[ This article discusses why it’s so hard and expensive to extract difficult oils like tar sands, oil shale, and tight “fracked” oil, for reasons such as:
- These are at the bottom of the resource pyramid, so there may be a lot of it, but it’s poor quality and expensive to extract.
- The tar sands in Canada and Venezuela were once super-giant fields of light oil. But over millions of years it’s been “overcooked” — bacteria swallowed most of the hydrogen atoms, degrading and converting the light oil into a nasty tar requiring expensive upgrading
- Shale gas and tight oil are in rocks where hydrocarbons may have been overcooked or haven’t made it into porous reservoirs yet. Robert Skinner says that getting them out “…amounts to giving the rocks an enema” with high pressure water, sand, and chemicals.
- Kerogen shale is undercooked. Millions of years from now it will turn into oil, but trying to accelerate this process takes too much energy
- Accelerating or reversing geology to get these difficult oils takes enormous amounts of cash, and energy, which in the end leads to huge amounts of GHG emissions.
Alice Friedemann www.energyskeptic.com author of “When Trucks Stop Running: Energy and the Future of Transportation, 2015, Springer]
Nikiforuk, A. 22 May 2013. Difficult Truths about ‘Difficult Oil’. As we work down the hydrocarbon pyramid, energy gets messier and much more costly. TheTyee.ca
As the global economy switches to heavier, messier and costlier hydrocarbons, Robert Skinner is getting a bit worried about the future of his three grandchildren. It’s all about the story of “difficult oil,” a term the highly respected energy expert and geologist first coined nearly a decade ago.
Now, Skinner, a 67-year energy veteran, has seen it all. He has not only worked extensively for industry and government (Energy Mines & Resources) but even for think tanks such as the prestigious Oxford Institute for Energy Studies. He also served as the policy director for the International Energy Agency in the early 90s as climate change and post-Soviet Europe seized the agency’s attention.
When not writing or thinking about difficult oil, Skinner now advises governments, universities and companies on strategy, whether for research, regulations or investment.
Skinner first saw the oil sands in 1966 as a student geologist. At the time it consisted of just one construction project for the first Suncor mine.
He has returned every decade since, first as a federal energy official, and then as an employee for the French oil giant, Total. In his last stint he served as senior vice president for Statoil Canada.
“I first saw the oil sands as a sideline, out-of-sight activity that governments were reluctant to approve — because it would compete with output from the string of discoveries after Leduc that governments were lobbying the U.S. to import. Today it is a burgeoning boomtown, world-scale industry that governments are again lobbying the U.S. to import.”
But his experiences working with bitumen over the last 45 years confirmed Skinner’s deepest suspicions: difficult oil is, well, difficult and really is a shift from business as usual. It is all about burning money to reverse or speed up geology. Moreover, technological breakthroughs to speed up or slow down geological forces are slow if not ponderous.
Skinner first dug up the important concept of “difficult oil” in 1998.
Difficult hydrocarbons, he explained, generally lie at the bottom of the resource pyramid. They might be massive in volume but high in cost, and often poor in quality.
Difficult oil has either been cooked too much, too little, or not at all. In some cases it has been degraded by bacteria. To accelerate or reverse geology generally requires ungainly amounts of energy along with clouds of GHG emissions.
The right degree of cooking over time, of course, produces light oil, notes Skinner, but much of the world’s conventional sources are now in steep decline.
Little or no cooking results in stuff like the massive resources of kerogen shale in Colorado and Wyoming. Although the U.S. government spent nearly $7-billion on trying to develop this extreme resource in the 1970s, it found that accelerating geology came with too many energy and environmental costs to make a commercial project.
That leaves over cooking or too much heat, which produces the so-called “wet gas fields,” now being pursued in the Eagle Ford field in western Texas.
The bitumen in Venezuela’s Orinoco basin and northern Alberta also requires massive geological tinkering, says Skinner.
How heavy oil got so heavy
Both heavy oil deposits actually began as super-giant fields of light oil. But over millions of years bacteria chewed up most of the hydrogen atoms degrading the resource into a thick heavy molasses-like tar. This goo can’t be turned into a commercial fuel stock without extensive upgrading to restore the ratio of hydrogen to carbon atoms.
