Text II

Clean Coal, a Global Failure in the Making

By Chris Morrison | Oct 30, 2009

Here’s a bit of unalloyed pessimism for you: Carbon capture and sequestration (CCS), more widely known as clean coal technology, is not going to work out. Governments and the coal industry are trying to bite off too much at once.

In theory, clean coal is a fine idea. The process of burning coal releases gases, which all modern plants already “scrub” off harmful substances like sulfur dioxide.

To fight global warming, coal mine and plant owners want to do the same for carbon dioxide.

Sounds great, except that a fairly average-sized 1,500 megawatt coal plant produces about three billion tons of CO2 yearly (update: This figure is closer to yearly emissions from all U.S. coal plants. A reader notes that the correct number is around 12 million tons per year, per plant.). All that CO2 has to be separated out, a process that uses up a lot of the energy the plant produces. Then, according to current thinking, we must bury the CO2 and hope that it doesn’t come back up.

That’s a hell of a challenge. A report released Thursday by the pro-CCS Global Carbon Capture and Storage Institute (GCCSSI) helps outline just how much.

A few bullet-points: projects exist today, and all are attached to gas plants

!$ ullet !$ The GCCSSI expects national governments to coordinate to give $100 billion yearly to CCS research.

!$ ullet !$ Provided the money is forked over immediately, we might have 20 plants by 2020.

!$ ullet !$ And if those initial plants work out as expected it will take until 2030 to have a significant number operating.

!$ ullet !$ If the technology works as expected, it will add an average of 78 percent to the cost of electricity from coal.

Anyone familiar with the basics of risk wouldn’t bet on that many “ifs”, especially given the looming difficulty of not only coaxing governments to throw trillions of dollars into research, but also share the technology as it develops.

Nevertheless, everything could work out perfectly and clean coal could be spreading in 2030. By that time, CO2 concentrations in the atmosphere may be over 500ppm. That’s no problem if the climate change skeptics are right; if the 97 percent of climatologists who study climate change are right, that number would mean we’re in for some major upheaval.

In other words, we need better solutions, right now. For coal, there are already some available. Old, inefficient plants can be shut down in favor of new ones that operate at a much higher thermal efficiency, and work on new concepts like underground coal gasification could be accelerated.

The $2.4 trillion the International Energy Agency says we should spend researching clean coal should also be spent other ways; research and investment into renewables like geothermal and solar power come to mind, and it’s also enough money to buy several hundred nuclear plants.

If we do insist on clean coal, the concept needs a rethink. Trying to figure out the most cost-effective way to scrub CO2 is enough of a challenge. The additional problem of permanently sequestering it underground adds too much expense and uncertainty.

There are better ways. One would be to use the CO2 to create liquid fuels for transportation. Oddly, this idea is rarely brought up in the debate over clean coal, although scientists are already working on ways to use CO2 they captured from ambient air for fuel.

It’s a more energy-intensive process (read: expensive) process to capture CO2 from the air around us than the flue of a coal plant, where it’s already highly concentrated. But the attitude toward CO2 from coal is that it must be buried, because it’s new to the atmosphere — nevermind whether the fuel could replace a petroleum product, which also emits new CO2.

But the thinking on clean coal is, for the moment, quite rigid. One can only hope that, in the wholesale rush toward what seems immediately sensible, we don’t forget one of our best weapons — creativity, and adaptation to new circumstances.

Chris Morrison, a reporter on energy, renewables and climate change,

is the former lead cleantech writer for VentureBeat.

http://www.energytribune.com/articles.cfm?

aid=2517, retrieved on 22 December 2009.

The author’s communicative intention in Text II is to

Text I

The next oil giant?

Mar 19th 2009

From the Economist Intelligence Unit ViewsWire

In the past two years Brazil has discovered the largest oil deposits in the country’s history and the world’s most promising fields since the discoveries made in Kashagan in Kazakhstan in 2000. This has put Brazil well on its way to becoming a major producer in the future, but technological and financial hurdles will have to be overcome first.

The finds are located in the Santos oil Basin, 300 km from the coast at Rio de Janeiro in south-eastern Brazil. The first discovery—the giant Tupi field—was made in November 2007. Potential reserves are estimated by Petróleo Brasileiro (Petrobras, the statecontrolled oil company) at 5-8bn barrels of oil equivalent (boe), which should make it the largest-ever deep-water oilfield discovery. Partner company British Gas is more optimistic, estimating that the field could contain 12-13bn boe.

The Tupi discovery was followed by other large finds, including Sugar Loaf, to the south-west of Tupi, in December 2007, and the Jupiter natural-gas field, located east of Tupi, in January 2008. The three fields constitute the largest hydrocarbons discoveries in the cluster area of the Santos Basin. The government estimates reserves at Sugar Loaf could be even larger than those of Tupi, at around 33bn boe, and that the Jupiter field could have “similar dimensions” to Tupi.

