, run by state coal company Shenhua.18 Other companies with significant interest in CTL/GTL technologies include Shell, Exxon, Statoil, Rentech and Syntroleum19. Shell is currently building the largest GTL plant in the world, in Ras Laffan, Qatar.20 Ruins of a German synthetic petrol plant in Police, Poland

For information on resistance see the Corporate Watch website (corporatewatch.org/uff/resistance)

Endnotes 1 See here for examples: <http://www.chemlink.com.au/gtl.htm> 2 Jeff Logan and John Venezia.’Coal to Liquids, Climate Change, and Energy Security’. World Resource Institute, May 2007. < [http://www. rand.org/content/dam/rand/pubs/monographs/2008/RAND_ MG754.pdf,> 3 Farrell, A E, and A R Brandt. ‘Risks of the Oil Transition’. Environmental Research Letters 1, no. 1 (October 2006): 014004. doi:10.1088/17489326/1/1/014004.<http://iopscience.iop.org/1748-9326/1/1/014004/> 4 Ou, Xunmin, and Xiliang Zhang. ‘Life-Cycle Analyses of Energy Consumption and GHG Emissions of Natural Gas-Based Alternative Vehicle Fuels in China’. Journal of Energy (2013): 1–8. doi:10.1155/2013/268263. <http://www.hindawi.com/journals/ jen/2013/268263/> 5 Op cit (Farrell et al 2006) 6 Hansen, James, Pushker Kharecha, Makiko Sato, Valerie MassonDelmotte, Frank Ackerman, David J. Beerling, Paul J. Hearty, et al. ‘Assessing “Dangerous Climate Change”: Required Reduction of Carbon Emissions to Protect Young People, Future Generations and Nature’. Edited by Juan A. Añel. PLoS ONE 8, no. 12 (3 December 2013): e81648. doi:10.1371/journal.pone.0081648. <http://www.plosone.org/article/ info%3Adoi%2F10.1371%2Fjournal.pone.0081648> 7 Ibid 8 Ibid 9 Op. Cit. (Farrell et al 2006) 10 1ppm is roughly equivalent to 2.12 Gt. Op. Cit. (Hansen et al 2013)

11 Op cit (Farrell et al 2006) 12 Ibid 13 Sonja Nowakowski ‘Coal to Liquids Water Usage’. November 8 ETIC meeting (2007) <http://leg.mt.gov/content/committees/ interim/2007_2008/energy_telecom/assigned_studies/ coal2liquidpage/Coal2liquidone.pdf> 14 ‘Thirsty Coal 2, Shenhua’s water grab’ Greenpeace East Asia (Jul 2013) <http://www.greenpeace.org/eastasia/Global/eastasia/ publications/reports/climate-energy/2013/Thirsty%20Coal%202. pdf> 15 Ibid 16 ‘Coal to Liquid, Liquid Fuels’. World Coal Association. Accessed 8 March 2014. <http://www.worldcoal.org/coal/uses-of-coal/ coal-to-liquids> 17 ‘Coal Emerges as Cinderella at China’s Energy Ball’. FT.com. Accessed 8 March 2014. <http://www.ft.com/cms/s/2/b3dff99a-b2a0-11e2a388-00144feabdc0.html#axzz2kX8ZWWmy> 18 ‘Institute for Energy Research’ China’s Coal to Liquids Program Not Allowed in the United States. Accessed 8 March 2014. <http://www. instituteforenergyresearch.org/2011/06/28/china%E2%80%99scoal-to-liquids-program-not-allowed-in-the-united-states/#_ edn5> 19 ‘Oil Shale: A Fuel Lifeline’. Oil Shale Information Centre. <www.oilshale.co.uk/oilshaleguide.pdf > 20 ‘Pearl GTL - Qatar’. Shell.com. Accessed 8 March 2014. <http://www.shell.com.qa/en/products-services/pearl.html>

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what is it? Methane hydrate, also known as methane clathrate or â&#x20AC;&#x153;fire iceâ&#x20AC;?, occurs when methane molecules are trapped in an ice-like form of water. At certain temperatures and pressures the water molecules surround the methane in a cage which forms a slushy icy substance. A diagram of methane hydrate molecular structure

gas molecule

Methane Hidrates METHANE (NATURAL GAS) AND WATER TRAPPED AS AN ICY SUBSTANCE UNDER THE SEA FLOOR AND IN THE ARCTIC PERMAFROST. VAST STORE OF CARBON, WHICH IF RELEASED WOULD HAVE DEVASTATING CONSEQUENCES FOR CLIMATE CHANGE.

water molecule There are huge amounts of methane hydrate around the world, mostly occurring on and under the sea floor on the continental shelves, with smaller amounts found in other marine and deep fresh water lake locations and also on-land, underground in Arctic regions. Methane hydrates may also trap large methane deposits (in gas form) beneath them.1 Methane hydrate deposits can be either biogenic in origin, created by microbes in sediment, or thermogenic, created by geological heating of organic material at great depths. The characteristics of the deposits vary significantly due to differences in origin, their structure, temperature and pressure conditions, and their association with different geological formations.

