|Eintime Conversion for education and research 05-14-2006 @
Copyrighted by originating associated source: Original
March 15, 2002
Persian Gulf Oil Is Still Critical,
But U.S. Grows Less Dependent
By THADDEUS HERRICK, MARC LIFSHER and JEANNE WHALEN
Staff Reporters of THE WALL STREET JOURNAL
In Venezuela, American energy companies have invested billions of dollars to pull up once-worthless, nearly solid crude oil and turn it into gasoline and jet fuel. In Canada's northern Alberta province, U.S. and Canadian companies are drawing new oil from gravel-like "tar sands." And in Russia, Soviet-era oil-production facilities have sprung back to life after years of neglect.
The upshot: The U.S. and the rest of the industrialized world are quietly growing less dependent on Middle Eastern oil. Producers, often relying on innovative drilling and refining technology, are tapping previously inaccessible or unusable reserves in places as diverse as Malaysia and the deep water off Brazil's Atlantic coast.
All of this activity is enlarging world supplies and diminishing the ability of Saudi Arabia and its Persian Gulf neighbors to push up prices by collectively cutting their production.
Dependence on Middle East oil for decades has been a central concern of U.S. diplomacy, national-security policy and domestic politics. In the wake of the Sept. 11 attacks and President Bush's declaration of war on terrorism much of which emanates from the Middle East -- the danger of disruption of Persian Gulf supplies has risen. But while fear of this risk caused prices to soar to nearly $30 a barrel in the days immediately after Sept. 11, they soon fell back, in large part because of the proliferation of petroleum sources in recent years. This week, oil is trading at about $24 a barrel.
President Bush and other advocates of increased production in places such as Alaska's Arctic National Wildlife Refuge invoke the cause of greater U.S. energy independence. But politics and national security haven't driven the little-noticed reduction in reliance on the Middle East. Instead, the energy industry's search for ready supplies and profits has powered the trend. In the case of Russia, relative political stability since 2000 has spurred new investment in previously mismanaged Soviet-era facilities.
In the short term, decreased dependence means that President Bush can consider limited military action against Iraq without serious worries of panicking oil markets or severely boosting prices at U.S. gas pumps. It also helps that OPEC has some seven million barrels of readily available spare capacity which could make up for any loss of Iraqi oil. If an American attack evolved into full-scale war, however, it could set off an oil crisis.
OPEC Will Meet in June, May Boost Production Then1
When the Organization of Petroleum Exporting Countries gathers Friday in Vienna, a giant topic will be Russia, which, for the moment, ranks as the world's leading producer. Russia increased output last year by 500,000 barrels a day, while OPEC cut production to prop up prices.
The Middle East, to be sure, holds a dominant two-thirds of the world's proven reserves, and the region will retain considerable influence even if production elsewhere continues to grow. Saudi Arabia has 25% of the Middle Eastern reserves, or 250 billion barrels. Together, Saudi Arabia, Iran and Iraq are responsible for about 20% of world production.
Still, as the recovering U.S. economy rekindles oil demand and pushes up prices, countries outside of the Middle East will produce a growing share of the world's crude oil.
The U.S. imported 23.5% of its oil from the Persian Gulf last year, down from 27.8% in 1977. This decrease is significant because the U.S. is increasingly looking for oil abroad but has still managed to reduce its reliance on the politically unstable Middle East. American domestic production has steadily declined as oil fields are depleted, while U.S. consumption is back up to the level of the late 1970s. (U.S. imports from the Middle East dropped as low as 16.9% in 1996 but have crept up more recently as Gulf War sanctions on Iraq were eased, allowing it to boost exports.)
Mexico for the moment has displaced Saudi Arabia as the No. 1 exporter to the U.S. because of the OPEC production cuts. Canada and Venezuela, the only Latin American OPEC member, are close behind. Today, 48.6% of U.S. imports come from the Western Hemisphere, compared with 34.5% in 1980, according to the research arm of the U.S. Department of Energy.