Other discoveries in the area include Parati, Bem te-vi, Carioca, Iara, Tupi Sul and Iati.

The president of the Agência Nacional de Petróleo (ANP, the industry regulating agency) puts total potential reserves in the Santos Basin at 80bn boe. If the new discoveries are found to be commercially viable, Brazil could become one of the world’s major oil-producing and exporting countries.

Two successful wells—Caramba and Guara— have already been drilled in the Sugar Loaf field by Petrobras in association with Portuguese Galp Energy in the first case, and with BG and Spanish Repsol in the second. Projected initial production at Tupi is estimated at 100,000 barrels/day under a pilot project scheduled to start next year. In the medium term, production from Tupi alone is expected to reach around 1m b/d by 2012.

With oil production averaging 1.9m b/d in 2008, the extra capacity might lift Brazil’s output to levels similar to Latin America’s two main oil producers, Venezuela and Mexico, who both produce 2.5-3m b/d.

Yet full development of the fields will pose serious geological challenges. The onset of a sharp global economic slowdown will throw up further complications, as financing constraints hinder investment and lower oil prices bring into question the government’s preference for a production-sharing (rather than concessionary) framework.

The reserves are located in the so-called “presalt” area (below the thick salt layer and more than 4km below the sea bed, under a series of layers of rock and salt). Until now, Brazil’s reserves have been found in post-salt formations—above the salt layer.

The depth of the oil reservoirs is not the main challenge, since Petrobras ranks among the world’s bestqualified companies in offshore deep-water exploration and is already exploring fields located at a similar depth.

The depth and thickness of the salt formation poses more problems. Unlike drilling through rock, which can be difficult owing to its thickness but once drilled remains stable, it is tough to maintain the dimensions of the hole after drilling through salt. Another challenge is the temperature shock of the oil as it travels up to the surface.

The technology needed and the subsequent development and maintenance of the reservoirs will be expensive. The development cost of each sub-salt well is estimated at US$100-150m, and Tupi alone could require as many as 200 wells. Developing the entire Tupi area could cost around US$600bn over the life of the wells. Unexpected geological or operational issues— such as longer drilling times, and increases in the rental costs of rigs—could further raise costs. The availability of deep-water rigs could also delay Brazil’s oil plans, as globally these are in short supply.

Extracted from THE ECONOMIST

http://www.economist.com/

displaystory.cfm?story_id=13348824&source=login_payBarrier,

retrieved on 22 December 2009.

The following extracts were taken from the article “Is Brazil the “New Saudi Arabia’, published in Money Morning, on March 18th, 2009. The extract which is NOT aligned with the information found in Text I is

Text I

The next oil giant?

Mar 19th 2009

From the Economist Intelligence Unit ViewsWire

In the past two years Brazil has discovered the largest oil deposits in the country’s history and the world’s most promising fields since the discoveries made in Kashagan in Kazakhstan in 2000. This has put Brazil well on its way to becoming a major producer in the future, but technological and financial hurdles will have to be overcome first.

The finds are located in the Santos oil Basin, 300 km from the coast at Rio de Janeiro in south-eastern Brazil. The first discovery—the giant Tupi field—was made in November 2007. Potential reserves are estimated by Petróleo Brasileiro (Petrobras, the statecontrolled oil company) at 5-8bn barrels of oil equivalent (boe), which should make it the largest-ever deep-water oilfield discovery. Partner company British Gas is more optimistic, estimating that the field could contain 12-13bn boe.

The Tupi discovery was followed by other large finds, including Sugar Loaf, to the south-west of Tupi, in December 2007, and the Jupiter natural-gas field, located east of Tupi, in January 2008. The three fields constitute the largest hydrocarbons discoveries in the cluster area of the Santos Basin. The government estimates reserves at Sugar Loaf could be even larger than those of Tupi, at around 33bn boe, and that the Jupiter field could have “similar dimensions” to Tupi.

Other discoveries in the area include Parati, Bem te-vi, Carioca, Iara, Tupi Sul and Iati.

The president of the Agência Nacional de Petróleo (ANP, the industry regulating agency) puts total potential reserves in the Santos Basin at 80bn boe. If the new discoveries are found to be commercially viable, Brazil could become one of the world’s major oil-producing and exporting countries.

Two successful wells—Caramba and Guara— have already been drilled in the Sugar Loaf field by Petrobras in association with Portuguese Galp Energy in the first case, and with BG and Spanish Repsol in the second. Projected initial production at Tupi is estimated at 100,000 barrels/day under a pilot project scheduled to start next year. In the medium term, production from Tupi alone is expected to reach around 1m b/d by 2012.