Methane hydrates were first created in labs in the 1800s and were found forming in and clogging up natural gas pipelines in the 1930s. It wasn’t until the 1960s that they were found to occur naturally, and later still, in the 1980s, that people started to consider methane hydrates as a potential fuel source. However, methane hydrates have since remained ‘a fuel of the future’ due to serious technical obstacles to their extraction. As well as a potential fuel source, methane hydrates are also of interest due to their role in the global climate system (see climate change section below). Methane hydrate resources are extremely large. While estimates still vary significantly,2 the total amount in the oceans is likely to be around 1000 to 5000 trillion cubic metres (about 500–2500 gigatonnes of carbon (GtC)),3 with the amount in Arctic regions around 400 GtC.4 An amount similar to that in the Arctic may also occur in the Antarctic.5 Another recent study made a conservative estimate of the total amount of carbon in methane hydrates as 1800 GtC.6

Some estimates are much higher, putting the total carbon in methane hydrates as similar to or even more than the total carbon in all the other fossil fuels in the world combined (about 5000 gigatonnes).7 8 9 10 A large proportion of the world’s methane hydrates are found at depths of several hundreds of metres below the sea floor in very fine-grained marine sediments. They are essentially mixed with mud, making their recovery and exploitation very difficult, and there are no current proposals for technologies to recover these deposits. The first assessments of potential technically-recoverable resources give an estimate of around 300 trillion cubic metres or around 150 GtC).11 This is still a very large amount, much more than the total estimated global natural gas reserves (around 190 trillion cubic metres).12 If methane hydrates are exploited as a fuel source it would add a massive amount of carbon to the atmosphere, with dire consequences for the climate. However, despite recent completed test projects, some predict that methane hydrates will never be an economical fuel source.

"there are huge amounts of methane hydrates around the world conceivably containing as much as or even more carbon than in all other fossil fuels combined"

Japanese drilling ship used for methane hydrate extraction

Wikimedia user: Gleam 2005

how is it extracted? As the methane is trapped in the ice-like hydrate structure, the gas cannot be extracted using the same methods as conventional natural gas extraction. Also, if methane hydrates are removed from their natural environment the change in pressure and temperature makes them unstable and releases the methane. These factors, combined with the fact that they are mainly found below the sea bed on the continental shelf (or underground on-land in polar regions), pose significant problems for developing methane hydrates as a fuel source. Extraction is still at the experimental stage. However, there are a number of methods that have been suggested and several test projects have been carried out. One proposed method involves pumping hot water down a drill hole to melt the hydrates and release the methane which could then be pumped away in pipelines along the sea bed.13 One drawback with this method is the large amount of energy required to heat the hydrates. A de-pressurisation method has been experimented with which involves drilling into the deposit, and pumping out excess fluid. This lowers the pressure and releases the methane. This method had some success at the Mallik Gas Hydrate Research Well in northern Canada,14 and was used in Japan’s recent test project, the first to successfully extract methane hydrates from marine deposits (see below).

There are also proposed techniques that involve using a combination of thermal and de-pressurisation methods. A further method, inhibitor injection, involves injecting chemicals (usually salts, alcohols or glycols) that lower the temperature at which the hydrates are stable, and thus release the methane. These inhibitors are regularly used to prevent methane hydrates forming in pipelines and during undersea drilling operations. Another method involves injecting CO2 into the deposit. The idea is for the CO2 to replace the methane in the hydrate and become trapped there instead.15 This is intended as a way of extracting methane from the hydrates and storing the CO2 at the same time. The replacement of methane with CO2 in hydrates has been demonstrated experimentally,16 and a test project using this method in Prudhoe Bay, on Alaska’s North Slope has been carried out.17 The project, a collaboration between Conoco Philips, the US Department of Energy (US DOE) and Japan Oil, Gas and Metals National Corporation (JOGMEC), claims to have successfully injected a CO2 /Nitrogen mixture and extracted methane (along with large volumes of water, mud, Nitrogen and CO2 ). However, a US Department of Energy spokesperson said, “Ongoing analysis of the extensive datasets acquired at the field site will be needed to determine the efficiency of simultaneous CO2 storage in the reservoirs”.18 The Prudhoe Bay test

is a very long way from proving the feasibility of this method and it is still far from certain whether or not this will be viable technology, especially at the scale and efficiencies that would be required for both commercial methane extraction and CO2 storage.

of deposit. The vast majority of the world’s methane hydrates are found in low concentration marine deposits, where the hydrates are spread over wide areas and mixed with lots of mud. There are currently no proposed technologies for extracting methane from these ‘low grade’ sources.

It has been suggested that methane hydrates could be mined from the sea-floor and transported to the surface in pressurised containers, but the technical difficulties mean this is highly unlikely in the near future.

Methane hydrate resource triangle

Higher

Arctic sands Marine sands

Vent site related massive hydrate Marine fine-grained

Gas hydrate resource triangle Volume of resource

Climate change Despite the variation in global resource estimates, it is clear that there are huge amounts of methane hydrates around the world, representing a vast store of carbon, conceivably as much as or even more than in all other fossil fuels combined. If we are to reduce carbon emissions to anything like the levels required to maintain a reasonably habitable planet we must move away from all forms of fossil fuel, including methane hydrates, as fast as possible. CONVENTIONAL OIL ‘SAFE’ EMISSIONS LIMIT 130 GtC

325 GtC METHANE HYDRATES

163 GtC

Most methane hydrate resources are in low concentration deposits, making them difficult to extract.

Non-sandstone marine reservoirs, including fractured fine-grained

Resource concentration Lower

Despite the completion of the recent test project in Japan (see below), there remain significant obstacles to methane hydrate extraction on a commercial scale. As well as difficulties with extraction technologies, a potential problem is in the dispersal of the deposits, if they are too widely distributed it may be uneconomical to extract them. In addition the variation in the types of deposits (the kind of structures they have, the geological formations they are associated with etc.) could make it difficult to find commercially exploitable deposits and extraction technologies may only be appropriate for very specific types

The extreme difficulties with methane hydrate extraction have led some to conclude it will never be a viable fuels source.

