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."
That’s very helpful and much appreciated, thank you! I would think also that with prices around $90+ per barrel that “oil sands” in Canada and “Oil shale” in the USA (I understand that those labels are not exactly accurate) become economically feasible and even quite profitable, and those are supposed to be vast deposits to rival Saudi Arabian oil???? Big problem is getting the tens and hundreds of billions of dollar investments for 10-20 year projects (or longer).....
Ok. But at what level was it producing a decade ago?
I see promise because production is building. It is a bright spot, but not a panacea.
What was your point?
What were all those dinosaurs doing, way down there?
What did I write that was not true?
Before you answer, please read my post about reserves and the rate of extraction. It is the rate of extraction which defines a peak not the reserves in the ground.
Also, read my post about the various types of reserves, and reserve growth. Believe the reserve numbers in the North Sea, and the U.S. and anywhere else western oil companies have been involved as the operators recently. Believe the Gulf States, Iran and Russia if you like, but they lack credibility. Faith is a fine thing in religion, but it is no way to evaluate our energy supplies.
Also, when analyzing EIA numbers, try to sort out unconventional reserves like tar sands from crude oil. They are only equivalent in the sense that they can be refined into similar products. Extraction rates and the costs of inputs differ enormously.
Please research new discoveries [plenty of data out there.] I’ll recap some of the high points: U.S. Discoveries peaked in the late 1930s. U.S. Production peaked in IIRC 1971. World discoveries peaked in IIRC 1969. World production of crude and lease condensate peaked [for now] in 2005.
We could see a further leg up but two years of stagnant production in the face of higher prices may be telling us something.
BTW, if the message is that those that have the oil are somehow engaged in a conspiracy to withhold it, there is a clear an element of truth in that. OPEC is after all a cartel and manipulating markets is what cartels do. When doing so, recognize that even if that is the root cause [for the sake of argument -- I don't believe that this is the root case of recent price action], it is not reasonable to expect relief because the non OPEC world isn't finding enough lower cost of production sources to bring prices back to previous levels.
I believe that they’re talking about getable, free-flowing oil as compared to mining and cooking rock to get oil.
I agree with you on the tar sands [which can be produced economically] ... maybe or maybe not on oil shale.
Shell may be on to something with their in situ process of creating a wall of frozen water around and area to be produced and heating the enclosed area to 600 degrees. It may work in scale ... or it may not.
Also, the big problem is not attaining profitability [although that is a big hurdle] but flow rate. I suspect oil shale will be helpful, and am confident that tar sands will contribute, but the scale needed is enormous and the constraints of water, natural gas, and other infra structure are daunting.
My original main point was that nothing will replace petroleum as the primary fuel of civilization until it's economically spent though. When that will be is up in the air even by your very well informed calculations IMO. I simply see no alternative edging petroleum out until it's effectively gone.
Hiding from evil white men of course. ;^)
Under the standard theory, oil came into existence from sediments rich in algae which bloomed in shallow seas. The algae died ... sank to the bottom ... the organic rich mud built up to depth and was covered with other sediments becoming shale ... the thermal gradient [the tendency for the temperatures to increase at depth] kicked in and over the course of geologic time the result was to cook the organic matter in the shale into oil. This oil being lighter than the salty water which also was present floated upward until it found a place where it could go no further [”a trap”] bounded by impermeable rocks and usually including a high spot in the formation, a fault, or maybe just surrounding parts of the formation where the porosity or permeable dropped below a certain point where the oil could no longer migrate.
If the trap itself has sufficient porosity and sufficient permeability, is large enough in terms of area and volume, and if enough oil had migrated to that trap, you have a prospective oil field.
Oil shale is theorized to be a deposit that was never buried deeply enough to become oil by cooking out of the shale. It remains trapped in the shale as “kerogen.” The process for tar sands is a little different [I must confess ignorance on the particulars] but the end result is “bitumen” which is a lot like asphalt. It lacks enough hydrogen molecules to make it flow at ambient temperatures.
Now [finally!] to your point. Natural gas may or may not come from the same source as oil. There is clearly a lot of methane [most of what is referred to be natural gas] that is not organic in nature. In any event, although oil seems to exist only at relatively shallow depths with a limit of about 15 to maybe 17 thousand feet based on rock temperatures, natural gas and some associated liquids such as propane, butane and ethane can be found in commerical quantities much greater depth [well beyond 20 thousand feet -— IIRC 25,000 feet is not out of the question.]
Now [really] the answer to your question: If is the depth within the rock, and the rate at which the rock temperatures increases as depth increases the defines the limits of the oil window. Normally 15 to 17 thousand feet is about the maximum depth for finding crude oil. Presumably because the rock was a little cooler than normal, both this find off Brazil and for Jack II the 17,000 foot level is still within the oil window.
There is an opposing theory that oil is abiotic i.e. not the result of the decay of plant matter. I see no particular merit to this theory, but in any event the observations from gas wells seems to bear out the belief that you can go very deep searching for gas, but in doing so you won’t find oil.