With oil production averaging 1.9m b/d in 2008, the extra capacity might lift Brazil’s output to levels similar to Latin America’s two main oil producers, Venezuela and Mexico, who both produce 2.5-3m b/d.

Yet full development of the fields will pose serious geological challenges. The onset of a sharp global economic slowdown will throw up further complications, as financing constraints hinder investment and lower oil prices bring into question the government’s preference for a production-sharing (rather than concessionary) framework.

The reserves are located in the so-called “presalt” area (below the thick salt layer and more than 4km below the sea bed, under a series of layers of rock and salt). Until now, Brazil’s reserves have been found in post-salt formations—above the salt layer.

The depth of the oil reservoirs is not the main challenge, since Petrobras ranks among the world’s bestqualified companies in offshore deep-water exploration and is already exploring fields located at a similar depth.

The depth and thickness of the salt formation poses more problems. Unlike drilling through rock, which can be difficult owing to its thickness but once drilled remains stable, it is tough to maintain the dimensions of the hole after drilling through salt. Another challenge is the temperature shock of the oil as it travels up to the surface.

The technology needed and the subsequent development and maintenance of the reservoirs will be expensive. The development cost of each sub-salt well is estimated at US$100-150m, and Tupi alone could require as many as 200 wells. Developing the entire Tupi area could cost around US$600bn over the life of the wells. Unexpected geological or operational issues— such as longer drilling times, and increases in the rental costs of rigs—could further raise costs. The availability of deep-water rigs could also delay Brazil’s oil plans, as globally these are in short supply.

Extracted from THE ECONOMIST

http://www.economist.com/

displaystory.cfm?story_id=13348824&source=login_payBarrier,

retrieved on 22 December 2009.

“Tough conditions and high cost” can be used as a heading for the section comprised between lines

Text I

The next oil giant?

Mar 19th 2009

From the Economist Intelligence Unit ViewsWire

In the past two years Brazil has discovered the largest oil deposits in the country’s history and the world’s most promising fields since the discoveries made in Kashagan in Kazakhstan in 2000. This has put Brazil well on its way to becoming a major producer in the future, but technological and financial hurdles will have to be overcome first.

The finds are located in the Santos oil Basin, 300 km from the coast at Rio de Janeiro in south-eastern Brazil. The first discovery—the giant Tupi field—was made in November 2007. Potential reserves are estimated by Petróleo Brasileiro (Petrobras, the statecontrolled oil company) at 5-8bn barrels of oil equivalent (boe), which should make it the largest-ever deep-water oilfield discovery. Partner company British Gas is more optimistic, estimating that the field could contain 12-13bn boe.

The Tupi discovery was followed by other large finds, including Sugar Loaf, to the south-west of Tupi, in December 2007, and the Jupiter natural-gas field, located east of Tupi, in January 2008. The three fields constitute the largest hydrocarbons discoveries in the cluster area of the Santos Basin. The government estimates reserves at Sugar Loaf could be even larger than those of Tupi, at around 33bn boe, and that the Jupiter field could have “similar dimensions” to Tupi.

Other discoveries in the area include Parati, Bem te-vi, Carioca, Iara, Tupi Sul and Iati.

The president of the Agência Nacional de Petróleo (ANP, the industry regulating agency) puts total potential reserves in the Santos Basin at 80bn boe. If the new discoveries are found to be commercially viable, Brazil could become one of the world’s major oil-producing and exporting countries.

Two successful wells—Caramba and Guara— have already been drilled in the Sugar Loaf field by Petrobras in association with Portuguese Galp Energy in the first case, and with BG and Spanish Repsol in the second. Projected initial production at Tupi is estimated at 100,000 barrels/day under a pilot project scheduled to start next year. In the medium term, production from Tupi alone is expected to reach around 1m b/d by 2012.

With oil production averaging 1.9m b/d in 2008, the extra capacity might lift Brazil’s output to levels similar to Latin America’s two main oil producers, Venezuela and Mexico, who both produce 2.5-3m b/d.

Yet full development of the fields will pose serious geological challenges. The onset of a sharp global economic slowdown will throw up further complications, as financing constraints hinder investment and lower oil prices bring into question the government’s preference for a production-sharing (rather than concessionary) framework.

The reserves are located in the so-called “presalt” area (below the thick salt layer and more than 4km below the sea bed, under a series of layers of rock and salt). Until now, Brazil’s reserves have been found in post-salt formations—above the salt layer.

The depth of the oil reservoirs is not the main challenge, since Petrobras ranks among the world’s bestqualified companies in offshore deep-water exploration and is already exploring fields located at a similar depth.

