Untitled Document

Global Oil Hot Spots
Geotimes staff

As consumers continue to face higher gas prices at the pump, petroleum geologists continue to search the world for oil and natural gas. Despite political instability and, in some cases, war, efforts are moving forward in several new and old “hot spots” for oil production. From Iraq and offshore Africa to Canada and Russia, the challenges facing modern oil production are more complex than ever. But technological innovation and new investment strategies are leading the way.

Sidebar: Libya
Sidebar: Venezuela

Iraq’s oil sector still in turmoil

Every few days it seems, oil production in Iraq screeches to a halt as saboteurs systematically bomb the pipelines carrying what precious oil can be pumped by dilapidated and outdated systems. These ongoing security issues combined with looting, sabotage, corruption and a lack in some places of basic services, such as electricity and sewage systems, mean that Iraq has a long road ahead. Heavy outside investment is necessary before the country can reach a production rate of 6 million barrels of oil a day by 2010 — a goal some people say is unattainable.

In October, Iraq was producing about 2.6 million barrels of oil a day, up from a production average of 2 million barrels of oil a day in the first six months of this year. Nevertheless, where Iraq’s oil sector was one year ago is not too different from where it is today and where it will likely be a year from now, says James A. Paul, executive director of the U.N. Global Policy Forum in New York City.

Iraq’s reserves rank among the largest in the world. The Energy Information Administration estimates that the 438,000-square-kilometer nation holds 115 billion barrels of oil in “proved reserves,” which refers to oil that has been discovered and that can be extracted profitably under current conditions. Other estimates put the total reserves — including as-yet undiscovered oil — as high as 300 billion barrels or as low as 120 billion barrels (see Geotimes, October 2003).

Part of the reason for the discrepancy in estimates is that just over 10 percent of the country has been explored, and virtually no exploration has occurred over the past two decades, says Mohammad Al-Gailani, managing director of GeoDesign Limited in London. This range of reserves estimates is precisely why outside companies need to get into Iraq to help develop and explore the fields, he says.

“There is a lot of potential for new discoveries,” as well as for development of current fields, says Robert Ebel, energy chair at the Center for Strategic and International Studies in Washington, D.C. But the oil fields and pipelines are in bad shape, Ebel says, and Iraq needs a lot of work before it can even get back to where it was before the war, much less begin exploring or producing new fields.

“In Iraq, there are two ways to go: You can come in and work on ‘brown fields’ — fields that are known and somewhat developed — and restore those fields to good health, or you can come in and develop ‘green fields’ — fields that are completely undeveloped,” Ebel says. The place to start is with reservoir studies in current fields — drilling more exploration wells in the “developed” fields and doing more geophysical testing, says Walter Pierce, a consulting geologist who owns WHPierce Exploration in Cypress, Texas. This testing is a top priority, he says, because most of these fields do not have nearly enough test wells to adequately determine reserves, and because much of the original exploration data have been lost or are not available. “There’s not enough data to make the judgment of reserves,” Pierce says.

Beyond reserves estimation, Al-Gailani says, production facilities need to be secured and restored, as do the pipelines. Basic infrastructure reconstruction alone will cost anywhere from $100 billion to $400 billion, he says, with oil infrastructure costs on top of that. Nonetheless, he says, exploration of new fields could, and perhaps should, occur simultaneously with repair.

Iraq cannot upgrade its oil system, however, without immense outside investment from foreign oil companies, says Gal Luft, co-director of the Institute for the Analysis of Global Security in Washington, D.C. But with “the situation in flux” in Iraq, large oil companies are understandably hesitant to even go into Iraq, says Lori Feathers, an attorney at Houston-based Haynes and Boone, LLP, which advises oil companies about investments.

Companies certainly want to get into Iraq, Feathers says, and sooner rather than later. But they will not likely do much of anything until the volatile security situation is resolved and a democratically elected government is in place. It is too dangerous now, and dealing with an interim government is risky because there is no guarantee that contracts will be honored by the next regime, she says.