Thanks, very interesting info which I have not seen explained so well before!!
Thanks. You are correct. We will use oil and will we will develop substitutes for oil that closely resemble oil. It is not perfect, but it is in many ways wonderful stuff.
There is a lot of uncertainty. If we believe the OPEC spokesmen, Cambridge Energy Research Associates [CERA] or EXON spokemen, there is nothing to worry about.
If we believe the discovery trend over the past several decades, EXON’s recent production and discovery numbers, and examine CERA’s recent track record there is not a whole lot of comfort to be had in the still prevailing consensus that peak oil won’t be a problem for decades.
I apologize for repeating myself, but the problem is scale [this includes whatever might develop in terms of tar sands and shale oil.] It the peak is now or in the near future we need to do everything we can to manage the right side of the production curve.
“Shell may be on to something with their in situ process of creating a wall of frozen water around and area to be produced and heating the enclosed area to 600 degrees.”
I....uh....foresee a few technical problems in that area.
Although I would like to hire on to the team exploring this adventure.
Not really. Petrobras is active in the U.S. Gulf of Mexico and is technically competent. They aren't hidebound and slow-moving like Petroleos Mexicanos, which is much more your stereotypical socialist enterprise.
PDVSA, the Venezuelan state enterprise, has been more like Petrobras in the past, but Chavez wants to turn it into something like Pemex has been.
Even Pemex doesn't want to be Pemex any more; they are finding that the demands being placed on them by Mexico's accelerating industrial economy require them to improve.
Plant matter generally becomes dry gas. The source of oil is another type of kerogen derived from marine and lacustrine animal life, principally from copepods, very small marine organisms which have a significant amount of fatty, oily tissue while alive, which becomes, after burial, the kind of kerogen that produces liquid oil.
When heated by very high temps and under pressure, liquid hydrocarbons and kerogens become fractionated, just as in refineries, and the products are "wet gas", light hydrocarbons similar to gasoline and naptha (and sometimes referred to by old-time oil men as "casinghead gasoline" but now called "condensate", accent on the first syllable), and bitumen, which remains in the formation.
' The harder the deep hydrocarbons are fractionated by high heat, the drier the gas (i.e. lower liquid yield per million standard cubic feet) and the lighter the condensate will be. Whereas much condensate is light brown or straw-colored ("brown oil" sometimes called), the lightest is colorless and rather like lighter fluid or gasoline.
There is much more to the subject than this (a whole semester's worth of organic chemistry and geology), but these are the rudiments.
Some of the gas produced in the Gulf Coast is the aforesaid fractionated gas from deep sources (probably the Mesozoic, down below 30,000 feet somewhere) that has migrated upward through the Tertiary sandpile into the fields that have been found and exploited since about 1946. Originally possibly sour (i.e. containing sulfur), these hydrocarbons have been scrubbed by iron-bearing minerals in the overlying clastic pile, as if in a very large refinery scrubbing process. This combination of favorable factors has made U.S. Gulf Coast and Mexican Reforma-trend crudes some of the most sought-after. By contrast, West Texas and Mexican "Mayan heavy" crudes are thicker, more viscous, and contain more sulfur. Several years ago, the Mexicans found it desirable to "bundle" the Mayan crude with their Reforma Light, in order to induce American refiners to take it.
Bad news for the “peak oil” crowd.
Any idea what technique is being used to see below the salt?
Probably — but, then again, you can’t tell the difference at the pump.
If you mean those who are worried about the near term ... well not really. First of all, only a real nut would be cheering for the near term end of oil in the form of a near term rapid decline in extraction capability. These sorts of nuts exist, but they are not representative of those of us who are worried.
Beyond that, if there are 8 billion barrels of recoverable oil in this discovery, the standard version of the peak oil theory ["Hubbert Linearization" although it wasn't really M. King Hubbert's thing] would conclude that this discovery would push back the date of peak oil by about two months. This is a very simplified computation as all peak oil models assumes that new discoveries will occur and makes allowances for some level of new discoveries. If this discovery fits within the existing ultimate recoverable reserves "URR" estimate for a particular model [it should -- it is not another Ghawar] the conclusion would be that that this find has no impact on the date of the peak.
A change in the trend of discoveries, e.g. a bunch of these sorts of discoveries per year for several years or another Ghawar or two would be required to significantly change the assumed world URR and therefore the date of the peak. I am hopeful that the discovery curve will change, but much more hopeful that the peak is a few years away and that post peak decline can be moderated by managing the decline and bringing on other forms of energy.
This find would have to be repeated five times a year to put off the peak indefinitely. Once a year or once in five years won’t get it done. The peak is here, now. A misconception is that at the peak, oil production will suddenly fall, but this obviously can’t happen. Instead the peak will be broad and production might not decline much at all for a few years.
The proposed TransAlaska Natural Gas Pipeline will be going through these deposits. The product could be used there to produce oil rather than piping the gas to Chicago.
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.