The depth and thickness of the salt formation poses more problems. Unlike drilling through rock, which can be difficult owing to its thickness but once drilled remains stable, it is tough to maintain the dimensions of the hole after drilling through salt. Another challenge is the temperature shock of the oil as it travels up to the surface.

The technology needed and the subsequent development and maintenance of the reservoirs will be expensive. The development cost of each sub-salt well is estimated at US$100-150m, and Tupi alone could require as many as 200 wells. Developing the entire Tupi area could cost around US$600bn over the life of the wells. Unexpected geological or operational issues— such as longer drilling times, and increases in the rental costs of rigs—could further raise costs. The availability of deep-water rigs could also delay Brazil’s oil plans, as globally these are in short supply.

Extracted from THE ECONOMIST

http://www.economist.com/

displaystory.cfm?story_id=13348824&source=login_payBarrier,

retrieved on 22 December 2009.

The author of this article, claims that

Text I

The next oil giant?

Mar 19th 2009

From the Economist Intelligence Unit ViewsWire

In the past two years Brazil has discovered the largest oil deposits in the country’s history and the world’s most promising fields since the discoveries made in Kashagan^(a) in Kazakhstan in 2000. This has put Brazil well on its^(a) way to becoming a major producer in the future, but technological and financial hurdles will have to be overcome first.

The finds are located in the Santos oil Basin, 300 km from the coast at Rio de Janeiro in south-eastern Brazil. The first discovery—the giant Tupi field—was made in November 2007. Potential reserves are estimated by Petróleo Brasileiro (Petrobras,^(b) the statecontrolled oil company) at 5-8bn barrels of oil equivalent (boe), which should make it^(b) the largest-ever deep-water oilfield discovery. Partner company British Gas is more optimistic, estimating that the field could contain 12-13bn boe.

The Tupi discovery was followed by other large finds, including Sugar Loaf, to the south-west of Tupi, in December 2007, and the Jupiter natural-gas field, located east of Tupi, in January 2008. The three fields constitute the largest hydrocarbons discoveries in the cluster area of the Santos Basin. The government estimates reserves^(c) at Sugar Loaf could be even larger than those^(c) of Tupi, at around 33bn boe, and that the Jupiter field could have “similar dimensions” to Tupi.

Other discoveries in the area include Parati, Bem te-vi, Carioca, Iara, Tupi Sul and Iati.

The president of the Agência Nacional de Petróleo (ANP, the industry regulating agency) puts total potential reserves in the Santos Basin at 80bn boe. If the new discoveries are found to be commercially viable, Brazil could become one of the world’s major oil-producing and exporting countries.

Two successful wells—Caramba and Guara— have already been drilled in the Sugar Loaf field by Petrobras in association with Portuguese Galp Energy in the first case, and with BG and Spanish Repsol in the second. Projected initial production at Tupi is estimated at 100,000 barrels/day under a pilot project scheduled to start next year. In the medium term, production from Tupi alone is expected to reach around 1m b/d by 2012.

With oil production averaging 1.9m b/d in 2008, the extra capacity might lift Brazil’s output to levels similar to Latin America’s two main oil producers, Venezuela and Mexico, who both produce 2.5-3m b/d.

Yet full development of the fields will pose serious geological challenges. The onset of a sharp global economic slowdown will throw up further complications, as financing constraints hinder investment and lower oil prices bring into question the government’s preference for a production-sharing (rather than concessionary) framework.

The reserves are located in the so-called “presalt” area (below the thick salt layer and more than 4km below the sea bed, under a series of layers of rock and salt). Until now, Brazil’s reserves have been found in post-salt formations—above the salt layer.

The depth of the oil reservoirs is not the main challenge, since Petrobras ranks among the world’s bestqualified companies in offshore deep-water exploration and is already exploring fields located at a similar depth.

The depth and thickness of the salt formation poses more problems. Unlike drilling through rock, which can be difficult owing to its thickness but once drilled remains stable, it is tough to maintain the dimensions of the hole after drilling through salt. Another challenge is the temperature shock^(d) of the oil as it^(d) travels up to the surface.

The technology needed and the subsequent development and maintenance of the reservoirs will be expensive. The development cost of each sub-salt well is estimated at US$100-150m, and Tupi alone could require as many as 200 wells. Developing the entire Tupi area could cost around US$600bn over the life of the wells. Unexpected geological or operational issues— such as longer drilling times, and increases in the rental costs of rigs—could further raise costs. The availability of deep-water rigs could also delay Brazil’s oil plans,^(e) as globally these^(e) are in short supply.

Extracted from THE ECONOMIST

http://www.economist.com/

displaystory.cfm?story_id=13348824&source=login_payBarrier,

retrieved on 22 December 2009.

The referent of the pronoun is indicated in

Text I

The next oil giant?