Nonetheless, this summer, the Iraq Oil Ministry announced the reconstitution of the Iraqi National Oil Company (which will oversee fields already producing oil), and then solicited bids from foreign companies for evaluation of two of Iraq’s biggest fields at Kirkuk and Rumaila. The evaluation projects will be the first application of updated oil exploration technologies, such as 3-D seismic, to these fields in two decades. Dozens of international companies, including BP and Shell (as reported in the Aug. 4 New York Times), bid on the contracts, which are designed to determine just how much oil is in the ground and how it can best be recovered.

Additionally, several oil companies are already providing technical assistance to Iraq, Feathers says. ChevronTexaco, for example, has been working remotely with Iraqi officials and scientists and is teaching Iraqi geologists and geophysicists about some of the new technologies and how to best develop their fields, says Andy Norman, a spokesman for ChevronTexaco.

“We’re absolutely interested in getting into Iraq,” Norman says, “but the time has to be right, and the Iraqis will be the ones dictating when” that time is. In the meantime, “we’re making strides and building relationships.”

It is good, Feathers says, that companies are getting their foot in the door and getting to know “some of the key Iraqi players.” Indeed, Luft says, building such relationships is a good beginning, but in reality, investors need a secure environment before they’ll go in, and the world needs it quickly. “With oil topping $53 a barrel, the global market has no wiggle room. There is absolutely an urgent need for Iraq’s oil.”

Meanwhile, elections for an Interim National Assembly are tentatively scheduled for this January, although the security situation may postpone them, Paul says. The assembly will then draft a national constitution. By January 2006, parliamentary elections are supposed to be held to elect a constitution-based, democratic government. Oil companies will probably not invest and go into Iraq for exploration and production, Paul says, until after the parliamentary elections produce a government with whom they can negotiate.

Megan Sever

Libya opens up

Libya’s decision to give up its programs to develop weapons of mass destruction make it an area of interest for foreign investment and a major competitor for Iraq’s oil industry, says Gal Luft, co-director of the Institute for the Analysis of Global Security in Washington, D.C. Foreign companies are rushing to get into the country because “Libya has better oil that is easier to produce,” in addition to being much more politically stable and safe, Luft says.

In September 2003, the United Nations, which had imposed sanctions on Libya in 1992 following the 1988 Pan Am bombing over Lockerbie, Scotland, lifted the sanctions in response to Libya’s cooperation regarding the case. Then in December 2003, after Libya announced the end of its weapons program, the United States began lifting its own sanctions against the nation. Since then, and with the recent release of previously frozen bank assets, U.S. companies have begun negotiating with the Libyan government for oil exploration and production contracts.

Libya holds 36 billion barrels of crude oil in proven reserves, according to figures from the Energy Information Administration (EIA), and is still largely unexplored. Analysts suggest the potential is excellent for large undiscovered reserves. In addition to being close to major European markets and having a well-developed oil infrastructure, Libya’s oil is high-quality, low-sulfur “sweet” crude oil, which takes less refining and thus is much cheaper to produce; it is the preferred oil for gasoline, according to EIA.

To entice foreign companies back into the country, the Libyan National Oil Corporation recently solicited bids on 15 blocks of land for exploration and production of oil and natural gas; the winning bids will be announced in January, according to the corporation’s Web site. The New York Times reported on Oct. 18 that the corporation had received bids from 120 different companies.

Still, a couple of barriers remain to open U.S. involvement in Libya, says Lori Feathers, an attorney with Haynes and Boone, LLP, in Houston, Texas. American companies can travel to, sign contracts with and work in Libya, but because the country is on the list of states that sponsor terrorism, there are export controls, she says. Thus, many high-tech goods that companies would export for use in or sale to Libya cannot be exported without a license from the U.S. Department of Commerce. In addition, Feathers says, Libya still has some regulations in place that are contrary to U.S. laws, including promises to abide by a boycott of Israel by a consortium of Arab states. Officials at the newly formed American embassy in Tripoli are trying to work out this and other issues with the Libyan government, she says, but it will likely take some time.