CONVENTIONAL GAS

277 GtC

If we are to reduce carbon emissions to anything like the levels required to maintain a reasonably habitable planet we must move away from all forms of fossil fuel as fast as possible. Measuring from the start of the industrial revolution (around 1750), a maximum of 500 Gigatonnes of carbon (GtC) can be emitted to the atmosphere while still avoiding most serious impacts and the risk of irreversible and uncontrollable changes to the climate.19 Between 1750 and now (2014), we have already emitted about 370 GtC leaving a limit of 130 GtC that could be further added.20 In order to stay within this limit we have to leave the vast majority of the remaining conventional oil, coal and gas in the ground. Estimates vary significantly, but remaining conventional coal reserves alone are well over 500 GtC.21

Exploiting the estimated 163 GtC22 of extractable methane hydrates is absolutely incompatible with staying below the limit outlined above.

Methane hydrates and the climate

As well as being a possible form of unconventional fossil fuel, methane hydrates are of interest to climate scientists from the perspective of the climate system. It has been suggested that methane hydrates might induce a positive feedback mechanisms (a process in which an initial change will bring about an additional change in the same direction i.e. A produces more of B which in turn produces more of A). First, rising temperatures warm and change the pressures surrounding the hydrates, releasing some of the methane they contain to the atmosphere. As methane is a powerful greenhouse gas, it increases temperatures further, which further warms the hydrates releasing yet more methane, which then further warms the atmosphere. This is

referred to as the “clathrate gun” hypothesis. It has been suggested that it may have been the cause of periods of rapid warming in earth’s history and could be an immediate cause for concern if it is triggered by man-made climate change. However, while there remains debate among scientists over the timescales at which methane release would occur, it is likely to be a matter of centuries rather than decades.23 There are also concerns that hydrate extraction may result in the sudden release of large amounts of methane, either as a result of sea-floor destabilisation causing landslides, or uncontrolled destabilisation of the hydrates, where extracting methane changes the pressure in the surrounding hydrates, leading to a chain reaction spreading throughout the deposit.

A method of extraction that replaces methane in the hydrates with carbon dioxide as a means of CCS has been experimented with in labs and at a test site, but it is far from clear that this could ever be a viable technology (see ‘extraction methods’ above). The long-term (and even short-term) instability of CO2 hydrates, the substance that would replace the methane hydrates, raises serious concerns about the reliability of using them as a trapping mechanism for holding captured CO2.24

Other social and environmental issues The methane hydrates in marine sediments beneath the seafloor are often thought to be in a “precarious” state. Methane hydrate is a very low-density compound and in principle would float in sea-water if not held in place by the weight of the overlying sediments. The presence of methane gas bubbles sometimes held beneath the methane hydrate layer makes the situation even more unstable. If the mixture of solids (sediment and methane hydrate), methane gas bubbles and sea-water becomes unstable and starts to rise up the gas bubbles expand, separating the sediment further, causing it to rise even faster. This could happen in response to a small temperature increase, a physical shift or settlement of the marine sediments. Methane naturally and regularly escapes from the sediments into the ocean in this way, leaving behind explosion craters on the seafloor called pockmarks.25 However, there are also examples where the methane hydrate instability described above is believed to have caused or contributed to large under water landslides. The ‘Storegga Submarine Landslide’ is generally believed to be an instance of this. The slide occurred 8000 years ago off the Norwegian coast. It caused massive amounts of sediment to slide down the continental slope, creating an enormous tsunami, perhaps 25m high, that struck

Where, how Much and Who? The vast majority of the world’s methane hydrates are found on the edge of the continental shelf, beneath the sea bed, mixed with fine-grained mud. Methane hydrates also occur in much smaller amounts in other marine locations (including the floor of the Caspian Sea and the Gulf of Mexico) and onshore, in and beneath the polar permafrost. It is most likely that deposits in the permafrost and marine deposits in sand (rather than mud) on the sea bed will be targeted first as they are significantly easier to extract.

Norway and Scotland. The landslide may have been caused by rapid decomposition of hydrates due to temperature and pressure changes and the end of the last ice age.26 It is not clear how much of a risk methane hydrate extraction would pose in terms of causing landslides and tsunamis, but it is obviously a cause for concern. Geir Erlsand from the University of Bergen in Norway warned, “Extraction increases the risk of large-scale collapses, which might have catastrophic consequences”.27 Even small scale pressure changes or subsidence could cause problems at extraction sites, potentially leading to methane being lost to the sea and atmosphere.28 If methane hydrate extraction starts to take place on a significant scale, it would involve the deployment of large amounts of industrial infrastructure, which could have a serious impact on marine and Arctic environments. There are also unique ecosystems on and below the sea floor that include organisms which depend on methane hydrates as a food source. The race to secure methane hydrate resources may also lead to conflict between countries, particularly as some deposits are found in disputed territories such as the South and East China Seas.

Several countries have active methane hydrate research programmes or are investigating the possibilities of extraction, including the US, Japan, China, Germany, Norway, India, South Korea, the UK,Taiwan, New Zealand, Brazil and Chile. Notable Research groups/projects include: - The National Methane Hydrates R&D Program, US Department of Energy.29 - Japan’s national methane hydrates R&D program (MH21). The Ministry of Economy, Trade and Industry (METI) is funding the JOGMEC methane hydrate research (see below).30

- German Submarine Gas Hydrate Reservoirs (SUGAR) project. A project to develop marine methane hydrates as an unconventional fuel and to combine their production with CO2 sequestration.31 - Chinese Ministry of Land and Resources (MLR) methane hydrate research project, collaborating with Shenhua Energy.32 - India’s National Gas Hydrate Programme (NGHP), a collaboration between the Indian Government, national energy companies and research institutions.33 - The Gulf of Mexico Joint Industry Project (JIP) is a cooperative research program between the US DOE and an industry consortium led by Chevron. It aims to investigate methane hydrate accumulations in the deep water Gulf of Mexico.34 - United Nations Environment Program, Global Outlook on Methane Gas Hydrates, evaluating methane hydrate as a potential energy resource for future development.35 - Canada recently ended its 15 year research programme saying that methane hydrate research was “not a current priority” (probably due to existing shale and tar sands projects).36 Around the world a number of test projects have either been completed or are currently being carried out, usually involving a collaboration of national governments, research institutes, and energy companies. These include:

1 Kvenvolden, K. ‘A review of the geochemistry of methane in natural gas hydrate’. Organic Geochemistry 23 (11–12): 997–1008 (1995) 2 Ruppel, C.D. ‘Methane Hydrates and Contemporary Climate Change’. Nature Education Knowledge 3(10):29 (2011). <http://www.nature.com/scitable/knowledge/library/ methane-hydrates-and-contemporary-climate-change-24314790> 3 Milkov, Alexei V. ‘Global Estimates of Hydrate-Bound Gas in Marine Sediments: How Much Is Really out There?’ Earth-Science Reviews 66, no. 3–4 (August 2004): 183–197. doi:10.1016/j.earscirev.2003.11.002. <http://www.sciencedirect.com/science/article/pii/ S0012825203001296> 4 MacDonald, G. J. ‘Role of methane clathrates in past and future climates’. Climatic Change, 16, 247-281. (1990) 5 Wadham, J. L., S. Arndt, S. Tulaczyk, M. Stibal, M. Tranter, J. Telling, G. P. Lis, et al. ‘Potential Methane Reservoirs beneath Antarctica’. Nature 488, no. 7413 (29 August 2012): 633–637. doi:10.1038/nature11374. <http://

- Completion of the first off shore extraction test project in March 2013 by the national resource company, Japan Oil, Gas and Metals National Corporation (JOGMEC). The test took place in the Nankai Trough off the coast of Japan using the specialised drilling ship the Chikyu Hakken. Extraction used a depressurisation method and successfully produced an average of 20,000 cubic metres of gas per day over six days. On the sixth day sand clogged a pump and extraction had to be halted early. - CO2 /methane exchange project in Prudhoe Bay, on Alaska’s North Slope (mentioned in extraction methods section above). The project, completed in 2012 was a collaboration between Conoco Philips, the US Department of Energy (US DOE) and Japan Oil, Gas and Metals National Corporation (JOGMEC).37 - An international consortium, led by Japan and Canada and including the US, conducted short-duration production testing in 2002 at the Mallik site in Beaufort Sea, Canada. It demonstrated, for the first time, that methane could be produced from hydrate. - There are also various other current and past US DOE methane hydrate projects.38 Notable companies involved in methane hydrate extraction include BP, ConocoPhillips, Anadarko Petroleum, Chevron, Shenhua Energy, Japan Oil, Gas and Metals National Corp. (JOGMEC) and Mitsui Engineering and Shipbuilding Co.

www.nature.com/nature/journal/v488/n7413/abs/nature11374. html> 6 Boswell, R. & Collett, T. S. ‘Current perspectives on gas hydrate resources’. Energy and Environmental Science 4, 1206-1215 (2011). 7 Buffett, Bruce, and David Archer. ‘Global Inventory of Methane Clathrate: Sensitivity to Changes in the Deep Ocean’. Earth and Planetary Science Letters 227, no. 3–4 (November 2004): 185–199. doi:10.1016/j. epsl.2004.09.005. <geosci.uchicago.edu/~archer/reprints/ buffett.2004.clathrates.pdf> 8 Kvenvolden, Keith A. ‘Methane Hydrate — A Major Reservoir of Carbon in the Shallow Geosphere?’ Chemical Geology 71, no. 1–3 (December 1988): 41–51. doi:10.1016/0009-2541(88)90104-0. <http://www.sciencedirect. com/science/article/pii/0009254188901040> 9 MacDonald, G J. ‘The Future of Methane as an Energy Resource’. Annual Review of Energy 15, no. 1 (November 1990): 53–83. doi:10.1146/ annurev.eg.15.110190.000413. <http://www.annualreviews.org/doi/ abs/10.1146%2Fannurev.eg.15.110190.000413>

10 Gornitz, V., and I. Fung. ‘Potential Distribution of Methane Hydrates in the World’s Oceans’. Global Biogeochemical Cycles 8, no. 3 (September 1994): 335–347. doi:10.1029/94GB00766. <http://www.sciencedirect. com/science/article/pii/0009254188901040> 11 Boswell, Ray, and Timothy S. Collett. ‘Current Perspectives on Gas Hydrate Resources’. Energy & Environmental Science 4, no. 4 (2011): 1206. doi:10.1039/c0ee00203h. <http://pubs.rsc.org/en/content/ articlelanding/2011/ee/c0ee00203h#!divAbstract> 12 ‘Survey of Energy Resources: Focus on Shale Gas’. World Energy Council (2010). <www.worldenergy.org/documents/shalegasreport.pdf> 13 ‘Gas Hydrate Extraction from Marine Sediments by Heat Stimulation Method’. The Proceedings of the Fourteenth International Offshore and Polar Engineering Conference (2004). <https://www.isope.org/ publications/proceedings/ISOPE/ISOPE%202004/volume1/2004jsc-140.pdf> 14 ‘Analysis of 2007 and 2008 gas hydrate production tests on the Aurora/ JOGMEC/NRCan Mallik 2L-38 well through numerical simulation’. Natural Resources Canada (20012). <http://www.pet.hw.ac.uk/icgh7/ papers/icgh2011Final00449.pdf> 15 B. P. McGrail, T. Zhu, R. B. Hunter, M. D. White, S. L. Patil, and A. S. Kulkarni. ‘A New Method for Enhanced Production of Gas Hydrates with CO2’. AAPG Hedberg Conference (Vancouver): Gas Hydrates: Energy Resource Potential and Associated Geologic Hazards (2004) <http://www.searchanddiscovery.com/documents/ abstracts/2004hedberg_vancouver/extended/mcgrail/mcgrail.htm> 16 Ibid 17 ‘DOE/NETL Methane Hydrate Projects’. National Energy Technology Laboratory (NETL), U.S. Department of Energy (DOE). Accessed 9 March 2014. <http://www.netl.doe.gov/research/oil-and-gas/projectsummaries/methane-hydrate> . 18 ‘ConocoPhillips Group Evaluating Alaska Hydrate Test’. Oil & Gas Journal. Accessed 9 March 2014. <http://www.ogj.com/articles/2012/05/ conocophillips-group-evaluating-alaska-hydrate-test.html> 19 Hansen, James, Pushker Kharecha, Makiko Sato, Valerie MassonDelmotte, Frank Ackerman, David J. Beerling, Paul J. Hearty, et al. ‘Assessing “Dangerous Climate Change”: Required Reduction of Carbon Emissions to Protect Young People, Future Generations and Nature’. Edited by Juan A. Añel. PLoS ONE 8, no. 12 (3 December 2013): e81648. doi:10.1371/journal.pone.0081648. <http://www.plosone.org/article/ info%3Adoi%2F10.1371%2Fjournal.pone.0081648> 20 Ibid 21 Ibid