Mar 19th 2009

From the Economist Intelligence Unit ViewsWire

In the past two years Brazil has discovered the largest oil deposits in the country’s history and the world’s most promising fields since the discoveries made in Kashagan in Kazakhstan in 2000. This has put Brazil well on its way to becoming a major producer in the future, but technological and financial hurdles will have to be overcome first.^(a)

The finds are located in the Santos oil Basin, 300 km from the coast at Rio de Janeiro in south-eastern Brazil. The first discovery—the giant Tupi field—was made in November 2007. Potential reserves are estimated by Petróleo Brasileiro (Petrobras, the statecontrolled oil company) at 5-8bn barrels of oil equivalent (boe), which should make it the largest-ever deep-water oilfield discovery.(b) Partner company British Gas is more optimistic, estimating that the field could contain 12-13bn boe.

The Tupi discovery was followed by other large finds, including Sugar Loaf, to the south-west of Tupi, in December 2007, and the Jupiter natural-gas field, located east of Tupi, in January 2008. The three fields constitute the largest hydrocarbons discoveries in the cluster area of the Santos Basin. The government estimates reserves at Sugar Loaf could be even larger than those of Tupi, at around 33bn boe, and that the Jupiter field could have “similar dimensions” to Tupi.

Other discoveries in the area include Parati, Bem te-vi, Carioca, Iara, Tupi Sul and Iati.

The president of the Agência Nacional de Petróleo (ANP, the industry regulating agency) puts total potential reserves in the Santos Basin at 80bn boe. If the new discoveries are found to be commercially viable, Brazil could become one of the world’s major oil-producing and exporting countries.

Two successful wells—Caramba and Guara— have already been drilled in the Sugar Loaf field by Petrobras in association with Portuguese Galp Energy in the first case, and with BG and Spanish Repsol in the second. Projected initial production at Tupi is estimated at 100,000 barrels/day under a pilot project scheduled to start next year. In the medium term, production from Tupi alone is expected to reach around 1m b/d by 2012.^(c)

With oil production averaging 1.9m b/d in 2008, the extra capacity might lift Brazil’s output to levels similar to^(d) Latin America’s two main oil producers, Venezuela and Mexico, who both produce 2.5-3m b/d.

Yet full development of the fields will pose serious geological challenges. The onset of a sharp global economic slowdown will throw up further complications, as financing constraints hinder investment and lower oil prices bring into question the government’s preference for a production-sharing (rather than concessionary) framework.

The reserves are located in the so-called “presalt” area (below the thick salt layer and more than 4km below the sea bed, under a series of layers of rock and salt). Until now, Brazil’s reserves have been found in post-salt formations—above the salt layer.

The depth of the oil reservoirs is not the main challenge, since Petrobras ranks among the world’s bestqualified companies in offshore deep-water exploration and is already exploring fields located at a similar depth.

The depth and thickness of the salt formation poses more problems. Unlike drilling through rock, which can be difficult owing to its thickness^(e) but once drilled remains stable, it is tough to maintain the dimensions of the hole after drilling through salt. Another challenge is the temperature shock of the oil as it travels up to the surface.

The technology needed and the subsequent development and maintenance of the reservoirs will be expensive. The development cost of each sub-salt well is estimated at US$100-150m, and Tupi alone could require as many as 200 wells. Developing the entire Tupi area could cost around US$600bn over the life of the wells. Unexpected geological or operational issues— such as longer drilling times, and increases in the rental costs of rigs—could further raise costs. The availability of deep-water rigs could also delay Brazil’s oil plans, as globally these are in short supply.

Extracted from THE ECONOMIST

http://www.economist.com/

displaystory.cfm?story_id=13348824&source=login_payBarrier,

retrieved on 22 December 2009.

The verb phrase in bold conveys less certainty in the fragment

Text I

The next oil giant?

Mar 19th 2009

From the Economist Intelligence Unit ViewsWire

In the past two years Brazil has discovered the largest oil deposits in the country’s history and the world’s most promising fields since the discoveries made in Kashagan in Kazakhstan in 2000. This has put Brazil well on its way to becoming a major producer in the future, but technological and financial hurdles will have to be overcome first.

The finds are located in the Santos oil Basin, 300 km from the coast at Rio de Janeiro in south-eastern Brazil. The first discovery—the giant Tupi field—was made in November 2007. Potential reserves are estimated by Petróleo Brasileiro (Petrobras, the statecontrolled oil company) at 5-8bn barrels of oil equivalent (boe), which should make it the largest-ever deep-water oilfield discovery. Partner company British Gas is more optimistic, estimating that the field could contain 12-13bn boe.

