— John Kemp is a Reuters columnist. The views expressed are his own —
By John Kemp
LONDON (Reuters) - The International Energy Agency’s chief economist Fatih Birol has this week repeated earlier warnings about peaking global oil production within the next decade and the need for more investment to sustain output.
The IEA’s alarmism about oil supplies is not new. It is paid to be the “conscience” of the oil-consuming countries.
But a sense that production is close to peaking and will then begin an inexorable decline, even as demand continues to grow, has become deeply ingrained in the public imagination. Even the Green Group in my home village (population 3,000) has scheduled a talk on peak oil and intends to discuss the impact on food supplies with the Gardening Club (here).
In a trivial sense, the peak oil theory must be true. Like all the best things, oil is something they don’t make any more. It takes thousands of years of sedimentation, heat and pressure to convert long-dead plants and animals into kerogen then various hydrocarbons (natural gas, crude oil, bitumen, lignite and coal). The volume of crude oil in earth’s crust is fixed; at some point extraction will peak and then eventually run out.
The problem with peak oil is that it is the right answer but to the wrong question. As technology improves, there is plenty of conventional crude to be discovered in formerly inaccessible areas such as the ocean floors and the Arctic. Technology also exists to develop unconventional sources (such as bitumen and kerogen) into oil, and to turn natural gas and coal into liquid fuels that can be used to power cars and aeroplanes.
Global hydrocarbon reserves are more than enough to last hundreds of years, long after combusting them has cooked the planet, if fears about global warming prove correct. The real questions are how much it will cost to develop them and how to mitigate the impact on the earth’s atmosphere.
Peak oil can trace its intellectual ancestry to Reverend Thomas Malthus, a British cleric who believed that population growth would inevitably lead to global poverty. In a similarly pessimistic vein, the respected U.S. Geological Survey boldly predicted in 1919 world oil production would peak by 1928. In fact, U.S. production did not peak until 1970, and global oil production is still rising 40 years later.
But the real godfather of the movement was Shell geophysicist M King Hubbert. His theory was that production rates within an oil basin or province would follow a bell-shaped "logistic curve," rising in the early years to a peak before tailing off as the region's resource base neared exhaustion. It became the dominant paradigm in the industry when Hubbert's 1956 prediction that U.S. oil production would peak in 1970 came true (here).
Hubbert’s theory applied to a basin or region rather than an individual field. But it has been powerfully reinforced by the observed output from some of the world’s oldest and largest “super-giant” fields.
Initially, production rates rise as the oil comes out under natural pressure and more wells and gathering infrastructure are developed. As natural pressure declines, secondary recovery techniques (water injection) and tertiary recovery (injecting carbon dioxide, steam, nitrogen or solvents) can sustain output for some time. But it will eventually decline as diminishing returns set in, wells produce more water and less oil.
Peak oilers point to the dramatic production decline at Mexico's massive Cantarell field as evidence oil is running out (here).
Petroleos Mexicanos began a huge nitrogen injection program at Cantarell in 2000, boosting output to more than 2 million barrels per day (bpd) by 2004-2005. But production had fallen to less than a third of this by May 2009 (641,000 bpd). Mexico has failed to bring on enough new fields to replace the lost output, and the country’s total production has fallen 25 percent in five years.
In its 2008 World Energy Outlook, the IEA calculated natural output was declining by as much as 9 percent a year at mature (post-peak) fields, or about 6.7 percent once injection programs and other investment are taken into account. Field declines imply the need for huge investment in secondary and tertiary recovery programs, and massive new field discoveries, just to sustain current output levels, let alone increase them. The industry is running faster to stand still.
It is easy to extrapolate that world output is close to peaking. In a 2005 report for the U.S. Department of Energy, Robert Hirsch surveyed a number of respected peak oilers. Most thought the peak would occur between 2007 and 2010. The IEA's Birol has now put this back to sometime in the next decade (here).
But the Hirsch report should give peak oilers pause. Hirsch illustrated the risks by pointing to the imminent peaking of U.S. natural gas production. At the time, analysts forecast reliance on ever-greater volumes of imported gas, especially through LNG terminals, and an associated surge in natural gas prices. One prominent analyst commented “U.S. natural gas production is heading firmly downwards.”
History has not worked out that way. High prices from 2003-2008 stimulated massive increases in reserves and a huge rise in production, which has left the country awash with gas.
Higher prices and improvements in exploration and drilling technology are extending the volume of conventional oil that can be considered recoverable. Reserves are now being developed from much deeper in the earth’s crust. As IEA says, the average depth of production from offshore wells has tripled in ten years.
With its exclusive focus on “conventional” oil production, peak oil also “frames” the question in the wrong way.
First, the definition of “conventional” changes over time as a result of price and technology. Deepwater oil only became conventional 20 years ago, and ultra-deepwater in the last decade. In future, higher prices and technology changes could eventually shift ocean and arctic output into the “conventional” category and increase the reserve base substantially.
Second, the focus on conventional oil obscures the much larger reserve base of other hydrocarbons — natural gas, coal, bitumen (oil sands), and kerogen (oil shale), let alone methane hydrates (natural gas trapped in ice formations at the polar ice caps, in the permafrost zone and on the ocean floor).
Using the IEA's conservative assumptions about recovery rates, conventional crude accounts for only 10-20% of the hydrocarbon reserve base. Shale oil, oil sands and natural gas and coal could all provide huge extensions. Crucially, most of these other hydrocarbons are located outside the Middle East (here).
With the exception of methane hydrates, technology for recovering all these hydrocarbons is already in commercial use, as is technology needed to turn natural gas and solid fuels into liquids that can be used in the transport sector.
The question is cost. Most techniques are expensive compared with drilling and refining conventional crude, though not excessively so ($40-120 per barrel). They tend to be energy intensive (so the net energy gain is lower than with conventional crude). But they are workable and feasible.
Blinded by their obsession with physical availability of conventional oil, peak oilers miss the much larger questions: how much will these alternative hydrocarbons cost and what happens to the environment if we combust them all and don’t find a way to trap the CO2?
Edited by David Evans