Brazilís Big Oil BetĒ Ahead
As an update to last week's oil company earnings roundup, I bring you Brazil's state-owned oil company, Petroleo Brasileiro (PBR), affectionately known as Petrobras. It may seem like same story, different day, as Petrobras announced a 20% drop in first-quarter net profits compared with Q1 2008 (due to - yawn - the global economic slowdown, lower oil prices and lower demand).
But there are some interesting things happening in Petrobras - mainly an increase in capital spending to the tune of $28.6 billion this year - up from $23 billion last year.
Why the massive billions in capital?
One word - Tupi.
Brazil is a bit of a newcomer to big oil exploration and production, compared to the pre-World War II boom days in the Middle East. But going back to 1954 with onshore drilling and expanding offshore the following year, Brazil has steadily increased its production levels for half a century.
As with most oil nations, for the first couple of decades, the majority of the oil produced in Brazil came from onshore fields, but Brazil continued to find and develop offshore sites. In 1977, the Campos Basin was opened up and began production, and by 1982, 54.4% of Brazil's domestic production came from offshore wells. By 2008, 89.5% of Brazil's oil came from offshore drilling, with 83% of the oil coming from the Campos Basin. (You can dig in to the National Production of Crude Oil stats here.) In 2008, domestic production averaged 1.85 million barrels per day of oil and natural gas. So far in 2009, Petrobras is averaging 1.99 mbpd.
Petrobras continued to explore for oil and in November of 2007, it announced the discovery of the Tupi oil reserve located in the Santos Basin off the southeastern coast of Brazil.
The oil was sweet, with sulfur content less than 0.5% sulfur by weight, and with a gravity of 28 atmospheric pressure ionization, it was in the medium-to-light oil range. In other words, it was essentially perfect for refining. And there was possibly a lot of it - 5 billion to 8 billion barrels of oil equivalent (BOE).
While Tupi is a large field - the 5 billion to 8 billion BOE is more than enough to qualify it as a "giant" field (a designation that kicks in at 0.5 billion BOE) and the largest to be found in 20 years, it's still small time compared with the real giants: Saudi Arabia's Ghawar, the world's largest oil field, has somewhere between 66 billion and 150 billion BOE. Tupi's upper estimate does land it in the neighborhood of the 20th largest oil field in the world - Iran's Gachsaran - but only in an across-the-tracks kind of way. Gachsaran has a reserve estimated between 12 billion and 14 billion BOE.
If you're wondering about who holds places 2 through 19, check out Fredrik Robelius' dissertation Giant Oil Fields - The Highway to Oil.
So Petrobras discovered the Tupi reserves in October of 2006, announced its existence to the world on November 2007 and on May 1, 2009, the first barrels of oil started flowing in an extended well test (EWT). The EWT is expected to peak at 15,000 bpd and last 15 months. By late 2010, after completion of the EWT, the Tupi Pilot Project is expected to begin, with production levels forecast at 4 million cubic meters of natural gas and 100,000 barrels of oil produced per day.
Full production at Tupi is forecast to top out at 1 million barrels of oil per day - effectively increasing Brazil's production to close to 3 million bpd. That's enough to take Brazil from the No. 16 position on the top oil-producing country list, up to No. 6 - leapfrogging over places such as Mexico, United Arab Emirates, Canada, Kuwait, Venezuela, Iraq, Norway, Nigeria, Angola and Algeria. And that's not all - Petrobras is aiming to increase overall production to 3.6 million BOE by 2013 as it continues to add new wells.
Look out big boys - here comes Brazil!
Oil field development, especially ultra-deep water development, is an expensive endeavor. Brazil's Minister of Energy and Mines Edison Lobao stated in March, "We need 270 billion (dollars) and that will be just for 10 years." In order to complete these projects, Petrobras has dug into its own coffers - the company announced an investment plan of $174.4 billion from 2009-13 which includes $28.6 billion this year (up from $23 billion in 2008). But there's no way it can go solo, so like most oil nations, Brazil is bringing in partners. For the Tupi well, Petrobras holds 65%, with BG Group (BG.L) taking 25% and Spanish company Galp Energia (GLPEF.PK) owning the remaining 10%.
There are a few reasons why this project is expensive, but one big one: location, location, location.
Tupi is located 290 km (180 miles for those of us educated in the U.S.) off the coast of Brazil - basically the distance between Seattle and Portland, Ore. This distance adds the difficulty and expense of processing and transporting the well products to shore. Every single piece of rebar, every worker, every spare part has to get on a boat or a helicopter to make that trip.
Once you're all the way out there, the water is 2,140 meters deep (1.3 miles), which qualifies the site as "ultra deep" water in oil business lingo. And if that is not enough, once the equipment hits the sea floor at 2,140 meters, the real fun begins.
The first barrier is called the post-salt layer. It's around a kilometer thick. The good news is that Petrobras already had a lot of experience dealing with this type of geology - this is the layer in which production currently occurs. After the post-salt layer, there is a 2 km layer of salt - not the hard, familiar salt you'd find on an onshore salt mine, but a pasty concoction that requires special equipment and techniques for drilling through without busting the rig. Once that layer is drilled through, you arrive at the pre-salt layer. That's the money layer. Not a pool of oil to pump out, but a layer of reservoir rock that holds the reported 5 billion to 8 billion barrels.
Once the oil is reached, it has to be brought to the surface, and that presents its own set of challenges. For one, the oil temperature at drill depth is high - around 100 degrees Celsius. Once the recovered oil reaches the water level, the temperature drops to about 4 degrees Celsius. Obviously, the engineers have solved these problems, at least enough to begin with the extended well test, but there are sure to be more challenges to solve as the well ramps up production. And that means money - lots of it.
Is it sustainable? And by that I mean, will oil prices support continued development of the project? The U.S. Energy Information Administration just recently released a report forecasting oil demand to drop by 1.8 million bpd this year, bringing oil demand to 2004 levels. As far as prices go, the EIA is forecasting U.S. crude prices to average $52 in 2009 and $58 for 2010. In April, Petrobras' CFO Almir Barbassa stated in April that oil from the pre-salt area would be competitive at under $40 a barrel. If that holds true, then Petrobras will indeed have something to celebrate.
The news here is simple: The oil is indeed flowing. So all of these hurdles have been overcome, at least on a small scale. And that clears the way for a very different worldwide oil map within a few years.
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March 2nd, 2021
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