The Tupi discovery was followed by other large finds, including Sugar Loaf, to the south-west of Tupi, in December 2007, and the Jupiter natural-gas field, located east of Tupi, in January 2008. The three fields constitute the largest hydrocarbons discoveries in the cluster area of the Santos Basin. The government estimates reserves at Sugar Loaf could be even larger than those of Tupi, at around 33bn boe, and that the Jupiter field could have “similar dimensions” to Tupi.

Other discoveries in the area include Parati, Bem te-vi, Carioca, Iara, Tupi Sul and Iati.

The president of the Agência Nacional de Petróleo (ANP, the industry regulating agency) puts total potential reserves in the Santos Basin at 80bn boe. If the new discoveries are found to be commercially viable, Brazil could become one of the world’s major oil-producing and exporting countries.

Two successful wells—Caramba and Guara— have already been drilled in the Sugar Loaf field by Petrobras in association with Portuguese Galp Energy in the first case, and with BG and Spanish Repsol in the second. Projected initial production at Tupi is estimated at 100,000 barrels/day under a pilot project scheduled to start next year. In the medium term, production from Tupi alone is expected to reach around 1m b/d by 2012.

With oil production averaging 1.9m b/d in 2008, the extra capacity might lift Brazil’s output to levels similar to Latin America’s two main oil producers, Venezuela and Mexico, who both produce 2.5-3m b/d.

Yet full development of the fields will pose^(a) serious geological challenges. The onset of a sharp global economic slowdown will throw up further complications, as financing constraints hinder investment^(b) and lower oil prices bring into question the government’s preference for a production-sharing (rather than concessionary) framework.

The reserves are located in the so-called “presalt” area (below the thick salt layer and more than 4km below the sea bed, under a series of layers of rock and salt). Until now, Brazil’s reserves have been found in post-salt formations—above the salt layer.

The depth of the oil reservoirs is not the main challenge, since Petrobras ranks among^(c) the world’s bestqualified companies in offshore deep-water exploration and is already exploring fields located at a similar depth.

The depth and thickness of the salt formation poses more problems. Unlike drilling through rock,^(d) which can be difficult owing to its thickness but once drilled remains stable, it is tough to maintain the dimensions of the hole after drilling through salt. Another challenge is the temperature shock of the oil as it travels up to the surface.

The technology needed and the subsequent development and maintenance of the reservoirs will be expensive. The development cost of each sub-salt well is estimated at US$100-150m, and Tupi alone could require as many as 200 wells. Developing the entire Tupi area could cost around US$600bn over the life of the wells. Unexpected geological or operational issues— such as longer drilling times,^(e) and increases in the rental costs of rigs—could further raise costs. The availability of deep-water rigs could also delay Brazil’s oil plans, as globally these are in short supply.

Extracted from THE ECONOMIST

http://www.economist.com/

displaystory.cfm?story_id=13348824&source=login_payBarrier,

retrieved on 22 December 2009.

The word in bold type expresses the idea in parenthesis in

Text I

The next oil giant?

Mar 19th 2009

From the Economist Intelligence Unit ViewsWire

In the past two years Brazil has discovered the largest oil deposits in the country’s history and the world’s most promising fields since the discoveries made in Kashagan in Kazakhstan in 2000. This has put Brazil well on its way to becoming a major producer in the future, but technological and financial hurdles will have to be overcome first.

The finds are located in the Santos oil Basin, 300 km from the coast at Rio de Janeiro in south-eastern Brazil. The first discovery—the giant Tupi field—was made in November 2007. Potential reserves are estimated by Petróleo Brasileiro (Petrobras, the statecontrolled oil company) at 5-8bn barrels of oil equivalent (boe), which should make it the largest-ever deep-water oilfield discovery. Partner company British Gas is more optimistic, estimating that the field could contain 12-13bn boe.

The Tupi discovery was followed by other large finds, including Sugar Loaf, to the south-west of Tupi, in December 2007, and the Jupiter natural-gas field, located east of Tupi, in January 2008. The three fields constitute the largest hydrocarbons discoveries in the cluster area of the Santos Basin. The government estimates reserves at Sugar Loaf could be even larger than those of Tupi, at around 33bn boe, and that the Jupiter field could have “similar dimensions” to Tupi.

Other discoveries in the area include Parati, Bem te-vi, Carioca, Iara, Tupi Sul and Iati.

The president of the Agência Nacional de Petróleo (ANP, the industry regulating agency) puts total potential reserves in the Santos Basin at 80bn boe. If the new discoveries are found to be commercially viable, Brazil could become one of the world’s major oil-producing and exporting countries.

Two successful wells—Caramba and Guara— have already been drilled in the Sugar Loaf field by Petrobras in association with Portuguese Galp Energy in the first case, and with BG and Spanish Repsol in the second. Projected initial production at Tupi is estimated at 100,000 barrels/day under a pilot project scheduled to start next year. In the medium term, production from Tupi alone is expected to reach around 1m b/d by 2012.