22 See <www.corporatewatch.org/uff/carbonbudget> 23 Op. Cit. (Ruppel 2011) 24 Brewer, P. G. ‘Direct Experiments on the Ocean Disposal of Fossil Fuel CO2’. Science 284, no. 5416 (7 May 1999): 943–945. doi:10.1126/ science.284.5416.943. 25 Hill, Jenna C. ‘Large-Scale Elongated Gas Blowouts along the U.S. Atlantic Margin’. Journal of Geophysical Research 109, no. B9 (2004). doi:10.1029/2004JB002969. <http://onlinelibrary.wiley.com/ doi/10.1029/2004JB002969/abstract> 26 Maslin, M., M. Owen, R. Betts, S. Day, T. Dunkley Jones, and A. Ridgwell. ‘Gas Hydrates: Past and Future Geohazard?’ Philosophical Transactions of the Royal Society A: Mathematical, Physical and Engineering Sciences 368, no. 1919 (19 April 2010): 2369–2393. doi:10.1098/rsta.2010.0065. <http://rsta.royalsocietypublishing.org/content/368/1919/2369. long> 27 ‘Tundra Gas Inc.’ Methane Hydrate. Accessed 9 March 2014. <http:// tundragas.com//methane-hydrate.html> 28 Rutqvist, J. and G. Moridis. ‘Evaluation of geohazards of in situ gas hydrates related to oil and gas operations’. Fire in the Ice, US Department of Energy, Office of Fossil Energy, National Energy Technology Laboratory, 10(2), 1-4 (2010) 29 <http://www.netl.doe.gov/research/oil-and-gas/methane-hydrates> 30 <http://www.mh21japan.gr.jp/english/> 31 <http://www.geomar.de/en/research/fb2/fb2-mg/projects/ sugar-2-phase/> 32 ‘China Hypes Methane Hydrates despite Industry Ambivalence’ Progressivechina. Accessed 9 March 2014. <http://progressivechina. com/china-hypes-methane-hydrates-despite-industryambivalence/4421> 33 <http://oidb.gov.in/index3.asp?sslid=257&subsublinkid=69> 34 Op. Cit. ‘DOE/NETL Methane Hydrate Projects’ 35 <http://www.methanegashydrates.org/> 36 ‘Canada Drops out of Race to Tap Methane Hydrates’. Technology & Science - CBC News. Accessed 9 March 2014. <http://www.cbc.ca/ news/technology/canada-drops-out-of-race-to-tap-methanehydrates-1.1358966?cmp=rss> 37 Op. Cit. ‘DOE/NETL Methane Hydrate Projects’ 38 Op. Cit. ‘DOE/NETL Methane Hydrate Projects’

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Other

Unconventional

FossilFuels

BELOW IS A QUICK SUMMARY OF SOME OF THE LESS WELL KNOWN UNCONVENTIONAL FOSSIL FUELS: Enhanced oil and gas recovery (EOR/EGR); extra-heavy crude; deep water oil and gas; Arctic oil and gas; and geopressurised zones.

Enhanced Oil and Gas Recovery (EOR/EGR)

When conventional oil and gas deposits are exploited, only a certain amount can be extracted using drilling. A large percentage of the oil or gas remains underground. Enhanced oil and gas recovery techniques can be used to increase the amount recovered from the deposit. The terms enhanced oil or gas recovery are also used to refer to methods of extraction (such as fracking or steam assisted gravity drainage) of unconventional fossil fuel deposits (such as shale gas and tar sands).

Methods for increasing the amount of oil or gas recovered from conventional deposits include the injection of gases such as CO2, nitrogen or natural gas, the injection of other chemicals to aid the flow of oil, heating the deposit, or injecting water. Microbial EOR involves injecting microbes into a deposit (or stimulating existing ones) which then enhance oil recovery by producing carbon dioxide, partially digesting the oil and/or plugging up pores in the rock. EOR/EGR increases the amount of fossil fuel that can be recovered, and while this may be good news for oil companies its very bad news for the climate.

