Extreme oil: Scraping the bottom of Earth's barrel

David Strahan, New Scientist 2 Dec 09;

Editorial: Plenty more oil, but use it wisely

EIGHTY-FIVE million barrels. That's how much oil we consume every day. It's a staggering amount - enough to fill over 5400 Olympic swimming pools - and demand is expected to keep on rising, despite the impending supply crunch.

The International Energy Agency forecasts that by 2030 it will rise to about 105 million barrels per day with a commensurate increase in production (see graph), although whistle-blowers recently told The Guardian newspaper in London that insiders at the IEA believe the agency vastly over-estimates our chances of plugging that gap. The agency officially denies this.

Wherever the truth lies, it is widely expected that by 2030 we will have passed the peak of conventional oil production - the moment that output from conventional oil reserves goes into terminal decline. A report from the UK Energy Research Centre (UKERC) published in August said there was a "significant risk" it would happen before 2020. And that means we will soon be staring down the barrel of the ultimate oil crisis.

Some governments and corporations are waking up to the idea and beginning to develop alternatives to keep the world's transport systems moving when cheap oil runs out. These include biofuels, more energy-efficient - or electric - carsMovie Camera, and hydrogen. But none of these is likely to make up the global shortfall in time. The pressure is on to keep the black stuff flowing and so the next two decades will see an unprecedented effort to exploit increasingly exotic and unconventional sources of oil. They include tar sands (a mixture of sand or clay and a viscous, black, sticky petroleum deposit called bitumen), oil shale (a sedimentary rock containing kerogen, a precursor to petroleum) and synthetic liquid fuels made from coal or gas.

Purely in terms of geological abundance, these sources look more than sufficient to meet global demand. According to the IEA, taken together, they raise the remaining global oil resource to about 9 trillion barrels (see map) - almost nine times the amount of oil humanity has consumed to date. The trouble is that the name "non-conventional oil" hides several dirty little secrets and a whole host of huge challenges.

Conventional oil refers to liquid hydrocarbons trapped in deep, highly pressurised reservoirs, which means that when the wells are drilled, the oil usually gushes to the surface of its own accord. Non-conventional oils are not so forthcoming, and need large amounts of energy, water and money to coax them from the ground and turn them into anything useful, like diesel or jet fuel.

As a result, non-conventional oil production to date has been slow to expand - with current output of just 1.5 million barrels per day. Not only that, because they take so much energy to produce, they are responsible for higher carbon emissions per barrel than conventional oil.

But, slowly, things are beginning to change. Growing awareness of the impending oil shortage and its ramifications - Deutsche Bank predicts a barrel price of $175 by 2016, for example - has driven a surge of investment in new technologies to recover non-conventional oil more effectively. "Canada could eclipse Saudi Arabia," says Julie Chan, vice-president of finance at E-T Energy, a Canadian company developing a new technique to extract oil from tar sands. So are non-conventionals poised to swoop in and confound the peak-oil doomsayers? Can we expect a new era of expensive, technologically demanding and environmentally damaging oil?

The most famous of the non-conventional resources are the Canadian tar sands, where proven reserves are second only in size to Saudi Arabia's conventional crude. Today, production stands at 1.2 million barrels per day. Tar sands containing bitumen are extracted from huge opencast mines and processed to produce oil. But mining and processing the raw bitumen is expensive and requires huge volumes of water (see diagram). In Canada, the industry is already reaching the legal limits of what can be drawn from the Athabasca river in winter. Worse, mining is only possible for deposits less than about 75 metres deep, and that's just 20 per cent of the total resource. So a whole range of new technologies is now being explored to extract the deeper bitumen.
Steamy business

Steam-assisted gravity drainage (SAGD) is one of the most established processes, accounting for almost half of tar sands production. Steam is injected into a well to melt the bitumen, which drains into a secondary shaft from where it is pumped out (see diagram). This is cheaper and uses much less water than mining, but more energy - usually from natural gas - to produce the required steam. An industry-sponsored report published by Alberta Chamber of Resources in 2005 found that if tar sands oil production rose to 5 million barrels per day by 2030, it would need 60 per cent of the gas consumed by western Canada, which it said would be "unthinkable".

But this brand of SAGD is not the only game in town. Nexen, a Canadian oil company, has developed a new twist on SAGD by dispensing with natural gas as fuel and using some of the bitumen to generate the energy needed to produce the steam. At its site in Long Lake, Alberta, the company gasifies asphaltenes - the heaviest fraction of bitumen. This synthetic gas is burned to generate steam for SAGD, and is also used to produce hydrogen which in turn is used to upgrade the bitumen on-site into high quality synthetic crude oil. This makes the process cheaper and energy self-sufficient - it even generates surplus power to export to the grid. The downside is that carbon dioxide emissions are higher than for mining or standard SAGD. The company aims to expand production from its current 14,000 barrels per day to 60,000 by 2013.