With oil production averaging 1.9m b/d in 2008, the extra capacity might lift Brazil’s output to levels similar to Latin America’s two main oil producers, Venezuela and Mexico, who both produce 2.5-3m b/d.

Yet full development of the fields will pose serious geological challenges. The onset of a sharp global economic slowdown will throw up further complications, as financing constraints hinder investment and lower oil prices bring into question the government’s preference for a production-sharing (rather than concessionary) framework.

The reserves are located in the so-called “presalt” area (below the thick salt layer and more than 4km below the sea bed, under a series of layers of rock and salt). Until now, Brazil’s reserves have been found in post-salt formations—above the salt layer.

The depth of the oil reservoirs is not the main challenge, since Petrobras ranks among the world’s bestqualified companies in offshore deep-water exploration and is already exploring fields located at a similar depth.

The depth and thickness of the salt formation poses more problems. Unlike drilling through rock, which can be difficult owing to its thickness but once drilled remains stable, it is tough to maintain the dimensions of the hole after drilling through salt. Another challenge is the temperature shock of the oil as it travels up to the surface.

The technology needed and the subsequent development and maintenance of the reservoirs will be expensive. The development cost of each sub-salt well is estimated at US$100-150m, and Tupi alone could require as many as 200 wells. Developing the entire Tupi area could cost around US$600bn over the life of the wells. Unexpected geological or operational issues— such as longer drilling times, and increases in the rental costs of rigs—could further raise costs. The availability of deep-water rigs could also delay Brazil’s oil plans, as globally these are in short supply.

Extracted from THE ECONOMIST

http://www.economist.com/

displaystory.cfm?story_id=13348824&source=login_payBarrier,

retrieved on 22 December 2009.

The problematic issues raised include all of the following, EXCEPT

Text I

The next oil giant?

Mar 19th 2009

From the Economist Intelligence Unit ViewsWire

In the past two years Brazil has discovered the largest oil deposits in the country’s history and the world’s most promising fields since the discoveries made in Kashagan in Kazakhstan in 2000. This has put Brazil well on its way to becoming a major producer in the future, but technological and financial hurdles will have to be overcome first.

The finds are located in the Santos oil Basin, 300 km from the coast at Rio de Janeiro in south-eastern Brazil. The first discovery—the giant Tupi field—was made in November 2007. Potential reserves are estimated by Petróleo Brasileiro (Petrobras, the statecontrolled oil company) at 5-8bn barrels of oil equivalent (boe), which should make it the largest-ever deep-water oilfield discovery. Partner company British Gas is more optimistic, estimating that the field could contain 12-13bn boe.

The Tupi discovery was followed by other large finds, including Sugar Loaf, to the south-west of Tupi, in December 2007, and the Jupiter natural-gas field, located east of Tupi, in January 2008. The three fields constitute the largest hydrocarbons discoveries in the cluster area of the Santos Basin. The government estimates reserves at Sugar Loaf could be even larger than those of Tupi, at around 33bn boe, and that the Jupiter field could have “similar dimensions” to Tupi.

Other discoveries in the area include Parati, Bem te-vi, Carioca, Iara, Tupi Sul and Iati.

The president of the Agência Nacional de Petróleo (ANP, the industry regulating agency) puts total potential reserves in the Santos Basin at 80bn boe. If the new discoveries are found to be commercially viable, Brazil could become one of the world’s major oil-producing and exporting countries.

Two successful wells—Caramba and Guara— have already been drilled in the Sugar Loaf field by Petrobras in association with Portuguese Galp Energy in the first case, and with BG and Spanish Repsol in the second. Projected initial production at Tupi is estimated at 100,000 barrels/day under a pilot project scheduled to start next year. In the medium term, production from Tupi alone is expected to reach around 1m b/d by 2012.

With oil production averaging 1.9m b/d in 2008, the extra capacity might lift Brazil’s output to levels similar to Latin America’s two main oil producers, Venezuela and Mexico, who both produce 2.5-3m b/d.

Yet full development of the fields will pose serious geological challenges. The onset of a sharp global economic slowdown will throw up further complications, as financing constraints hinder investment and lower oil prices bring into question the government’s preference for a production-sharing (rather than concessionary) framework.

The reserves are located in the so-called “presalt” area (below the thick salt layer and more than 4km below the sea bed, under a series of layers of rock and salt). Until now, Brazil’s reserves have been found in post-salt formations—above the salt layer.

The depth of the oil reservoirs is not the main challenge, since Petrobras ranks among the world’s bestqualified companies in offshore deep-water exploration and is already exploring fields located at a similar depth.

