Posted on 12/01/2007 5:44:49 PM PST by Graybeard58
RIO DE JANEIRO, Brazil — This country, famed for its development of sugar-cane-produced ethanol, soon could become one of the world's great oil powers — if its state-controlled energy company, Petrobras, can tap a potentially massive deposit beneath the South Atlantic Ocean.
Experts believe the deposit, in the Tupi field 180 miles off the southeastern Brazilian coast, holds up to 8 billion barrels of light oil and natural gas. If confirmed, the deposit would be the largest petroleum find in seven years and would propel Brazil to the No. 12 position in oil reserves, after the United States and ahead of Canada and Mexico.
Analysts estimate that the deposit could be worth as much as $60 billion and predict that Brazil, which last year for the first time produced as much oil as it consumed, could become a major oil exporter.
Yet the find will challenge Petrobras' reputation as one of the world's best at exploiting deep-sea oil deposits.
About 70 percent of Petrobras' oil production comes from deep-water wells, making it the world's biggest oil producer at such depths. But the Tupi deposit is deeper than Petrobras has ever drilled — under 7,000 feet of ocean water and more than 16,000 feet of rock, sand and salt, including a 1.2-mile-thick layer of rock-hard salt.
How to tap into the find has set off a technological race, spurred because the potential rewards of exploiting the deposit are so great — especially as the price of oil nears $100 a barrel.
"It's among the most complicated projects in the world in terms of deep water," said Caio Carvalhal, a Brazil-based research associate with the U.S. consulting firm Cambridge Energy Research Associates. "But Petrobras has proved in the past that it is up to the task."
Company officials have said that years of planning lie ahead, and experts estimate that the Tupi field won't start operating fully until 2013. Although the company announced the find last year, it just released estimates of its size in November. The company will have to drill more wells to better calculate the size of the deposit.
"This was the first time that we arrived at this depth, and the technology is expensive," said Guilherme Estrella, Petrobras' director of exploration and production. "The costs are elevated, but the quality of the oil brings robustness and viability to this investment."
The Tupi field is the latest landmark in a technological race to the bottom of the ocean that many say is the energy industry's future.
Already, about a third of world oil production is offshore, with as much as 15 percent coming from deep waters, said energy consultant David Llewelyn, who's worked extensively in Brazil. Some of the most promising offshore oil regions lie in the so-called Golden Triangle, made up of the Gulf of Mexico and the coasts of Brazil and western Africa.
In 2005, U.S.-based Chevron and its partners drilled the deepest offshore oil and gas well in history at 34,189 feet below sea level in the Gulf of Mexico, according to Transocean, the world's largest offshore drilling contractor, which completed the well. The deepest onshore well, at 37,016 feet, was completed earlier this year on Sakhalin Island, off the Russian coast, for ExxonMobil.
Last year, Chevron announced it had found one of the biggest oil deposits in the United States, as much as 15 billion barrels of petroleum, more than 28,000 feet below sea level in the Gulf of Mexico.
"This is where the industry has to go to make the big finds like this," said Thomas Marsh, the Houston-based vice president of the consulting group ODS-Petrodata, a world leader in offshore exploration analysis. "And a lot of money is being spent on getting the industry going where it needs to go."
Oil companies reach such ultra-deep deposits by lowering drill bits into the ocean floor through a system of pipes connected to a floating platform on the water's surface. The pipes and drills get smaller the farther into the ocean floor they penetrate. At maximum depth, they're only about 8 inches wide, which increases their chances of being damaged.
The dangers come with the intense water pressure and heat, which can damage even the hardiest of metal drills. Temperatures 30,000 feet below the ocean floor can reach 400 degrees Fahrenheit, hot enough to turn oil into natural gas.
The biggest technical challenge of the Tupi deposit is penetrating the solid salt layer, which can become a kind of gel that squeezes and resists the drill bit. The salt also can interfere with sound wave-based seismic imaging that engineers use to figure out what's below it.
The deposit's location far from the Brazilian coast also complicates the task of delivering an estimated 53 million cubic feet of natural gas daily to consumers in the project's pilot phase.
Because natural gas can't be stored, Petrobras might have to build an enormous gas pipeline that would stretch 180 miles to shore or install gas liquefaction facilities above the deposit to turn the natural gas into storable liquid.
Despite all the difficulties, Petrobras will rise to the challenge, said Marcio Rocha Mello, president of the Brazilian Association of Petroleum Geologists and a former head of the company's geosciences section.
Before confirming the Tupi find, Petrobras already had drilled 15 wells into the solid salt along Brazil's southeastern coast, mapping an undersea basin of oil and gas stretching about 500 miles long.