American production peaked in 1970 at 9.6 million barrels a day and has shrunk since then. Today the U.S. holds less than 5% of the world's oil reserves and produces fewer than six million barrels a day. Much of the oil overseas is more plentiful and accessible -- and therefore cheaper to produce.
Meanwhile, U.S. consumption jumped 17.6% between 1991 and 2001, as Americans built bigger houses, bought gasoline-hungry sport-utility vehicles and took more plane flights. The country now uses about 20 million barrels of oil a day and imports 60% of that amount.
Increasingly, those imports are coming from places such as northern Alberta. Producers such as Conoco Inc. and Exxon Mobil Corp. have invested $4 billion there since 1996 in the oil consortium Syncrude. Another $4 billion is expected by 2007. The group collects rocky tar in a process that resembles strip-mining of coal more than oil drilling. The tar is hauled away and heated to separate the rocks and then refined into gasoline and other products. The investments over 11 years are expected to double production by 2007, to 500,000 barrels a day.
Last year, Petrobras, Brazil's state oil company, began production off the Atlantic coast in 8,500 feet of water, a breathtaking logistical feat. Petrobras and other deep-water explorers have cut costs by fine-tuning equipment that creates three-dimensional pictures of reserves beneath the ocean floor. The pictures show where the most promising pools of oil lie within a field estimated to hold 1.3 billion barrels of reserves.
In Venezuela, the national oil company, Petroleos de Venezuela SA, as well as Conoco, Exxon Mobil, ChevronTexaco Corp. and others have invested a total of $14 billion since 1996 to pump and upgrade tar-like crude oil along the Orinoco River. The oil there is still much less accessible than that of Saudi Arabia and therefore costs more to produce. But industry officials estimate that the Venezuelan reserves could exceed those of Saudi Arabia.
In years past, the nearly solid heavy oil near the Orinoco had only marginal value as a cheap, highly polluting boiler fuel not used in the U.S. Today, the Orinoco project, 125 miles south of the Caribbean coast, is one of the most closely watched in the industry.
At work in Orinoco: new drilling technology and refining methods that allow producers to efficiently extract the heavy oil and turn it into mid-grade crude. The mid-grade can then be further refined for use in the U.S. and elsewhere as gasoline, heating oil and jet fuel.
The Orinoco operations are already producing more than 200,000 barrels a day, and output is expected to triple by 2006. The first shipment of refined heavy crude left Venezuela for a Conoco refinery in Lake Charles, La., in early March 2001.
Teams of engineers from each of the companies involved at Orinoco work from air-conditioned control stations, where they use satellites and global-positioning devices to monitor the exact location of whirling drill bits. Computers compare that information with three-dimensional seismic images of the same underground area, so that minute adjustments can be made to the drilling trajectory. All of the data are continually updated on "intranet" Web sites, so that engineers and executives in Caracas and Houston can log on and follow the drilling.
At the wellheads, under the searing skies of the Venezuelan savanna, roughnecks and engineers drill a main well and then push out sideways in a series of horizontal perforations. This relatively new method has allowed the companies to avoid drilling numerous separate wells, greatly reducing costs. The Orinoco heavy crude comes to the surface either with the latest super-powerful pumps, or with the help of injected steam, which heats the oil to help it flow.
To move the gooey pitch, with its telltale, rotten-egg sulfur smell, the oil companies use an innovative process to dilute it with naptha, a petroleum derivative. The crude goes north by pipeline to a new complex near the Caribbean port of Jose. There, the companies heat the oil to very high temperatures until it becomes low enough in sulfur and light enough to be shipped to Venezuelan and U.S. Gulf Coast refineries.
Producers say they can make profits on the Orinoco heavy crude as long as prices stay above $12 a barrel -- which they ordinarily do. Conoco has discussed doubling the output of its year-old production facility in Venezuela. Exxon Mobil sent its first shipment to Chalmette, La., last August. TotalFinaElf SA of France and Norway's Statoil ASA are expected to start production in Venezuela this spring.
Long term, Orinoco production could be hurt by a controversial 2001 law that increases Venezuela's royalties on future projects to 20% to 30%, up from 1%. Existing projects are partially exempted. The law also requires that Venezuela have majority control of all future projects, which could discourage foreign investment.