A method called "toe to heel air injection" takes a similar approach to SAGD, but does its burning underground. THAI involves a pair of wells. A vertical air-injecting well is drilled close to the "toe" of a horizontal production well (see THAI). Steam is pumped into both wells to heat the bitumen until it is hot enough to combust spontaneously when exposed to air. Then the steam is turned off, and air is pumped down the injector well to feed a horizontal fire front that moves slowly through the reservoir from the toe of the production well towards the heel, generating temperatures of up to 500 °C. The intense heat separates the bitumen into heavier and lighter fractions, with the heavier one (asphaltines) fuelling the fire while the lighter ones melt, flow to the production well and get pumped to the surface. That's a neat trick, because it means part of the refinery's job is done underground. This process uses between 10 and 30 per cent of the natural gas consumed by SAGD processes. It is even self-sufficient for its water needs, because groundwater is pumped up the production well along with the bitumen and recycled.

A third approach sounds a little more "out there", but in theory has the potential to be the least polluting of all the new bitumen-extraction techniques. Instead of heating the bitumen in a conventional fashion, the idea is to zap it with electricity, using a technique called electro-thermal dynamic stripping process (ET-DSP). A grid of vertical wells is drilled into the tar sands, each containing three large electrodes (see ET-DSP). Current is conducted between the wells via groundwater. The electrical resistance of the earth generates heat which liquefies the bitumen and allows it to flow into a central production well. Changing the voltage gradient between the electrodes allows the operators to direct the electric field to heat the richest parts of the bitumen deposit. Any water that comes up with the liquefied bitumen is re-injected to maintain conductivity. Since the process runs on grid electricity, there's no need for natural gas.

However, on the basis of Alberta's largely coal-fired power supply, the electricity used in ET-DSP means the production process is responsible for more carbon emissions than either mining or conventional crude production. E-T Energy, the company developing the technology, insists that emissions could be slashed if it were powered using hydro, wind or even gas-fired power. In a separate development, Bruce Power, an Alberta-based nuclear power generation company, has drawn up plans for new reactors sited near Canadian tar sands deposits to provide CO2-free electricity to the oil-extraction industry.

Although THAI and ET-DSP seem to have solved some of the practical problems of tar sands oil production, and the costs may fall in the future, they are still in their infancy. IHS CERA, an oil consultancy that recently produced a report on the growth prospects for tar sands production, estimates it will take between 5 and 15 years to commercialise the new technology. "It could be a decade before it is used in enough [tar sands] reservoirs to contribute meaningfully to production," says Jackie Forrest, one of the report's authors.
Tar sands

In a scenario most favourable to tar sands - high oil prices, growth in demand and a supportive regulatory framework - IHS CERA predicts output from the Canadian tar sands could reach 6.3 million barrels per day by 2035. That's a small fraction of forecast global demand, but to achieve even this, production would have to grow twice as fast as it ever has. That, says Forrest, "is really pushing it". So what of the other alternatives?

Oil shale is the next large unconventional resource under consideration, with around 2.5 trillion barrels of "oil equivalent" identified. It was used to produce oil before the oil industry took off in the late 19th century. To produce oil from it, you essentially need to speed up a geological process that takes millions of years.

This is done by heating the rock to 500 °C until the kerogen decomposes into a synthetic crude oil and a solid residue. Traditionally that has meant digging up the shale and baking it in a huge oven. An expensive, energy-intensive process. It also leaves a greater volume of waste than the original shale, as testified by the hills of shale slag called "bings" that dot the West Lothian region of Scotland, where a century of shale oil production ended in the 1960s. What's needed is an in-situ production method similar to those developed for tar sands. Three-quarters of the global shale resource (see map) lies in Colorado, Utah and Wyoming, and Barack Obama's administration has recently restarted the process of leasing federal land for shale oil R&D. A number of technologies are being developed to heat the shale underground. These utilise microwaves, high-temperature gas injection, and radio waves combined with supercritical CO2. Such heating creates an oil reservoir that can then be extracted using conventional drilling.

Oil multinational Shell has experimented with in-situ shale oil extraction at its development site in Cathedral Bluffs, Colorado. The company drilled bore holes 650 metres deep and inserted electrodes to heat the shale to between 340 °C and 370 °C over a period of months. However, the process is extremely power hungry, requiring energy to both heat the shale and to freeze the perimeter of the reservoir to block the flow of groundwater.