As EOR/EGR techniques require more energy, the resulting fuels have significantly higher lifecycle greenhouse gas emissions than conventionally produced oil and gas.1 EOR is sometimes used in conjunction with Carbon Capture Storage technologies (CCS – see separate CCS factsheet). CCS involves pumping CO2 into underground storage sites, as a way of reducing emissions. However, the injection of CO2 into oil fields is primarily about extracting more oil rather than a way of addressing climate change.2 In addition the injection of CO2 for EOR has been linked to earthquakes, which undermines the concept of CCS technologies in general, as earthquakes are likely to create fractures allowing the CO2 to escape to the atmosphere.3 Many EOR methods also produce large amounts of brine (salty waste water), which can contain toxic and radioactive substances leached from the rock. Over the next decade or so more fossil fuels are likely to be produced using EOR than through other unconventional methods. This is because the infrastructure is already there and EOR has better financial returns than other unconventional forms of fossil fuel production.

Extra-heavy crude

Extra heavy crude is is a dense, thick form of oil. It is similar to bitumen (see Tar Sands factsheet), but flows slightly more easily. Around 90% of the world’s proven extra-heavy crude reserves are in Venezuela,4 mainly in the Orinoco Belt. Venezuela’s heavy and extra-heavy crude reserves are estimated at 220 billion barrels (220 Gb), giving it total oil reserves of 296 Gb, more than Saudi Arabia (265 Gb).

Mainly due to the huge investment and infrastructure required, as well as technical and political obstacles, Venezuela’s extra-heavy crude resources remain largely unexploited. However, they have enormous value and are seen as vital to the future economy of Venezuela. The government and state owned oil company Petroleos de Venezuela have plans to expand production. Heavy oil/crude is also sometimes included as an unconventional fossil fuel. It is more dense and viscous than conventional crude, but less so than extra-heavy crude. Exploiting the world’s heavy and extra-heavy crude resources would add an estimated 81 Gigatonnes of carbon to the atmosphere.6

Deep water oil and gas

Definitions vary as to what constitutes ‘deep water’ drilling. Anything at depths of greater than 500 feet (152 metres) used to be considered deep water, but the definition now refers to greater depths sometimes over 500 metres (1640 feet). Estimates of the amount of oil and gas in deep water fields also vary significantly. Energy giant Total puts the amount of oil and gas at 330 billion barrels (330Gb) oil equivalent – that’s 7% of the world’s oil and gas resources.7 Others have estimated the amount of deep-water oil as being 150 Gb.8 Our thirst for energy is pushing oil and gas extraction to ever deeper waters, but working in these

Extracting and processing extra-heavy crude requires significantly more energy than drilling and refining conventional crude oil. Removing it can require multilateral drilling or energy intensive ‘in-situ’ (in place) extraction techniques. It also needs to be upgraded, requiring further energy. As a result it has much higher lifecycle greenhouse gas emissions, estimated at 30.8 kg CO2E/ MMBtu*,5 almost as much as the Canadian tar sands (estimated by the same study as 34 kg CO2E/MMBtu), compared with conventional crude oil at about 18 kg CO2E/MMBtu *kg CO2E/MMBtu is emissions in the equivalent weight in carbon dioxide per million british thermal units – it is a measure of a fuels greenhouse gas emissions per unit energy.

Deepwater Horizon offshore drilling unit on fire

extreme environments involves significantly increased risks. The Deep Water Horizon platform spectacularly demonstrated this in 2010, when the failure of a blowout preventer resulted in a disaster that killed 11 workers, and caused the largest off shore oil spill in history resulting in massive environmental damage. Deep water deposits can be found around the world, but there is a ‘golden triangle’ between the offshore regions of West Africa, Brazil and the Gulf of Mexico that holds the bulk of the deep-water resources. Exploiting the world’s deep water oil and gas resources would add an estimated 40 Gigatonnes of carbon to the atmosphere.9

Arctic oil and gas

It has been known for a long time that there are significant oil and gas resources in the Arctic but it has always been considered too difficult to exploit them due to the extreme conditions. However, things are changing: due to melting Arctic ice, high oil prices and energy security concerns (not to mention the huge profits to be made) several governments and companies now have plans to drill for oil and gas in the Arctic. The US geological survey estimated in 2008 that the Arctic’s technically recoverable resources include 90 billion barrels of oil and 1,670 trillion cubic feet (47 trillion cubic meters) of natural gas.10 There are concerns that if an oil spill were to occur in the Arctic environment it could have a devastating impact. The logistical difficulties, sensitive ecosytems

and lack of bacteria to digest and break down the oil mean that a spill in the Arctic could have significantly more serious consequences than in other locations.11 12 The extreme technical difficulties of Arctic oil exploration were recently demonstrated when, following a host of other problems, Shell’s Arctic exploration rig, the Kulluk ran aground and Shells plans for 2013 had to be put on hold. There are also various competing claims over countries’ rights to extract resources from the Arctic, and fears that this may fuel military conflict in the future.13 There is a cruel irony at play in the Arctic: burning fossil fuels is warming the atmosphere, melting the ice caps and opening up access to yet more fossil fuels. Extracting them will cause further CO2 emissions, warming the atmosphere even more. If we are to end this vicious cycle we must reduce energy consumption, move to renewable energy sources and leave the fossil fuels in the ground, in the Arctic and around the world. Exploiting Arctic oil and gas resources would add an estimated 39 Gigatonnes of carbon to the atmosphere.14 Countries involved in development of Arctic oil and gas resources include: Norway, Russia, Denmark, Canada, US and China. Notable companies involved in Artic oil and gas include: Shell, BP, Exxon, Gazprom, Rosneft and Statoil.

Geopressurised Zones

Geopressurized zones are deposits of natural gas under very high pressure, found at depths of about 3,000 to 7,500 metres below the earth’s surface either inland or under the sea. There is a particularly high concentration of geopressurised zones in the Gulf Coast region off the United States, which have been estimated to hold large gas resources.15

Shell’s Arctic exploration rig, the Kulluk, after running aground in 2013

There has been some exploratory drilling of geopressurised zones, however, and due to the difficulties of extreme pressure and depth no commercial extraction has yet taken place. Despite the extremely large estimated global resources,16 geopressurised natural gas remains an undeveloped energy source.