Oil flows into a global marketplace, so increased supplies from almost anywhere can make it harder for Persian Gulf producers to keep prices high. The sources are diverse. The United Kingdom already produces more oil than Abu Dhabi, and Angola is expected to be producing more than Kuwait in coming years.
While Russia is too far away to be a direct U.S. supplier, its production has grown 15% in the last two years, to seven million barrels a day, making it a bigger player in the world market. Mikhail Khodorkovsky, head of oil producer OAO Yukos, says Russia may not climb back to its peak Soviet-era production level of 11.5 million barrels a day, but it can act as a "safety valve" to ease world prices if they get too high.
While Russia's share of overall export markets is smaller today than in the late 1980s, much more Russian oil now reaches international "spot" markets, where it affects short-term prices. In the 1980s and earlier, more Russian oil was sold to other governments under long-term contracts that had little effect on world prices.
Russian oil companies project that their output could grow another 14%, to eight million barrels a day, by 2005. Exports outside the former Soviet Union last year grew 7%, to about 4.2 million barrels a day, according to Petroleum Argus, a British publisher of energy newsletters.
A key to Russia's production surge is a change in mentality. At the height of Soviet oil production in the 1980s, Siberian oilmen were told to pursue ambitious production targets at any cost. In the oil-rich Tyumen region, workers drilled too many holes on some fields and pumped too much water into wells to boost output. The sloppy development eventually caused damage and eroded production.
After state financing collapsed along with the Soviet Union in 1991, production gradually decreased by almost 50%, to six million barrels a day in 1996. Privatization in the mid-1990s was supposed to help, but the tycoons who bought Russia's oil fields mostly pocketed their proceeds, rather than reinvesting to maintain or improve facilities. As political stability has grown since 2000 under Russian President Vladimir Putin, these same businessmen are investing in their long-neglected fields and focusing on improved efficiency.
Foreign investors over the past year have expressed growing interest in Russia, but Russian oil barons are reluctant to welcome competition. The Russians so far have persuaded their legislators not to enact laws that foreigners say are needed to protect outside investments in energy there. Mr. Putin has promised to press for the legal protections.
For now, foreign activity is mostly limited to Sakhalin Island in the Far East, where a group led by Exxon Mobil has agreed to invest up to $12 billion in an offshore oil-and-gas project. A consortium led by Shell plans to spend as much as $8.5 billion on the island, while BP PLC says it hopes to begin exploring there soon.
In the future, up-and-coming technologies could expand the world's oil supply even further. An approach known as gas-to-liquids is expected to produce large amounts of fuel in Asia and Africa, among other areas.
This method puts to use abundant natural gas that is often located too far away from consumers that use that fuel. Using chemical catalysts, energy companies can turn the gas into clean-burning fuels, which then can be used locally or moved to ports for shipping.
Large-scale use of the technology is still a ways off. It could provide a million barrels of oil a day by 2020, industry officials estimate. World-wide consumption today is 75 million barrels.
But the industry is pushing ahead, in part because the technology produces low-sulfur fuels that can meet tough new environmental regulations scheduled to go into effect in Europe and the U.S. in coming years.
Royal Dutch/Shell Group, which operates a gas-to-liquids plant in Malaysia producing 12,500 barrels a day, says it has plans to spend some $6 billion in coming years to build up to four plants that could each produce 75,000 barrels a day. The company is studying potential sites in Asia, Australia and Latin America.
Chevron, working with South Africa's Sasol Ltd., is investing in a plant in Nigeria that will produce 33,000 barrels a day when it is completed in 2005. Conoco is building a 400-barrel-a-day demonstration plant in Ponca City, Okla., and plans to invest up to $150 million in gas-to-liquid technology this year.
Write to Thaddeus Herrick at email@example.com, Marc Lifsher at firstname.lastname@example.org and Jeanne Whalen at email@example.com
URL for this article:
(Original Len: 15067 Condensed Len: 14724)
Created by Eintime:CondenseHtmlFile on 060514 @ 17:24:02 CMD=RAGSALL