"We've already put a lot of training and resources into this," Rocha Mello said. "The technology involved is already fully understood. It's not going to be a problem."
Drilling the first well alone cost $240 million, and tapping the Tupi deposit will require investing at least $5 billion at the outset, Llewelyn said. Petrobras controls a 65 percent stake in the deposit, with British company BG Group and Portugal's Gal Energia controlling the rest.
Petrobras has made such investments pay off in the past largely through innovation. The company pioneered the use of floating platforms to drill wells and store oil and has come up with new ways to heat and transport extracted petroleum.
The company has tried such technology in more than two dozen countries, including in the United States, and shared its know-how with countries also looking at going deep. In the process, Petrobras has lowered its costs for finding new deposits.
And unlike state energy companies in Venezuela and Mexico, Petrobras is known as one of the best-run firms in the industry.
Innovation has come with risks, however, and even tragedy. In 2001, a Petrobras rig that was then the largest in the world caught fire and sank off the Rio de Janeiro coast, killing 11 people.
Despite such setbacks and the enormous investments required, the Tupi discovery guarantees that Petrobras will be exploring the ocean floor off the Brazilian coast for years to come.
"With a find this size, the cost isn't really an issue," said energy consultant Llewellyn. "You really just have to do it."
thanks, bfl
True.
BTW, it isn’t the amount in the ground that is the immediate concern. It is the rate at which oil can be produced. Individual wells, fields, provinces, countries and one can surmise the world as as whole follows production curves. Wells generally start out with the highest production rates they will achieve in the most productive formation they have tapped and then decline. Fields build up over time as wells are drilled until the point where new wells cannot make up for the decline of existing wells [or until they are fully drilled out] and then decline. Provinces, countries and the world are made up of fields large and small all following a pattern of rising and then declining production.
When the world as a whole fails to find enough new producers to make up for the decline curves in the existing wells, [and / or to build enough capital and energy intensive unconventional projects] the decline begins for the world. Peak oil.
At the point of peaking, there is a lot of oil left to be produced. Maybe 50 or 60 percent for light crudes ... and even more for heavies. The problem is they won’t come out of the ground are fast as they used to. Once again “peak oil”.
Are we there yet. No way to tell until after the fact, but IMO the signs don’t look good for anything beyond the next few years. One last thing: Natural gas appears to have a longer period until absolute decline. Gas exists at deeper depths [oil generally isn't found beyond 15 to 16 thousand feet as it appears to cook down] and can be produced from tight formations, shales and coal beds that could never produce commercial quantities of oil.
Thanks for explaining it so well. ~P~
Points well taken. All. But haven’t known reserves, calculated year by year, steadily gone up since oil became a commodity? I found some charts a while ago that showed a steady rise with no down turns ever. The end of petroleum just keeps getting pushed further and further out there decade after decade.
You may be surprised. The quest for Perfect EPA compliance and ZERO accidents has brought endless pondering and paperwork.
I work for big oil and have worked for big guv, the difference is funding for small projects is faster with oil.
Most if not all of the OPEC countries goosed up [sorry hardly a technical term ... but descriptive] their reserves circa 1990. This was done because production quotas were set based on reported reserves. More “reserves” = bigger quotas. A lot of production has occurred since. With no truly major finds since 1969 Saudi Arabia continues to report the same reserves. Ghawar [the granddaddy of all oil fields] is about half of Saudi production and a large portion of reported reserves when the western oil companies managed ARAMCO. With the exception of a of little [Khuff — spelling] natural gas production, production in Ghawar comes from one zone the Arab D. That zone was well mapped, explored and had been in production for a long time before the Saudis took over ARAMCO. The western oil companies knew what was there and most of that isn’t there any more. The numbers don’t add up.
Kuwait is another example. A rather small patch of desert. Quite well explored. Two million barrels of oil per day for decades and the reported reserves are basically unchanged.
Reserve growth also occurs as secondary and tertiary production techniques improve. No doubt about it. We will extract additional amounts from existing and sometimes previously abandoned oil fields. The problem once again is the rate of extraction. These fields will almost never be what they once were. We will however manage the decline by doing intelligent and aggressive things to extract more oil from existing fields. Having written that, the decline curves are nasty in the remote and offshore locations. I can make money with an existing two or three barrel a day onshore well in TX or OK if I don’t have to handle a lot of water. I have no direct knowledge of offshore costs but it is obvious that the operating costs are staggering. When well managed offshore fields go down, they often go down hard and with apparent finality. The North Sea is a classic example.