Endnotes 1 Farrell, A E, and A R Brandt. ‘Risks of the Oil Transition’. Environmental Research Letters 1, no. 1 (October 2006): 014004. doi:10.1088/17489326/1/1/014004. <http://iopscience.iop.org/1748-9326/1/1/014004/ pdf/1748-9326_1_1_014004.pdf> 2 ‘CO2-driven Enhanced Oil Recovery as a Stepping Stone to What?’. Pacific Northwest National Laboratory, US Department of Energy (Jul 2010). <http://www.pnl.gov/main/publications/external/technical_ reports/PNNL-19557.pdf> 3 ‘The Latest on Earthquakes: Enhanced Oil Recovery Shaking Things Up in U.S.’. Duke Dean’s Blog: The Green Grok. Accessed 9 March 2014. <https://blogs.nicholas.duke.edu/thegreengrok/the-latest-onearthquakes-enhanced-oil-recovery-shaking-things-up-in-u-s/> 4 Hughes D J. ‘Drill, Baby, Drill: Can Unconventional Fuels Usher in a New Era of Energy Abundance?’. Post Carbon Institute (Mar 2013). <http://www.postcarbon.org/drill-baby-drill/> 5 ‘An Evaluation of the Extraction, Transport and Refining of Imported Crude Oils and the Impact of Life Cycle Greenhouse Gas Emissions’. National Energy Technology Laboratory, US Department of Energy (Mar 2009). 6 See <www.corporatewatch.org/uff/carbonbudget> 7 ‘Deep Offshore: Global Oil and Gas Reserves’. Total.com. Accessed 9 March 2014. <http://total.com/en/energies-expertise/oil-gas/ exploration-production/strategic-sectors/deep-offshore/ challenges/context-overview> 8 ‘Updating World Deepwater Oil & Gas Discovery’. Resilience.org. Accessed 9 March 2014. <http://www.resilience.org/stories/ 2012-05-14/updating-world-deepwater-oil-gas-discovery>

9 See <www.corporatewatch.org/uff/carbonbudget> 10 ‘USGS Release: 90 Billion Barrels of Oil and 1,670 Trillion Cubic Feet of Natural Gas Assessed in the Arctic (7/23/2008 1:00:00 PM)’. USGS.gov. Accessed 9 March 2014. <http://www.usgs.gov/newsroom/article. asp?ID=1980&from=rss_home#.UxyLYc7xHSc> 11 ‘Oil Spill Prevention and Response in the U.S. Arctic Ocean: Unexamined Risks, Unacceptable Consequences. The Pew Charitable Trusts (Nov 2010). <http://www.pewtrusts.org/our_work_report_ detail.aspx?id=61733> 12 ‘U.S. Icebreakers Can’t Handle Alaska Oil Spills: Official’. Reuters. Accessed 9 March 2014. <http://www.reuters.com/ article/2011/02/11/us-arctic-oil-vessels-idUSTRE71A5RM20110211> 13 ‘Heat over Arctic: Battle for North Pole High on Global Military Agenda’. Global Research. Accessed 9 March 2014. <http://www. globalresearch.ca/heat-over-arctic-battle-for-north-pole-highon-global-military-agenda/5351489> 14 See <www.corporatewatch.org/uff/carbonbudget> 15 Quitzau, R., and Z.A. Bassiouni. ‘The Possible Impact of the Geopressure Resource on Conventional Oil and Gas Exploration’. Society of Petroleum Engineers, 1981. doi:10.2118/10281-MS. <https://www.onepetro.org/conference-paper/SPE-10281-MS> 16 ‘Unconventional Forms of Natural Gas’. JUICE: Alternate Fuels World’. Accessed 9 March 2014. <http://www.alternatefuelsworld.com/ unconventional-forms-of-natural-gas.html>

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what is it? Carbon Capture and Storage (CCS) technologies are designed to take carbon dioxide from fossil fuels (either before or after they are burned) and inject it into underground storage sites, usually geological formations. Proponents of the technology (often employees of the fossil fuels industry) say that it can provide significant emissions reductions, and allow us to go on burning coal, oil, natural gas, and even unconventional fossil-fuels such as tar sands, while still reducing emissions sufficiently to stabilise the global climate. In reality it is not a viable way of effectively reducing CO2 emissions.

Carbon Capture andstorage CAPTURING CO2 WHERE IT IS PRODUCED, TRANSPORTING IT, AND PUMPING IT INTO UNDERGROUND STORAGE SITES TO REDUCE EMISSIONS. THE TECHNOLOGY HAS SEVERE LIMITATIONS, LIKELY IMPOSSIBLE AT THE SCALE REQUIRED, BUT IS USED AS A SMOKESCREEN FOR THE CONTINUED EXPANSION OF FOSSIL FUEL PRODUCTION.

There are three main types of CCS technology. The first is post combustion capture, where CO2 is ‘scrubbed’ from the exhaust gases after fuel is burned. The second is pre-combustion capture, where the fuel is heated and mixed with oxygen to produce hydrogen (a clean burning fuel) and carbon dioxide, which is then removed. Thirdly, oxy-fuel combustion involves burning the fuels in oxygen rather than air, producing pure CO2 which can then be removed. Once the CO2 has been extracted it can be transported to storage sites in pipelines. Underground oil and gas fields (either depleted fields or declining fields as part of enhanced oil/gas recovery – see ‘Other Unconventional Fossil Fuels’ factsheet) are most likely to be used for storage, but underground saline aquifers (underground layers of rock containing salt water), underground coal seams, basaltic rocks beneath the seafloor, ocean storage and mineral carbonation (where CO2 is reacted with minerals to form solids) have also been suggested. Although the various technologies involved in CCS have been tested on a relatively small scale for some time, they have only been put together on an industrial scale in a handful of installations. There are currently no commercial installations and no large-scale installations dealing with emissions from electricity production.