Libya is looking for $30 billion in foreign investment by 2010, hoping to increase its daily oil production to at least 3 million barrels per day. In October, the nation was producing more than 1.5 million barrels per day, with hopes of reaching 2 million barrels per day this month.

Megan Sever

Back to top

Offshore oil wealth in poor Africa

The western Atlantic margin of Africa has far more petroleum resources than previously thought, according to the U.S. Geological Survey’s (USGS) 2000 World Petroleum Assessment. The large deltas of western Africa produce good sandstone reservoir rocks and large sedimentary sequences offshore, some in water 2,000 to 4,000 meters deep. Scientists expect that 75 percent of West Africa’s mean estimated 70 billion barrels of undiscovered oil is offshore.

Advances in deepwater technology have recently increased the economic feasibility of recovering previously unreachable resources, in part fueling the oil boom that began offshore in the mid-1990s. Since then, the region has continued to be attractive to petroleum companies as an alternative to the Middle East, even though that oil wealth has not translated into better living conditions for the people of West Africa.

Citing resources in South America and West Africa, the USGS report notes the apparent emergence of a major energy-producing region in the South Atlantic. “This could lead to a significant strategic change in the intercontinental import-export flow of petroleum,” wrote geologist Ron Charpentier, coordinator for sub-Saharan Africa for the USGS World Energy Resources Team, and his colleagues.

In testimony last July before the Senate Foreign Relations Committee, David L. Goldwyn, former U.S. assistant energy secretary for international affairs, predicted that the non-OPEC countries in the west-Africa Gulf of Guinea region could provide up to 20 percent of U.S. energy needs in the coming years. He noted that governments there are open to Western investment and have good relationships with the United States.

By and large, the United States would prefer to get oil from non-OPEC countries for “easy supply,” says Tony N. Enyia, a petroleum economist with Royal Dutch/Shell in Lagos, Nigeria. And compared with the Middle East as a development region, he says that West Africa’s political and religious climates play “salutary roles.” But the region is far from being geopolitically stable. “Political risk is fairly high in a lot of African countries,” Charpentier says. “That’s almost always a consideration.”

In Nigeria, Africa’s top oil-producing country, 70 percent of the population lives in poverty. In one of the country’s most impoverished regions, the oil-rich Niger Delta, two rival militias, one led by Mujahid Dokubo-Asari and the other led by Ateke Tom, have been battling for control, demanding that some petroleum revenues be distributed among the people of the delta. The militias called a truce with each other and the government in early October, but Asari then threatened war on oil companies operating in the delta, forcing some companies to evacuate employees. The ongoing unrest has contributed to the recent upsurge in the price of oil, which reached $55 a barrel in late October.

Humanitarian organizations say that the problem of distribution of oil wealth is not limited to Nigeria. A 2003 study by Catholic Relief Services found that despite the vast wealth that oil brings to the governments of many nations, poverty is still widespread among their citizens. “Sub-Saharan African governments will receive more than $200 billion in oil revenues over the coming decade,” the study reports. “But ordinary Africans will see no such improvements so long as revenues generated by the current oil boom continue to be piped into governments lacking accountability.”

In Equatorial Guinea, a nation with a population of half a million that is the third largest African oil producer, offshore discoveries made in the mid-1990s led to an oil boom and skyrocketing annual economic growth rates of up to 40 percent. However, according to the World Bank, in 2003 the nation still had a gross national income per capita of $930.

This past summer, a U.S. Senate investigation found that oil companies may be contributing to corrupt practices there. An investigation into Washington, D.C.-based Riggs Bank uncovered payments made by U.S. companies to the president of Equatorial Guinea, Teodoro Obiang Nguema Mbasogo, and members of his family who hold prominent government positions. The payments may have violated anti-bribery tenets of the Foreign Corrupt Practices Act. A U.S. Securities and Exchange Commission probe is also investigating ChevronTexaco, Amerada Hess and Marathon Oil and their involvement in African oil payments.