The company says it is unlikely to commercialise the process for at least another five years. The IEA estimates shale oil would cost between $50 and $100 per barrel to produce, without taking into account any carbon-emissions pricing that may come into force. It expects no significant shale oil production this side of 2030.

There's yet another old-school production method that may experience something of a renaissance in the coming decades. Just as shale oil is nothing new, neither is making liquid fuels from coal. Two German researchers developed the eponymous Fischer-Tropsch process in the 1920s, heating coal to produce a gas of carbon monoxide and hydrogen, which is then catalysed to produce diesel and kerosene. The technology was exploited by oil-strapped, coal-rich Germany during the second world war, and by South Africa in the 1980s and early 1990s to beat sanctions imposed during apartheid. South Africa has the world's only major coal-to-liquids (CTL) plant operating today and China has recently built a demonstration plant in Inner Mongolia.

So, could coal be the answer? Few doubt there is enough of the stuff to support a major expansion of CTL (New Scientist, 19 Jan 2008, p 38), and the fuels produced are of a high quality. The drawbacks are formidable: it takes about two tonnes of coal and up to 15 barrels of water to produce a single barrel of synthetic fuels. That makes it expensive. The IEA says that when it comes to US coal, to supply just 10 per cent of US transport fuel consumption would mean investing $70 billion, and raising coal production by 25 per cent - an additional 250 million tonnes per year.

Worse, because of the feedstock and energy demands of the production process, CTL fuels have roughly double the carbon emissions of conventional crude on a well-to-tank - or "mine-to-tank" - basis. Carbon capture and storage could be applied to the production plant, but the process is likely to be 90 per cent efficient at best. Then there are still the same emissions as petrol derived from oil when burning it in your car engine. So even with CCS, CTL is always likely to emit more carbon than conventional crude.

The Fischer-Tropsch process can also be used to make liquid fuels from natural gas. As with coal, there is no immediate shortage of feedstock. In fact, prices have slumped as rising gas production in the US and falling global demand combine to produce a worldwide glut which should last for at least the next few years. But, as with coal, there are major drawbacks.

The gas-to-liquids process (GTL) emits much less carbon than CTL, because the feedstock is cleaner, but still more than conventional crude. That's because almost half of the 280 cubic metres of gas it takes to produce a barrel of GTL fuel is burnt during the conversion process. Three small plants account for global production of 50,000 barrels of synthetic fuels per day. That should quadruple in the next few years with the opening of two larger plants in Qatar and Nigeria.

So with huge reserves and up-and-coming technologies, what are the prospects for unconventional sources? Will the non-conventionals be able to fill the gap left by diminishing crude oil, are we doomed to soaring emissions from ever dirtier oil?

Most analysts agree on one thing: despite the enormous size of the non-conventional resource, it will be decades before the new technologies can have a significant impact. In the meantime, any attempt to grow output quickly will have major regulatory and financial hurdles to overcome. In the US, federal bodies are effectively banned from buying non-conventional fuels because of their high CO2 emissions.

Furthermore, Obama has pledged to introduce a nationwide Low Carbon Fuel Standard (LCFS), requiring American fuel suppliers to cut carbon emissions from burning their fuels by 10 per cent between 2010 and 2020. Globally, non-conventionals would be penalised by any carbon-pricing regime that may result from the UN's climate change conference in Copenhagen, Denmark, next week. The IEA is pushing for a carbon-emissions price of $50 per tonne, which it says would add $5 to a barrel of fuel derived from tar sands, $12.50 to a barrel of GTL fuels and $30 to CTL ones.

Oil-price volatility is perhaps of even greater significance. Since the price slumped from its peak of $147 last year, tar sands projects aiming to deliver a total of 1.7 million barrels per day have been cancelled or delayed indefinitely, says the IEA. If price volatility persists - with oil shortages leading to a price spike, leading in turn to recession and a resumption of low oil prices - the halting investment in non-conventional oil development could become chronic.

The IEA's chief economist Fatih Birol says non-conventionals can defer global peak oil to "around 2030". Others are not convinced. "If everything goes well," says Steven Sorrel, the lead author of the UKERC report, "oil sands might produce 6 million barrels per day in 20 years' time, but by then we'll need to add at least 10 times that much capacity - without allowing for any growth in demand. It's very hard to see non-conventionals riding to the rescue."

David Strahan is the author of The Last Oil Shock: A survival guide to the imminent extinction of petroleum man (John Murray, 2007)