Emissions Limitations Even those who have faith in CCS as a viable technology for emissions reductions admit that there are limits to its effectiveness. Removing the CO2 will always require a certain amount of energy, with further energy expended on transportation to storage sites. It is estimated that the energy cost of CO2 extraction from a coal power station would represent up to 40% of the energy produced by burning the coal.1 This extra energy would require more coal to be mined and transported, and the emissions from this mining and transportation could not be captured. In addition, CCS technologies only work on power generated from coal and gas and, in theory, some industrial processes such as cement production. This means that they would not mitigate emissions from the oil-based transport system, for example. In 2010 transport was estimated to make up 22% of global greenhouse gas emissions (16% from road transport and 6% from other sources including aviation and shipping).2 Ultimately, even if CCS were rapidly and widely implemented, it would only have potential to reduce global emissions by a limited amount. A very optimistic projection of the development of CCS technology, with 3800 CCS projects in operation by 2050 (at enormous cost), would lead to a total of 34 Gigatonnes of carbon (GtC) stored.3 Measuring from the start of the industrial revolution (around 1750), a maximum of 500 GtC can be emitted to the atmosphere while still avoiding most

serious impacts and the risk of irreversible and uncontrollable changes to the climate.4 Between 1750 and now (2014), we have already emitted about 370 GtC, leaving a limit of 130 GtC that could be further added.5 Considering that there are at least 500 GtC in remaining conventional coal reserves alone, being able to store at best 34 GtC by 2050 using CCS does not change the fact that the vast majority of all fossil fuels must remain in the ground. So even if all the huge technical problems were overcome and CCS were to be fully employed, we still could not afford to burn even a small fraction of the conventional fossil fuels we have, let alone exploit the huge additional unconventional resources. Further to this, CO2 can be (and is) injected into old oil, coal and gas deposits in order to extract more resources (known as Enhanced Oil, Gas or Coal Bed Methane Recovery, EOR, EGR or ECBM). Somewhat ironically, proponents of CCS advocate the technology being used in combination with EOR/EGR to make it financially viable. So a technology that is supposed to be used to reduce emissions, in practice would actually be used to access to even greater amounts of fossil fuels.

Storage All of the proposed storage options have their own problems. Ocean storage is not generally considered to be viable as it would rapidly accelerate ocean acidification. Another possibility, which can be carried out above ground, is â&#x20AC;&#x2DC;mineral carbonationâ&#x20AC;&#x2122;. This

involves allowing CO2 to react with suitable minerals (for example some silicate minerals) to produce a rock product in which the CO2 is effectively stored. However, mineral carbonation is also not an option due to the vast amounts of suitable minerals that would need to be mined and the enormous quantities of waste material (i.e., the CO2 -rock product) that would be produced.6 For CCS to be viable, gasses would have to be reliably stored at sites over very long time-scales, for hundreds or possibly thousands of years. While CO2 and other gases can naturally remain trapped for extremely long periods in geological formations, storage of man-made CO2 underground poses various problems. Every potential site has its own unique geology, which will respond to the injection of high pressure CO2 in a variety of ways. In some cases injection has resulted in earthquakes and significant changes of ground level, posing serious risk of leakage.7 8

A paper published in the journal the Proceedings of the National Academy of Sciences found that in many areas, carbon sequestration is likely to create pressure build-up large enough to break the reservoirs’ seals, releasing the stored CO2.9 They also found that there is a high probability that the injection of large volumes of CO2 will trigger earthquakes, and that even small to moderate sized earthquakes threaten the seal integrity of storage sites. This led the authors to conclude that, “large-scale CCS is a risky, and likely unsuccessful, strategy for significantly reducing greenhouse gas emissions”. There are also concerns that contaminants within the CO2, and the CO2 itself, might react with water to create acids which would then damage the structure of the rock and undermine its ability to keep the CO2 trapped. It should be noted too that abrupt leakage could pose a significant risk to human health and the local environment. In 1986 a large natural CO2 leakage rose from Lake Nyos in Cameroon and asphyxiated 1,700 people.

Other issues

Scale. The amount of CO that would need to be 2

condensed into liquid and transported to storage sites (which would often be a long way from the source) is enormous, and could require a pipeline network similar in scale to the existing fossil fuel pipeline infrastructure.10 This would of course be accompanied by the social and environmental impacts that a project of such a size would involve. There are also serious doubts about there being sufficient suitable storage sites around the world to sequester the volume of gas that would be required.11

Cost. No one knows exactly how much it would

cost to implement a CCS system across the globe, as different parts of the technology are at various stages of development, but the amounts involved would be huge. In particular, the transportation of CO2 by pipeline would be extremely expensive. In the best case scenario, close to a storage site, CCS is expected to increase the cost of electricity from a new power plant by 21–91%.12 Despite their supposed enthusiasm for the technology, there is apparently little desire for the energy industry

to take on the cost of developing CCS. Several competitions for CCS demonstration projects with very generous government grants have collapsed as a result of lack of commercial interest. Despite £1 billion being made available, the UK’s Longannet CCS demonstration project collapsed in 2011 after the consortium failed to keep estimated costs down. In July 2013 an EU CCS programme, NER300, attracted only one submission.13

Liability. A similar dilemma to that of responsi-

bility for the long term storage of nuclear waste exists with CCS. It is far from clear who would be responsible for monitoring and maintaining the sites for hundreds or even thousands of years, or for the cost (economic, social and environmental) of any leakage. Liability issues remain very much unresolved.14