The depth and thickness of the salt formation poses more problems. Unlike drilling through rock, which can be difficult owing to its thickness but once drilled remains stable, it is tough to maintain the dimensions of the hole after drilling through salt. Another challenge is the temperature shock of the oil as it travels up to the surface.

The technology needed and the subsequent development and maintenance of the reservoirs will be expensive. The development cost of each sub-salt well is estimated at US$100-150m, and Tupi alone could require as many as 200 wells. Developing the entire Tupi area could cost around US$600bn over the life of the wells. Unexpected geological or operational issues— such as longer drilling times, and increases in the rental costs of rigs—could further raise costs. The availability of deep-water rigs could also delay Brazil’s oil plans, as globally these are in short supply.

Extracted from THE ECONOMIST

http://www.economist.com/

displaystory.cfm?story_id=13348824&source=login_payBarrier,

retrieved on 22 December 2009.

Venezuela and Mexico are mentioned because they

Text I

The next oil giant?

Mar 19th 2009

From the Economist Intelligence Unit ViewsWire

In the past two years Brazil has discovered the largest oil deposits in the country’s history and the world’s most promising fields since the discoveries made in Kashagan in Kazakhstan in 2000. This has put Brazil well on its way to becoming a major producer in the future, but technological and financial hurdles will have to be overcome first.

The finds are located in the Santos oil Basin, 300 km from the coast at Rio de Janeiro in south-eastern Brazil. The first discovery—the giant Tupi field—was made in November 2007. Potential reserves are estimated by Petróleo Brasileiro (Petrobras, the statecontrolled oil company) at 5-8bn barrels of oil equivalent (boe), which should make it the largest-ever deep-water oilfield discovery. Partner company British Gas is more optimistic, estimating that the field could contain 12-13bn boe.

The Tupi discovery was followed by other large finds, including Sugar Loaf, to the south-west of Tupi, in December 2007, and the Jupiter natural-gas field, located east of Tupi, in January 2008. The three fields constitute the largest hydrocarbons discoveries in the cluster area of the Santos Basin. The government estimates reserves at Sugar Loaf could be even larger than those of Tupi, at around 33bn boe, and that the Jupiter field could have “similar dimensions” to Tupi.

Other discoveries in the area include Parati, Bem te-vi, Carioca, Iara, Tupi Sul and Iati.

The president of the Agência Nacional de Petróleo (ANP, the industry regulating agency) puts total potential reserves in the Santos Basin at 80bn boe. If the new discoveries are found to be commercially viable, Brazil could become one of the world’s major oil-producing and exporting countries.

Two successful wells—Caramba and Guara— have already been drilled in the Sugar Loaf field by Petrobras in association with Portuguese Galp Energy in the first case, and with BG and Spanish Repsol in the second. Projected initial production at Tupi is estimated at 100,000 barrels/day under a pilot project scheduled to start next year. In the medium term, production from Tupi alone is expected to reach around 1m b/d by 2012.

With oil production averaging 1.9m b/d in 2008, the extra capacity might lift Brazil’s output to levels similar to Latin America’s two main oil producers, Venezuela and Mexico, who both produce 2.5-3m b/d.

Yet full development of the fields will pose serious geological challenges. The onset of a sharp global economic slowdown will throw up further complications, as financing constraints hinder investment and lower oil prices bring into question the government’s preference for a production-sharing (rather than concessionary) framework.

The reserves are located in the so-called “presalt” area (below the thick salt layer and more than 4km below the sea bed, under a series of layers of rock and salt). Until now, Brazil’s reserves have been found in post-salt formations—above the salt layer.

The depth of the oil reservoirs is not the main challenge, since Petrobras ranks among the world’s bestqualified companies in offshore deep-water exploration and is already exploring fields located at a similar depth.

The depth and thickness of the salt formation poses more problems. Unlike drilling through rock, which can be difficult owing to its thickness but once drilled remains stable, it is tough to maintain the dimensions of the hole after drilling through salt. Another challenge is the temperature shock of the oil as it travels up to the surface.

The technology needed and the subsequent development and maintenance of the reservoirs will be expensive. The development cost of each sub-salt well is estimated at US$100-150m, and Tupi alone could require as many as 200 wells. Developing the entire Tupi area could cost around US$600bn over the life of the wells. Unexpected geological or operational issues— such as longer drilling times, and increases in the rental costs of rigs—could further raise costs. The availability of deep-water rigs could also delay Brazil’s oil plans, as globally these are in short supply.

Extracted from THE ECONOMIST

http://www.economist.com/

displaystory.cfm?story_id=13348824&source=login_payBarrier,

retrieved on 22 December 2009.

Text I informs that the largest oil reserve in Brazil nowadays is predicted to be