Geoscientist Online

Can non-conventional oil hope to fill the looming energy gap? David Strachan investigates.

Geoscientist 20.02 February 2010

The oil crisis is not dead, only sleeping, according to a gathering consensus. The price may have collapsed from the all-time high of $147 per barrel to around $75 today, as the recession grinds away at demand for crude; but nobody expects that to last once the economy recovers. Analysts Goldman Sachs predict oil will cost $95 by the end of 2010, while Deutsche Bank forecasts $175 by 2016. The International Energy Agency (IEA), the OECD’s energy watchdog, also predicts a “supply crunch” around the middle of the next decade.

Yet there is no shortage of oil – at least not underground. Conventional crude is substantially depleted, with estimates of 1.2 trillion barrels of proved reserves remaining. But conventional reserves are dwarfed by a whole range of non-conventional resources, such as the Canadian tar sands, oil shale, and synthetic liquid fuels made from gas or coal, which according to the IEA expand the total oil resource to nine trillion barrels (see graph). And so far the non-conventionals are almost entirely untouched. So how could there possibly be an oil supply crunch, let alone peak oil, any time soon?

The trouble is, non-conventionals are so called for a reason, and traditionally need large inputs of energy, water and money to get out of the ground and turn into anything useful like diesel or jet fuel. As a result, non-conventional oil production currently amounts to less than 1.5 million barrels per day (mb/d), of a total 85mb/d.

But now a clutch of emerging technologies promise to solve some of those problems and allow non-conventionals to be produced much more cheaply with far less energy and water. According to Julie Chan, VP Finance at E-T Energy, a Canadian company developing a way to produce bitumen from the tar sands by sending an electric current through the reservoirs, “Canada could eclipse Saudi Arabia”. So are non-conventionals about to ride to the rescue, and confound the peak oil doomsayers for decades to come?

The only significant non-conventional oil production today comes from the Canadian oil sands, and so far most of the bitumen has been extracted from huge mines run by operators such as Shell, Suncor and Syncrude. But mining is expensive, and new projects need an oil price of $80 to make a 10% return. The process also requires huge volumes of water, yet 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 75m deep – and that’s just 20% of the total resource.

The rest has to be produced using newer in situ techniques like Steam Assisted Gravity Drainage (SAGD), where steam is injected into a horizontal well to melt the bitumen, which then flows down into a lower well to be pumped out. This is cheaper and uses much less water than mining, but far more energy – usually in the form of natural gas - because of the need to raise steam. An industry-sponsored report found in 2005 that if oil sands production rose to 5mb/d by 2030, it would devour 60% of western Canada’s entire gas supply, which it described as “unthinkable”.

But now a range of new technologies are being developed that promise to relieve some of the constraints. Nexen, a Canadian oil company, has developed a new twist on SAGD by dispensing with natural gas as fuel, and using some of the produced bitumen to generate energy instead. At its Long Lake site, the company gasifies asphaltines - the heaviest fraction of the bitumen - to make a synthetic gas, which is used to raise steam for SAGD, and produce hydrogen to upgrade the bitumen on site into high quality synthetic crude oil. This makes the process cheaper and energy self-sufficient, even generating surplus power to export to the grid. The company aims to expand production from the current 14,000 barrels per day to 60,000 b/d by 2013.

Toe-to-Heel-Air-Injection (THAI) takes a similar approach, but does the burning underground. THAI involves a horizontal production well, paired with a vertical injector well drilled close to its ‘toe’. To start with steam is pumped down 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 pumped down the injector well to create a ‘fire front’ that moves slowly through the reservoir from the toe of the production well towards the heel, burning the asphaltines at temperatures of up to 500°C and melting the rest of the bitumen to flow into the well. The intense heat partially upgrades the bitumen so it emerges lighter than normal, meaning it needs less refining later. The process uses much less gas and produces a net surplus of water.

Another new approach is not to burn the bitumen underground, but 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 oil sands, each containing three electrodes. Current is conducted between the wells through groundwater, and the resistance heats the bitumen to flow into a production well in the middle. Changing the voltage gradient between the electrodes allows the operators to direct the electric field to heat the richest parts of the reservoir. Any water that comes up is re-injected to maintain conductivity, and because the process runs on grid electricity, there’s no need for natural gas.

So with huge reserves and new technologies, can the oil sands put off the oil crunch? Surprisingly, promoters of the newest technologies are skeptical. Bruce McGee, boss of E-T Energy, the company behind ET-DSP, stresses the massive investments that will be required even to reach industry estimates of 5 mb/d by 2030, and doubts output can be raised significantly further. Chris Bloomer, his counterpart at Petrobank Energy and Resources, the company developing THAI, agrees: “The oil sands are not going to solve the world’s oil supply problems”.

That view seems to be supported by the findings of a recent report on the oil sands’ growth prospects from analysts IHS CERA, after consulting widely in the industry. In its most optimistic scenario, “Barreling Ahead”, in which the industry is supported by strong demand, firm oil prices, and government policy, oil sands output reaches 6.3 million barrels per day in 2035. But to get there, the report assumes production capacity would rise 200,000 daily barrels every year, twice the growth rate between 2005 and 2008, when the industry overheated, suffering widespread skilled labour shortages, double-digit inflation and endemic project delays. Jackie Forrest, who project-managed the report for IHS CERA, says “we believe that’s really pushing it”.

THAI and ET-DSP may help relieve resource constraints and bring costs down in future, but IHS CERA estimates it will take between five and 15 years to commercialise the new technologies. “It could be a decade before it is used in enough reservoirs to contribute meaningfully to production”, says Forrest. And that’s well beyond many forecasts of the next oil crunch.