Recently, there have been some efforts to make resource development around the world more transparent. In September 2002, U.K. Prime Minister Tony Blair introduced the Extractive Industries Transparency Initiative (EITI) at the World Summit on Sustainable Development in Johannesburg, South Africa. The initiative aims to “increase transparency over payments by oil, gas and mining companies to governments, and transparency of revenues received by those governments.”

And last February, Nigerian President Olusegun Obasanjo announced the establishment of an EITI stakeholders working group. “I personally have no doubt that Africa’s era to be clean, open, transparent and accountable is now,” Obasanjo said the same week, at a workshop on managing petroleum revenues in Abuja, Nigeria. “I rejoice greatly that Nigeria is and will continue to be at the forefront of the continent’s new transparent dawn.”

Both the U.K. Department for International Development, an agency charged with promoting sustainable development and eliminating world poverty, and the World Bank have announced that they will help the Nigerian government implement the policy. These and other efforts could help make African oil a more stable industry in the future.

Sara Pratt
Geotimes contributing writer

Getting Canada’s bitumen flowing

Surprisingly enough, Canada is second only to Saudi Arabia in total proven crude oil reserves, according to the Oil & Gas Journal, at 178.9 billion barrels. But the majority of these are not typical deposits: They are mostly in shallow, tarry sand reservoirs. Removing the resource and preparing it for refining is technologically difficult. Nevertheless, Canada’s “oil sands” have contributed to a recent boom in the country’s oil production and promise more for the future.

Surface mining operations for bitumen in Canada’s oil sands use some of the largest trucks in the world, several stories tall. At Syncrude’s Aurora mine, two hauling trucks empty oil-filled sand into a crushing machine. Courtesy of Syncrude Canada Ltd.

Companies have “substantial interest” in developing the sands, says Soheil Asgarpour, the Alberta Department of Energy’s business unit leader for oil sands development, in part because of the political stability, tax incentives and transparency of the Canadian system. The Canadian oil sands could “provide a solution to the North American and global energy problem,” he says.

First known as “tar sands” because of their sticky asphalt consistency, the deposits most likely started out as very large oil reservoirs that percolated to the surface after mountain-building events (called the Laramide orogeny), around 60 to 30 million years ago. Over millions of years, the lighter components evaporated, and microbes munched away at the remaining hydrocarbons, leaving a thick sludge of tarry oil that sits near the surface in what is now Alberta, says Richard Meyer, a geologist emeritus at the U.S. Geological Survey. The roughly circular deposits are principally located in the McMurray sandstone from the Lower Cretaceous (Fort McMurray is where many oil operations are based), and the oil’s quality varies from field to field, Meyer says.

Since Suncor and a consortium of other companies started the first large-scale industrial efforts there in the late 1950s, the oil-rich region has drawn more than a dozen companies to its fields, including Shell, ExxonMobil, TotalFinaElf and Japan Canada Oil Sands. From 1999 to 2002, companies spent more than $5 billion (Canadian) a year developing new projects, according to Bob Dunbar, senior director of research for the Canadian Energy Research Institute (CERI), an independent nonprofit organization in Calgary.

The estimated volume of the potential resource hovers at 174 billion barrels of crude bitumen (semisolid petroleum, like asphalt), according to a recent CERI report. The sand deposits have produced about one million barrels of oil a day for the past several years. Projects now under construction could add 160,000 barrels a day by 2007. Other proposed projects aimed at producing synthetic crude oil and unprocessed bitumen could bump the oil sands up to 3.5 million barrels a day, CERI reports — but not until 2017, and with some uncertainty as to whether those projects will proceed.