The other reserve growth category is even more slippery. Resources like the Alberta or Orinoco [spelling] tar sands / ultra heavy oils become economic at some price. At some price the US oil shales may become truly economic. When that point is reach a very large bump in reported reserves occurs. However, the means to produce those reserves don’t magically appear. By comparison, conventional oil production is easy. These require massive investment, that go way beyond a few thousand feet of 8 inch hole, casing, tubing, separators, pumps, tanks, etc.In addition, resource constraints mean that although the Alberta tar sands reserves are almost unimaginably large, extraction rates probably will never exceed two or three million barrels of oil a day. A lot of oil for sure, but the yearly decline in existing wells may higher than that hoped for five million per day number.
To keep the age of [at least relatively] cheap oil going, we are going to need something like the Brazil find or better every few months, not every seven year years. Hope that answered your question.
Did they count oil shale deposits?
The Amazon basin/delta/offshore is likely to have the biggest oil deposits in the world but the big ones haven’t been found yet.
Sounds like they just need to go a little deeper like in this example.
Oil shale is at present a “resource” not a “reserve” since it is not known how or if the stuff can be processed to produce oil on an economically viable basis. [One of the Baltic States has produced oil shales for energy from a particularly rich deposit. It is my understanding that in that instance the kerogen was not processed to make oil, the rock itself was in essence thrown in a furnace. If that is the case, the result would something like burning the worst grade of coal imaginable.]
That’s right. This is peak oil. This is what peak oil is like.
Thank you for your most informative explanations. Another question if you don’t mind: have all the world’s continents truly been well explored for potential oil & gas deposits? if ocean deposits are being found 23,000 - 35,000 below the surface of the sea might there not be a lot of land deposits/oil and gas fields at similar depths below solid ground? Have all the promising places on planet earth already been tested to such depths, or is there a way to know in geological terms that there are no more major finds to be had on land?
He's apparently never heard of the U.S. Congress.
ANWR would probably flow at 1.5 MMBPD after reach peak then likely taper off flowing for more than 30 years.
Oil sand production in Alberta Canada has been flow for 4 decades.
Not true, oil reserves have supplied a growning demand and grown after meeting the demand for nearly every for decades.
Oil Proved Reserves, All Countries, EIA 1980 - 2007 Estimates
http://www.eia.doe.gov/pub/international/iealf/crudeoilreserves.xls
Onshore:
Parts of the Canadian, and Russian Arctic and Alaska [mostly ANWR but not solely ANWR.]
Parts of Eastern Siberia [the data is lacking — the Russians may have already have tested this possibility.]
Parts of onshore Africa.
A small area in Eastern Iraq. Western Iraq is probably pie in the sky as their known giant oil fields fall in a fairly narrow band which does not include Western Iraq.
The same is also likely in Saudi Arabia which has been more thoroughly explored than the Saudis are stating publicly. The best chance for largish totally new finds in Saudi Arabia may actually be in the Red Sea rather than the Persian Gulf or “Empty Quarter” areas. Time will tell. [Saudi Arabia does have a couple of very large undeveloped fields that have been know about for a long while. These have had problems either with finding appropriate production technology or with bad oil quality / metal pollution problems. These are going into production in the next couple of years. After that?]
Offshore the list of hopeful areas is longer [Arctic Ocean, Deep Water Mexican Gulf of Mexico, more to come in Brazil, Angola maybe Nigeria or its neighbors — and admittedly a number of other places] but would we [Brazil and similarly Jack II in the U.S. portion of the Gulf of Mexico] be drilling 16,000 foot wells in 7,000 feet of water, 180 miles from shore if the easy stuff had not already been tested? The best news about this new Brazilian find as well as Jack II is the apparent emergence of techniques for exploring under salt deposits which are almost opaque to normal seismic techniques. Once again, I am by no means and expert in this area, but I don’t think they were blindly punching holes through the salt to find out what lays below.
Offshore Florida and the Atlantic Coast don’t look that encouraging, but should be opened for testing. Southern California offshore has some potential, but as I understand it, little chance for giants ... and good luck on getting CA, FL or the East Coast open in the near future.
One other thing about offshore. The Chinese claim to have discovered a very large field in shallow water [Bohia Bay?] fairly recently so I am somewhat hopeful that the best estimates from what I still consider to be the realists are low.
To return to my main point, we need a lot of success and we need it soon or we are fast approaching the peak in oil production.
Sorry about the lack of specificity, but I hope this helped.
Disclaimer: Opinions posted on Free Republic are those of the individual posters and do not necessarily represent the opinion of Free Republic or its management. All materials posted herein are protected by copyright law and the exemption for fair use of copyrighted works.