In the meantime, any growth will depend on older, more expensive methods that are vulnerable to volatility in the oil price. Since the price slumped from its peak of $147 last year, oil sands projects totaling 1.7mb/d have been cancelled or delayed indefinitely, according to the IEA. If oil price volatility persists, as many analysts predict - with shortage leading to a price spike, leading in turn to recession and low oil prices again - the drag on oil sands development could become chronic.

Len Flint, of Lenef Consulting, which specialises in the tar sands, thinks output will still rise to 2mb/d by 2012 because of projects that are too far advanced to cancel, but acknowledges the risks to growth further out: “any volatile prices in which there may be a collapse inevitably curtails the development of the oil sands”.

Others take comfort from the oil price recovery from around $35 at the beginning of this year to around $70 today. “There’s been a probably structural uplift in where the pricing should be, and that’s encouraging”, says John Broadhurst, VP Development & Technical Services for Shell Canada. The company, which currently has 215,000 b/d in mining and SAGD production, is in the process of expanding output by 100,000 b/d, but a subsequent expansion is on hold.

Of all the supermajors Shell has most riding on the tar sands, and the company believes non-conventional oil will make up for declining conventional supplies, at least for a time. But they don’t pretend it will be easy. “It’s going to be a challenge because these are more challenging hydrocarbons to deliver” says Broadhurst.

The challenges for other forms of non-conventional oil production are even greater. Shale oil is another potentially massive resource, with over 2.5 trillion barrels in place, and has been used to produce oil since before the conventional industry took off in the late 19th Century. But production has dwindled since 1980, and today its only significant use is as power station fuel in Estonia (Geoscientist 17.2 Shale of the Century pp22-27).

The basic problem is that oil shale is a misnomer. The sedimentary rock contains no oil, only an organic substance called kerogen bound in a mineral known as kukersite, and to produce oil you need to heat the rock to 500°C until the kerogen decomposes into synthetic crude and a solid residue. Traditionally that has meant digging the shale up and baking it in a huge oven, which is energy-intensive and expensive. So what’s needed is an in situ production method, like those developed in the oil sands.

Three quarters of the global shale resource lies in Colorado, Utah and Wyoming, and the Obama administration has recently re-started the process of leasing Federal land for shale oil R&D. A number of ingenious technologies are being developed to heat the shale underground - including microwaves, high temperature gas injection, and radio waves combined with supercritical CO₂ – and then extract the resulting oil using conventional oil wells. But all are in their infancy.

Shell has done more work than most on its extraordinary shale In Situ Conversion Process. Electric heaters are lowered into 2000-foot vertical wells and left to heat the shale to 300-400°C for several years, converting its kerogen into oil, which is then pumped out. At the same time the perimeter of the production area is frozen to the same depth using wells refrigerated with ammonia to prevent groundwater contamination.

However, even after 25 years’ R&D the company will not be ready to decide whether to commercialise the technology until the “middle of the next decade and possibly later”. The IEA estimates shale oil would cost between $50 and $100 to produce, more when any future carbon penalty is taken into account, and the Agency expects no significant shale oil production this side of 2030.

Carbon regulation hangs over all non-conventionals, partly because the additional energy required to produce and refine them generally makes them more carbon intensive than conventional crude - although by how much is disputed. Greenpeace argues that producing and upgrading a barrel of bitumen emits up to five times as much as from a conventional barrel, while the industry insists that in terms of lifecycle emissions – including refining and end-use – the difference is only 5-15%.

Whoever is right, the tar sands will be penalised if President Obama makes good his pledge to follow California and introduce a nationwide Low Carbon Fuel Standard (LCFS), requiring a 10% cut in the average carbon intensity of fuel by 2020. “If the US goes ahead with the LCFS, it will slow down the development of the tar sands”, says Professor David Keith, of the Department of Chemical and Petroleum Engineering at the University of Calgary.

Non-conventionals would also be hit by the spread of carbon pricing, especially coal-to-liquids (CTL), which has twice the lifecycle emissions of conventional crude, of which less than half – the upstream portion - could be removed by carbon capture and storage (CCS). Production today is negligible at 160,000 barrels per day, but the IEA estimates that producing CTL costs up to $60 per barrel, to which a carbon price of $50 per tonne would add another $30/bbl. CCS would add yet more expense.

As the obstacles to expanding non-conventional oil production accumulate, the challenge of replacing conventional oil looks ever more daunting. A major study published in October from the UK Energy Research Centre entitled Global Oil Depletion: An assessment of the evidence for a near-term peak in global oil production, found that output from conventional oilfields is declining at four percent, meaning we have to add three million barrels per day of new daily production capacity every year just to stand still – equivalent to a new Saudi Arabia coming on stream every three years. They also found a ‘significant risk’ that conventional production will peak before 2020.

So what chance do non-conventionals have of filling the deficit? Not much, according to Steven Sorrel, the report’s lead author. “If everything goes well the oil sands might produce 6mb/d 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. So it’s very hard to see non-conventionals riding to the rescue. We haven’t demonstrated it in the report, but I think it’s likely that conventional peak oil will turn out to be peak oil full stop”.

Still, there may be a silver lining: if non-conventionals cannot defer peak oil, they will do that much less damage to the climate.

*David Strahan is an energy writer and author of The Last Oil Shock. www.lastoilshock.com He is a Trustee of the Oil Depletion Analysis Centre, loves his allotment and swims 100m freestyle in 1'25.

© David Strahan