Economists have calculated that market prices of at least $25 a barrel would make extraction of oil from the region worthwhile. “In the simplest terms, the oil from these oil sand deposits is very viscous and very dense,” Meyer says. Thus, companies have to process the oil sands to make them acceptable to a refinery. “This, of course, adds to costs,” he says. Depending on the recovery methods, costs range from about $12 to $30 (Canadian) for producing crude bitumen to synthetic crude oil, according to CERI.

Companies recover some oil sands with open-pit surface mines, scooping up the sedimentary layers up to 150 feet below the surface in some places and trucking them to processing plants in trucks that can carry 450 tons of material. To prepare the substance for oil refineries, producers dilute the crude with lighter oil or hydrogen, depending on its grade, or heat it up in order to capture escaping light components, leaving only solid residues behind.

In some of the region’s more southerly fields, the oil is less viscous, “such that under normal conditions, it would flow to the well bore,” Asgarpour says. But in general, industry has had to invent a variety of ways to melt the tar in place to enhance flow. For example, one system uses parallel horizontal wells, one above the other, he explains. Steam pumped into the lower well melts the oil, which rises and then is captured by the horizontal well above. Asgarpour also notes cyclic steam stimulation, where steam is injected in a vertical well and left to soak for a while to promote well production.

But steam-pumping methods require a lot of energy to mine energy: about a thousand cubic feet of natural gas per barrel of oil produced with steam in situ, according to CERI. “Natural gas is getting to be in short supply in North America,” Dunbar says, which makes steam production fueled by natural gas more expensive, in addition to associated costs of greenhouse gas emissions. New technologies are on the horizon, however, Dunbar says, citing pilot field tests that inject solvents instead of steam to make the viscous oil flow more easily.

All of these processes have raised environmental concerns for the region. Michael Steinhacker, a contract analyst for the U.S. Energy Information Administration, says that Canada’s signing of the Kyoto Treaty, an international agreement that would control emissions of greenhouse gases, has been an issue for companies working in Alberta’s oil sands. Compliance with the treaty was “some of the reason that companies were hesitant to invest there,” Steinhacker says. “They have to look at their business plans differently,” with regard to potential carbon trading or other plans Canada might put in place in the future.

In the past few years, several consortiums of native peoples, industry and government have formed to monitor oil sands operations for adverse ecological impacts. The Wood Buffalo Environmental Association posts air quality data on its Web site daily, tracking greenhouse gases such as sulfur dioxide and others.

The Cumulative Environmental Management Association (CEMA), in cooperation with a variety of stakeholders, conducts scientific research on reclamation, air quality and other issues, to inform government guidelines and regulations. “The hot issue here right now is in-stream flow needs,” says Robert Nowosad, director of CEMA, for rivers affected by the use and release of water for both surface and in situ operations.

Asgarpour says that the government of Alberta owns the resources and manages them to “maximize the value for the people of Alberta,” while also minimizing the environmental footprint of operations to satisfy its citizens’ concerns. “With innovation and technology, I think we have the solution,” he says.

But in addition to environmental and technological concerns, Dunbar says, the region’s current rapid growth and proposed expansion mean that future concerns will include an escalating demand for skilled labor and increased demands on the region’s water supply. “There are a lot of challenges the industry faces,” Dunbar says. “But at oil prices today, the oil sands are very attractive investments.”

Naomi Lubick

Venezuela’s oil sands

Outside of Canada’s immense oil sands, which make up the majority of its exports at a million barrels of oil a day, the only other oil sands in production are in Venezuela, says Bob Esser of Cambridge Energy Research Associates. Vene-zuela exports about 2.5 million barrels a day of crude oil, according to the U.S. Energy Information Administration (EIA). One-quarter of that total comes from its oil sands concentrated in the Orinoco Belt, which produce about 500,000 barrels of crude a day.

Venezuela, a founding member of OPEC, does not have to count its bitumen (tarry oil) production as a part of its OPEC production limits. But the resource is vast, with EIA estimating recoverable reserves of bitumen deposits and heavy crude oil, mostly concentrated in the Orinoco Belt, from 100 to 270 billion barrels. (Canada has about 174 billion barrels in such proved reserves.) Because “many of the non-OPEC countries are in decline or soon to be in decline,” Esser says, Venezuelan sands may play a key role in future energy supplies.

