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On September 2, London-based Super Oil BP Plc [London: BP], (NYSE: BP) announced the discovery of a large oilfield, dubbed Tiber, located in the deepwater Gulf of Mexico.

The field is 62 percent owned and operated by BP, while Brazil’s Petrobras (NYSE: PBR) and ConocoPhillips (NYSE: COP) own 20 and 18 percent of the find, respectively.

The technical challenges BP encountered in drilling this prospect have been immense. The field is located in waters more than 4,000 feet (1,220 meters) deep, and the total length of the well itself is more than 35,000 feet (10,685 meters)--more than 6.5 miles long from the bottom of the drilling rig to the bottom of the well.

The pressures and temperatures encountered at such depths tested the physical limits of drilling materials and technology. In fact, just a few years ago most producers and industry pundits felt drilling such a long well in deepwater was technically impossible.

For BP, Tiber is an important find and further demonstrated the company’s competence. In the deepwater Gulf of Mexico, BP is the largest leaseholder, has the largest remaining reserves and is the largest producer, pumping 400,000 barrels of oil equivalent per day.

The company suggested that Tiber will be bigger than another recent discovery made in the region, the so-called Kaskida find. Since Kaskida is estimated at around 3 billion barrels, this implies that Tiber could be one of the largest oilfields discovered anywhere in the world in the past two decades. Tiber could rival in size some of the major deepwater discoveries offshore Brazil over the past three years such as Tupi.

Not surprisingly, soon after BP announced its discovery headlines screamed about a giant new oilfield with reserves equal in size to an entire year’s worth of Saudi Arabian oil production.

Some pundits predicted that this surge of new supply would put downward pressure on oil prices, the huge reserves in the Gulf of Mexico seeming proof that global oil production can rise fast enough to meet long-term growth in demand.

As impressive as the Tiber discovery is, the latter argument just doesn’t hold water; take great care when absorbing sensationalist headlines about new discoveries. The basic problem is that many confuse oil reserves with oil production and reserves can be a misleading concept.

The reserve estimates you often hear quoted in the news are for estimates of original oil in place (OOIP), the total amount of oil contained in the reservoir. But oil and gas aren’t found in giant underground caves or lakes. These substances are actually trapped in the pores of rocks.

Some of this Tiber oil is stranded in sections of the field where the rock is impermeable--the oil can’t flow into the well. And some will simply be left behind during production; there’s no way to “pump” it out as if it were in storage.

Typically, a producer won’t recover anything close to 50 percent of the OOIP even after many decades of production. In the case of Tiber, it’s likely that even if OOIP is more than 3 billion barrels producers will only extract 500 million to 1 billion barrels of oil, a recovery rate of as high as a third.

And this production will come over decades. Don’t make the mistake of assuming that 500 million barrels of recoverable oil means producers can extract 1.35 million barrels a day over a one-year period.

The reality is that the Tiber field won’t go into commercial production until the latter part of the coming decade. And current estimates are that BP’s new deepwater discoveries will allow the firm to boost output from the current 400,000 barrels a day to more than 600,000 by 2020.

Thus, the real impact is an incremental 200,000 barrels a day of production, a nice boost for BP but barely a drop in the bucket when you consider global oil consumption of more than 80 million barrels of oil per day.

But 200,000 barrels a day of incremental production 11 years from now just doesn’t sound as exciting as more than 3 billion barrels of oil in 65 million year-old rocks under the seafloor; that reality doesn’t get much media attention.

This brings me to another common misconception about the oft-used term “peak oil.” Many investors I speak to appear to be of the impression “peak oil” means that the world is literally running out of oil. That’s not the case. “Peak” refers not to the amount of oil in the ground but to the rate at which it can be produced.

In other words, the world consumes more than 80 million barrels of oil per day, and demand is likely to grow long-term due mainly to increased consumption from developing countries.

The real question isn’t how big global oil reserves are or how much can ultimately be recovered. The question is how quickly they can be produced. If the world demand grows to 90 million barrels per day over the next five years, one of two things must change: Either prices will need to rise enough to choke back demand, or producers will need to ramp up capacity to 90 million barrels a day.

But new production from fields like Tiber in the Gulf and Tupi offshore Brazil is counterbalanced by declining production from existing, older fields.

Consider the following chart of oil production from the UK and Norway, the two main producers in the North Sea.

Source: BP Statistical Review

Production of oil from these two countries approximates North Sea production. The UK’s two major fields, Brent and Forties, went into production in 1975 and 1977, respectively. Norway’s major fields started going into production in the early 1970s and underwent major rehabilitation programs to boost production in the ’80s.

At any rate, the chart shows that not long after these giant fields entered production, North Sea oil production began to soar. The initial growth in production was rapid; the North Sea finally entered a sort of plateau period in 1995. Production peaked early this decade and has since fallen precipitously.

Although these fields will still be yielding oil (and gas) for many years to come, the production rate will continue to fall. That’s despite the fact that some estimate that many North Sea oilfields still contain 70 percent of their OOIP.

Most fields follow some version of this “bell curve” production profile. In other words, production ramps up quickly when a field is first produced because underground pressures are high; natural geologic forces drive production.

But at some point, as pressures fall, production hits a plateau. This occurs long before all the OOIP is recovered. At this point, the producer can use certain techniques to stabilize pressures and increase production. However, these factors are unlikely to do much more than simply stabilize production at relatively high levels.

The biggest beneficiaries of these trends: the oil services industry, including companies like Schlumberger (NYSE: SLB).

As production from existing oilfields decline, producers will need to drill more aggressively and use more sophisticated production techniques to stem decline rates. And as production from easy-to-produce fields wanes, producers will be forced to target ever more complex fields such as those in the deepwater.

The oil services industry is the main purveyor of that sophisticated technical know-how both to big international producers like BP and to state-owned oil companies like Saudi Aramco.

The other implication: To make such spending and development cost-effective, oil prices will need to remain elevated. Ironically, the discovery of giant new fields like Tiber foreshadows far higher, not lower, oil prices in years to come.

Source: Tiber Oilfield Spells Major Upside for Prices