To do so, hydrogen must be added to the bitumen or (more commonly) carbon must be subtracted, by “coking.” Coking creates mountains of petroleum coke, a coal-like substance.
Reversing geology, adds Skinner, “requires huge amounts of energy, labor, water, steel and capital. It’s all about the Second Law of Thermodynamics.”
Shale gas and tight oil, also belong to the difficult camp. They exist in source rocks where hydrocarbons may have been overcooked or not yet migrated up into porous reservoirs. As a consequence it requires some fiddling to wrestle them out of the shale. “To be graphic, it amounts to giving the rocks an enema,” says Skinner.
The cracking of these source rocks with high pressured volumes of water, sand and chemicals, a modern business frenzy, is all about accelerating geology “to speed up the migration” and release of these hydrocarbons.
But to Skinner reversing or accelerating geology ultimately adds up to one reality: spending big piles of cash.
“Difficult oil is by definition costly. And the costs are not coming down all that much.”
Bitumen remains the world’s most capital-intensive hydrocarbon. According to RSK Limited, an independent analysis firm, it takes $8 billion to develop a conventional oil field pumping one million barrels a day in the Middle East, while it takes $45 billion to produce the same result in the tar sands. (Venezuelan heavy oil is about $10 billion cheaper to produce than Canada’s bitumen.)
And that doesn’t include upgrading.
Moreover, the three biggest tight oil producers in the Bakken and Eagle Ford plays “have increased their long-term debt by over 300 per cent in the last three years. We’ve seen this over-leveraged train wreck before,” says Skinner.
The consultant also doesn’t think the capital intensity of difficult hydrocarbons gets enough attention among policy makers.
If interest rates increase and/or the price of oil sags, new production in the shale oil and oil sands becomes uneconomic, explains Skinner.
But as supply drops off, prices eventually increase again making for more volatility. The volatility of difficult oil in turn “compounds the inherent and ever-present instability caused by geopolitical factors.”
Reversing geology is not so easy
Another challenge plaguing difficult oil is the slowness and sheer difficulty of technological innovation. Reversing geology requires great complexity; progress is often incremental and disappointments are common.
“Every company, big and small, attempts to create a mystique around some ‘unique’ or ‘special’ black box or technique in particular or the firm’s technological prowess,” explains Skinner. “They do this to attract investors or to placate their environmental critics, or even to convince themselves that this business is for them.”
While new techniques and technologies, for example using solvents, are being tested, the oil sands is still running on technology several decades old. The steam plants, which boil water to make steam to melt deep underground bitumen, account for half of oil sands production. But the technologies that promised 20 years ago to produce more bitumen with less steam, still hasn’t delivered.
Instead of reducing the volume of steam needed to produce a barrel from 2.5 barrels to one barrel, most projects have increased their steam volumes (an average of 3.2 barrels now) along with energy and water costs due to the increasingly poor quality of deep reservoirs.
As Skinner notes “the ‘future’ of oil sands never seems to come; since SAGD was demonstrated nearly 20 years ago, actual industry performance has never come close to meeting projections even five let alone 10 years out.”
Nor is it just about the technology; “it’s the sheer difficulty of moving dozens of megaprojects through an overburdened regulatory process, construction and local infrastructure with an inadequate and ill-trained labor force.”
University of Calgary petroleum engineer Steve Larter has offered the same reality check: “Steam-Oil Ratios have tended to get worse with time as more difficult reservoirs are developed.” Moreover, “revolutionary technologies that lead to major downward shifts of the invested energy (e.g. steam) and emissions versus oil produced have not yet appeared.”
Skinner adds that most industry and government claims about getting cleaner are problematic at the moment: “Any company that claims its technology program will yield efficiency gains/emissions reductions beyond a modest, few percentage points within ten years — and they have yet to put steel in the ground to test their technologies — is simply naive or attempting to mislead someone. It can take more than three years just to get regulatory approval, two to build, one to three to ramp up, monitor and measure, and perhaps a couple more to analyze — and that is only for a pilot, not a full-scale commercial project: that can take another four to six years to produce initial results.”
Nevertheless Skinner believes that difficult oils such as bitumen will have a future “but it is not as bullish as some expect…. Oil sands’ future will be like their past… bumpy.” He believes that extreme, unconventional hydrocarbons will be hard-pressed to make up more than 10 per cent of global supply by 2035.