At 3,000-foot depths, the Orinoco field’s oil sands are much deeper than Canada’s, so surface mining is not possible. Instead, companies working in the Orinoco field use steam-injection to heat and liquefy the sands for extraction, Esser says. Three-quarters of the production goes to refineries on the Gulf Coast.

The country’s oil company, Petróleos de Venezuela S.A. (PdVSA), works with ConocoPhillips, ExxonMobil, Total, Statoil and ChevronTexaco in four projects operating there now; by law, PdVSA must have at least a 50-percent stake in any future oil sands projects. By the end of the year, after another facility goes online, the Venezuelan field should start producing about 600,000 barrels a day.

Since President Hugo Chavez weathered a recall vote in Venezuela earlier this year, which had been precipitated by unrest and strikes that hampered the country’s oil industry, Esser says that “things have been pretty quiet.” While no new projects have been officially established, the major oil companies have expressed interest, he says. With high expected crude oil prices in the future and the ability to find crude to develop in the region, ChevronTexaco, Shell, BP and ExxonMobil all “find this [area] of interest,” Esser says. “But it’s going to be five or more years before we actually see this” interest come to fruition — both because of politics and because of the time it will take to develop and bring new projects online.

Esser says that Russia is likely to have similar oil sand deposits, but Canada’s and Venezuela’s are the largest and the only ones under development. Both will “become terribly important between 2010 and 2020,” he says, providing a major source of crude oil as demand grows.

Naomi Lubick

Back to top

New (and old) territory in Russia

In a country where oil reserves are a state secret and average winter temperatures regularly fall well below freezing, foreign investors are cautiously awaiting reentry to production, exploration and related activities. Despite the ominous crackdown on Russia’s oil and other business magnates, its oil fields remain a beacon for international oil companies.

The Ardalin field, a joint venture of ConocoPhillips and two Russian partners that is operated by Polar Lights Company, is the first Russian-American project to develop a new oil field in Russia. Courtesy of ConocoPhillips.

“Russia, in our view, has the capacity to produce 12 million barrels a day by 2010,” says Tim Lambert, director of energy consulting at Wood Mackenzie in Edinburgh. Those projections are based on production profiles of several hundred fields that make up 90 percent of the country’s production. Lambert notes that Russia has increased its oil exports and production by about 30 percent over the past five years, from a low point in the late 1990s (it is now at around 9 million barrels a day, according to the U.S. Energy Information Administration). “It’s a place everybody wants to be,” he says, “because reserves there are big and theoretically available.”

Russia’s oil reserves and production capacity “cannot compete with Saudi Arabia,” says Fiona Hill of the Washington, D.C.-based Brookings Institution. But the country, the world’s major non-OPEC oil supplier, has immense promise in its oil and natural gas resources, she says, along with relative political stability and production reliability, without fears of attacks or civil war (see story above).

The involvement, however, of outside companies in the continued development in western Siberia and new developments elsewhere still “depends largely on government policies,” says John Webb, director of Russian and Caspian energy for the Cambridge Energy Research Associates in Massachusetts. “Recently we’ve seen [what is] really a reassertion of the Russian state, which is playing a greater role in the energy sector generally,” he says. “I think much still has to happen to unlock the full potential for investment in Russian oil and gas, including enactment of a more progressive and predictable tax regime, for example.”

Nevertheless, investors recently have been “signing path-breaking agreements with Russian companies,” Webb says. In September, for example, ConocoPhillips purchased 7.59 percent of Lukoil, the Russian oil giant that is second only to ExxonMobil in booked oil reserves. So far, ConocoPhillips has failed to obtain another several percent of shares that would give it a stronger say in how Lukoil is run, but a longstanding existing relationship between the two companies means that the current partnership “made sense,” says Julia Nanay of PFC Energy in Washington, D.C.

