PEAK OIL….PART 2….When we last left the subject of peak oil, ExxonMobil had conceded that within a few years the daily production rate of oil in non-OPEC countries will peak and then begin an irreversible decline. I’m going to say more about that subject shortly, but before I do, I want to back up a bit and answer a basic question: Everyone agrees that there’s plenty of oil still left in the ground, so why should production rates peak in the near future at all? What’s up?

I’m a sucker for historical documents, so here’s where it all started: in Figure 21 of “Nuclear Energy and the Fossil Fuels,” a paper delivered by Shell geologist M. King Hubbert in 1956. Using basic principles of oil extraction, he predicted that oil production in the continental United States would reach its highest point in 1970, after about half the total oil in the ground had been extracted. He turned out to be right: U.S. oil production peaked in December 1970 and has been falling off ever since. Today the continental United States produces about 50% of the daily volume that it did in 1970.

But why? This doesn’t make sense if you think of oil fields as underground swimming pools with straws in them. After all, you can suck soda out of a glass at the same rate until you get to the very bottom. Why not with oil?

The answer is that oil fields aren’t like underground swimming pools. They’re more like underground formations of styrofoam, with oil hidden in the nooks and crannies. Oil wells are drilled into pockets in the styrofoam and keep producing oil until they run dry.

Normally, the biggest, best oil pockets are put into production first. These pockets contain clean, high-pressure oil, and when newly drilled wells are uncapped, that clean, high-pressure oil shoots to the surface in vast quantities.

Over time, though, the pressure decreases. Gas caps develop above the oil that makes extraction more difficult. Underground water begins to contaminate the oil pocket, a problem made worse by water that’s deliberately injected into the reservoir in an effort to keep pressure from declining too much. The result is that not only does the oil flow to the surface more slowly, but the oil that gets there is increasingly made up of water. In old wells, the “water cut” can account for as much as 50% or more of the extracted fluid.

New wells are drilled to make up for this, of course, but the oil that’s left is usually in smaller, lower quality pockets that age even faster than the original pockets. At some point, new wells just can’t make up for the falling production in the older wells, and the daily production rate of the entire field goes into decline. Advanced technology can be used to reinvigorate old wells and slow down the decline, but nothing can stop it. In fact, if you try to overproduce a field, all you do is hasten its ultimate demise.

In 1956 this was theory. Today it’s a routinely accepted factor in oil field maintenance, one that applies to all oil fields. Prudhoe Bay, for example, peaked in 1989. The North Sea peaked in 1999. China’s massive Daqing field probably peaked a year or two ago. They all still have plenty of oil left, but their daily production rates are getting lower and lower every year.

There’s more to the story, of course. What about new discoveries to make up for declines in older fields? What about OPEC’s fields? Are they in decline too? What about oil shale in Colorado, tar sands in Canada, and heavy oil in Venezuela? And won’t new technology keep old fields producing at higher rates than we expect anyway?

I’ll take that up next.

Continue to Part 3.

UPDATE: In comments, RedDan provides a more complete and accurate description of oil field geology than “sort of like styrofoam.” However, after reading it you’ll probably understand why I stuck with the simple analogy.

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