ConocoPhillips’ interests include fields neighboring Lukoil leases, such as Ardalin, close to the Barents Sea, and a joint agreement to build a pipeline to serve that project. The American company also intends to have a stake in Lukoil’s bid for West Qurna, one of Iraq’s larger and as-yet undeveloped oil fields. Still, Lambert says, the marriage between ConocoPhillips and Lukoil probably will remain tempered by Russia’s political climate, as was the case with a recent BP deal.

In February 2003, BP spent more than $7 billion (U.S.) to merge with TNK (Tyumen Oil Co.) and SIDANCO, in the largest outside investment in Russia’s oil operations ever. While BP “has a very good position in Russia now,” Lambert says, taxes have cut into the new entity’s earnings, making it less profitable than it might have been. And last June, President Vladimir Putin’s administration questioned whether TNK-BP had broken laws regarding sharing reserves information with foreigners, according to a report in the Wall Street Journal.

Putin has continued to tighten the reins on companies that were privatized under Yeltsin’s administration in the early 1990s, which led to the rise of Russia’s so-called oil oligarchs. The billionaires who purchased state-owned companies on the cheap are now under intense scrutiny, if not attack, as exemplified by the unfolding saga of Yukos Oil’s former owner, Mikhail Khodorkovsky (see Geotimes, April 2004). In jail since October 2003 for tax evasion, Khodorkovsky has relinquished his stake in Yukos, formerly the top Russian oil company, which could be effectively bankrupted by the government’s demands for back-tax payments.

“The Russian government is open in principle to approaches from foreigners, but it’s something that has to be approved of in advance,” Lambert says. In the future, “companies will have to take much smaller shares,” Nanay says, something perhaps illustrated by ConocoPhillips’ approach to Russian investment.

“I think companies are not going to give up on Russia,” Nanay says. ChevronTexaco, for example, is discussing an integrated gas project with Gazprom (Russia’s largest state oil and gas company, according to Forbes), looking at delivering liquid natural gas to the United States. Exxon and BP also continue to pursue their current oil production interests in Russia.

One of the main concerns for future growth and operations in Russia is transportation infrastructure, “which has been stretched to capacity for several years now,” Lambert says. Right now, the country relies on rail, which is two to three times more expensive than pipeline delivery, Nanay says, and “clearly, Russia is going to need more pipeline export capacity.”

Several schemes have been proposed, including a pipeline to Murmansk on the Barents Sea, which Nanay says the United States favors for easy transport to points west. But Putin may be leaning more toward a pipeline to the east, in order to reach Asian markets. Yukos had been in discussions with China to build a pipeline privately, but those plans are “very much on the backburner,” Lambert says.

High oil prices may have a blinding effect even in Russia, Nanay says. “They’re making so much money, but not doing things to make sure their sector is developing as it should be,” she says. Russia needs international partners that will bring a level of management skills and technology experience to help develop new fields, as well as the offshore gas exploration and liquid natural gas projects that Russian companies have never carried out.

“The question is whether Russia can meet expectations,” Hill says, by keeping its high production rates going. So far, those current rates have met mostly the increased demand from China’s booming economy and energy needs. But Russia’s oil companies are predicted to peak next year, and “oil production will plateau for a while,” she says, “if they don’t move fast enough.”

Despite a plethora of problems, current and potential, Lambert says, “people still want to go there [because] Russia is one of the few places where you can still make a difference.”

Naomi Lubick

"Russian oil rumbles," Geotimes, April 2004
"Assessing Iraq's oil potential," Geotimes, October 2003

Back to top

Geotimes Home | AGI Home | Information Services | Geoscience Education | Public Policy | Programs | Publications | Careers

© 2019 American Geological Institute. All rights reserved. Any copying, redistribution or retransmission of any of the contents of this service without the express written consent of the American Geological Institute is expressly prohibited. For all electronic copyright requests, visit: