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Oil Frontiers: The Future of Oil
In January 2007, as the world’s media focused on the latest dire warnings about climate change coming from leading scientists meeting in Paris, another conference passed relatively unnoticed. Called the “Arctic Frontiers Conference,” it was held in Tromso, Norway.
The opening speech was given by the fresh-faced and enthusiastic Norwegian Minister of Petroleum and Energy, Odd Roger Enoksen. “Oil is a strategic commodity and no country can afford to run out of oil,” he told his captive audience. “Here, the Arctic could play an important role. If the U.S. Geological Survey is right, 25 percent of the world’s undiscovered petroleum reserves could be found in the Arctic.”
The Arctic region could be part of the “solution to the growing energy needs of the world,” Enoksen continued. Exploitation of these resources would lead to considerable economic development in the Northern areas, but such a development would also cause considerable environmental concern.
Any development in the Barents Sea, a part of the Arctic Ocean between Norway and Russia, would have a huge ecological cost. The conservation group WWF calls the Barents one of the most productive marine ecosystems in the world and among the most biologically diverse in the Arctic.
To encourage oil exploitation, Norway issued a new exploration license round in 2006. Enoksen said the area had more than six billion barrels of oil equivalents in reserves, but many more to be found. All previous exploration activity has been in the Southern Barents Sea, which opened 25 years ago. The northern Barents is unexplored and the area to the east, where there is disputed ownership with Russia, remains “geologically very much unknown.”
“Over the next few years, extensive exploration activity and drilling will take place,” Enoksen concluded. “I see a new petroleum province emerging.”
The Norwegian company Statoil, which recently merged with Norsk Hydro in a $30 billion deal to form the world’s biggest offshore operator, is leading the development in the Barents Sea. It is the operator of the Snøhvit field, which means Snow White in English.
The field is radically different from traditional offshore oil and gas fields. There is nothing to see on the surface, no drilling platform or floating production vessel, nothing. It is the first major development on the continental shelf which has no surface installations at all. All the production facilities stand on the seabed, and are remotely controlled from onshore. The oil flows to land along an underwater pipeline. Snøhvit is “just the start,” says Sverre Kojedal of Statoil. Echoing Enoksen, he says, “We think of the Barents Sea as Europe’s new oil and gas province.”
For the oil industry, regions like the Barents Sea and the Arctic are going to become ever more important, as traditional fields mature and others remain off limits. While the global oil industry may be flush with cash at the moment, finding and competing for oil and gas reserves is becoming increasingly difficult. Now the industry has to look further and harder to find oil.
The giants’ trouble is getting access to the remaining reserves of oil. Business Week pointed out that, in the 1960s, 85 percent of known reserves were accessible to the oil majors, but now that figure is only 16 percent. Even that figure has now been rewritten. In May 2007, a new report by energy consultants, PFC Energy concluded that the multinational oil companies “own or have access to less than 10 percent of world oil resources.” One part of the problem is that the more easily discoverable reserves have already been found [see “Half a Tank,” page 15].
Jim Mulva, chief of ConocoPhillips, says that “vast new areas will need to be opened and explored.” If they are not, the International Energy Agency is warning that the world is facing an oil supply “crunch” within five years that will force up prices to record levels.
Another part of the problem for Big Oil is that nearly two thirds of known reserves are now held by national oil companies — more than 60 percent of oil reserves are in the Middle East — and a further 19 percent have limited availability.
Big Oil is running out of oil. Countries that were once subservient partners to Big Oil, such as Venezuela, are less pliable. The majors have been hit by a double whammy: first, a spate of renationalizations, such as in Bolivia and Venezuela. Second, countries such as Russia have begun flexing their muscles and demanding the rewriting of one-sided contracts.
Shell’s huge project on the island of Sakhalin, off Russia’s Far East coast, is an example of the risks of frontier exploration. Once a penal colony, the area is remote and hostile. Two years ago, Shell announced that the cost of the main phase of development for Sakhalin 2 had doubled to $20 billion. Further delays threatened to undermine investor confidence not only in the project, but in Shell itself.
In 2006, in a move widely regarded as a sheer power play, Moscow announced that it might revoke a crucial environmental license Shell needed to proceed with the project. In December, Shell settled the dispute by allowing the Russian state-controlled Gazprom to take control of the project by buying 50 percent plus one share. Russia had wrestled a jewel from Shell’s crown.
Shell was not alone in being pressured by the Kremlin. Two months later, fearing it would lose its operational license all together, BP offered to hand over a majority stake in Kovykta, one of Russia’s most exciting gas projects, to Gazprom.
These episodes have left the oil industry reeling. Industry executives know how to factor in the huge technical and financial risks of frontier exploration, but the risk of politicians demanding contract renegotiations does not fit neatly into any spreadsheet.
The industry cannot escape the fact that where the reserves are is not where the friendliest governments are. Russia is sitting on a quarter of the world’s natural gas reserves. Russia’s known reserves are estimated at 47.82 trillion cubic meters, compared with Norway’s total of just 2.41 trillion. Russia’s gas field in the Barents, Shtokman, which is still awaiting exploitation, could be 10 times the size of Norway’s Snow White field.
However, every time the Russian government demands contracts be rewritten, as with Shell and BP, Western companies and their governments become wary.
This is why European governments are looking to Norway rather than Russia, even though Norway’s reserves are much smaller. Norwegian gas is already meeting 25 percent of the needs of France, Germany and the United Kingdom, and its exports to Europe are predicted to rise by almost 50 percent over the next 15 years.
As the technology improves, the industry goes further than was technologically possible even a year or two before. Drilling depth records keep getting broken. As the Snow White fields shows, the days of a floating oil platform are coming to an end. In time, advances in technology may even allow for exploration beneath the polar ice. However, the ecological risks are tremendous — being able to drill under the ice does not mean that companies can clean up an oil spill there.
The ultimate irony is that as the polar ice melts, more areas of ocean and land open up for the oil industry to exploit.
Meanwhile, the search continues. Across the Arctic, just days after Enoksen’s speech, Shell announced that it planned to drill the deepest offshore Alaskan well ever, at a depth of 14,000 feet beneath the sea floor. It was a remarkable U-turn for the company, which abandoned U.S. Arctic exploration 21 years ago. “Shell is pretty high on the Arctic,” says Keith Craik, the Shell drilling engineer leading the project. “It’s a really healthy place to look for hydrocarbons.” The following month, the company announced it was gearing up for an “aggressive” 2007 offshore exploration program in the Alaskan Beaufort Sea.
In February, the U.S. Minerals Management Service (MMS) gave approval to Shell to drill as many as a dozen exploration wells over two years in the Beaufort Sea. Local environmental and indigenous groups were outraged. Earthjustice, a nonprofit law firm that represents five Alaskan environmentalist groups, sued to block the approval. They argued that Shell’s activity could harm endangered bowhead whales, polar bears, migratory birds and other wildlife, and that MMS did not conduct a sufficiently rigorous environmental review to meet legal requirements.
“Native communities have the right to their subsistence way of life. Shell’s plans will severely impede subsistence,” argues Faith Gemmill of REDOIL (Resisting Environmental Destruction on Indigenous Lands), a network of Alaskan native subsistence users and one of the plaintiffs in the case against MMS. The agency’s failure to propose a full environmental impact statement with public input, she says, demonstrates “neglect in responsibility and lack of humanity by failing to listen to the people most directly affected by offshore oil and gas exploration and development.”
A federal court granted a temporary stay of MMS’s approval for Shell in July.
But the bad news for local wildlife and indigenous groups is that Alaskan offshore oil and gas exploration is set to increase. So far, the world’s oil companies have found more than 10 billion barrels of oil in North American Arctic seas. Many of those reserves, including gas, remain locked beneath the sea floor. Despite the fact that the Trans-Alaska-Pipeline has been operating since 1977 and over 15 billion barrels of oil have flowed along it, the industry has not been able to exploit Alaska’s vast gas reserves.
All that is about to change with the building of a $30 billion Alaskan gas pipeline to transport gas from Alaska across Canada to the lower 48 states. Alaska’s new governor, Sarah Palin, is working on legislation to push the project forward. BP, ExxonMobil and ConocoPhillips are all said to be interested in building the pipeline.
“For BP, the North Slope is the largest known but undeveloped resource in our portfolio, and frankly, we’d like to get rid of that idea,” says David Van Tuyl of BP. “BP’s future is directly linked to the future of the Alaska gas pipeline.”
Trouble at Sea
But going deeper and deeper is not without huge technical and physical risks, which translate into financial risk. BP has been placing its short-term bets in the Gulf of Mexico on its high-profile Thunder Horse field, which incorporates the largest offshore platform ever built, supported by 25 sub-sea wells. When operational, it will be the largest producer in the Gulf, producing some 250,000 barrels of oil and 200 million cubic feet of gas per day.
BP originally projected that it would start production in January 2005, but those plans were delayed and then thrown into disarray by Hurricane Dennis, which forced the semi-submersible platform to list some 20 to 30 degrees. Subsequently, metal failures have been found in the field’s subsea system. The start date for Thunder Horse has now been pushed back to the second half of 2008. Every day costs BP untold financial loses.
Another deep offshore project that is over two years behind schedule is Shell’s Bonga field, some 120 kilometers southwest of the Niger Delta, in water more than 1,000 meters deep. It has cost Shell and its partners some $3.5 billion before a drop of oil has been produced.
What is noteworthy is that most of these areas — Barents, Alaska and the Gulf of Mexico — are geo-politically safe.
Although Bonga has been beset by technical problems, it is far from the vortex of violence that surrounds Shell’s operations in the Niger Delta itself. This fact is not lost on the industry. Notes Petroleum Economist, an oil industry journal, “As well as proved reserves, which have helped position West Africa as an exploration hotspot, the isolation factor, with fields located miles from the shore, suggests a more comfortable operating climate, free from vociferous communities and sabotage.”
The Gulf of Guinea, where Bonga is located, is seen as another frontier for the industry. Within the next few years, some 25 to 30 percent of U.S. oil will come primarily from Africa. The United States now sees Nigeria and the other countries in the Gulf of Guinea as the “Next Gulf” — a counterweight to the Middle East.
Nigeria is not the only offshore “hotspot” — Angola too is enjoying a deep-water boom. In early 2007, Sonangol (Sociedade Nacional de Combustives de Angola) and Total registered new discoveries in waters over 5,000 feet deep. Chevron subsidiary the Cabinda Gulf Oil Company Limited also announced a significant oil discovery in deep water off Angola.
“This important discovery underscores the value of focusing Chevron’s exploration program on high-impact opportunities,” says John Watson, president of Chevron International Exploration and Production. “Our continued exploratory success in Angola, combined with our commitment to developing these resources, offers great prospect for increasing Angola’s oil-producing capacity.”
Perupetro, Peru’s state-owned oil company, is hoping to attract U.S. energy companies to highly controversial drilling concessions. In total, some 11 Amazonian blocks, covering approximately 22 million acres of highly biodiverse, intact primary tropical rainforest, are up for grabs.
Three of those blocks intrude upon official reserves set up to protect some of the last native peoples still living a traditional lifestyle in the Amazon. Three others overlap protected areas, and nine intrude upon titled indigenous lands. Only one block does not intrude on indigenous lands or protected areas. The new blocks mean that approximately 70 percent of the Peruvian Amazon will be carved into oil concessions. Just two years ago, it was only 20 percent.
Resistance is growing. In February 2007, indigenous leaders interrupted a presentation in Houston by Perupetro concerning the new Amazon oil concessions.
The indigenous leaders warned over 200 representatives of oil majors, including ExxonMobil, that their communities would vigorously oppose both the auction and exploitation of any drilling blocks intruding on their tropical rainforest homelands. The fight will be uphill, however.
By the end of the decade, the largest source of new oil supplies will be in Canada and Venezuela. In December 2006, Jeff Rubin, the chief strategist with CIBC World Markets, a subsidiary of the Canadian Imperial Bank of Commerce in Toronto, said that most of the world’s new capacity growth outside of OPEC will come from oil sands development after 2009.
“While deep water oil will account for the largest share of net additions of non-conventional capacity in the next two to three years, the oil sands will account for a larger share of incremental production growth after 2009,” he argues. According to Rubin, Canada holds about 50 percent of the world’s “investable reserves” for Western oil companies barred from operating in countries such as Saudi Arabia, Mexico and even Russia.
For the oil industry, unconventional oil has much going for it. It might be costly to convert to conventional oil, but that cost is calculable and largely predictable. Although Hugo Chavez’s Venezuela is slightly unpredictable at the moment, it is still selling oil to the United States, and close to U.S. consumers.
In February 2007, Venezuela’s President Chavez announced the nationalization of private oil assets in the Orinoco Delta, a region of heavy oil reserves. Chavez announced that the Venezuelan state would take a controlling 60 percent stake in heavy oil projects run by BP, ExxonMobil, Chevron, ConocoPhillips, Total and Statoil. He added that Venezuela doesn’t “want the companies to go. ... We just want them to be [minority] partners.” By May, Chavez’s government finally seized control of the last remaining oil projects controlled by U.S. and European oil companies.
In contrast, Canada is as politically safe and financially secure as they come. “In the final analysis,” argues Rubin, “what makes the oil sands properties so valuable is that there are few other places where production can grow and even fewer where you can invest. Canada’s oil sands may be the final frontier for investors intent on profiting from depleting conventional crude reserves.”
His analysis was backed by the first major report of its kind into unconventional oil two months later. Oil consultants Wood Mackenzie predicted in February 2007 that all of the world’s extra oil supply is likely to come from oil sands and heavy oils within 15 years.
According to Wood Mackenzie calculations, there are 3,600 billion barrels of unconventional oil and gas reserves in Canadian oil sands and Venezuela’s Orinoco region. This is 13 times Saudi Arabia’s reserves. Of these Canadian and Venezuelan reserves, only 8 percent has begun to be developed. Fifteen percent of the undeveloped reserves is actually heavy and extra-heavy oil; the remainder is even more challenging and more energy intensive to produce.
The study argues that the shift from conventional to unconventional oil may not be far away. Dr. Rhodri Thomas from Wood Mackenzie argues that, within the decade, non-OPEC conventional oil will peak and go into decline. Thomas predicts the gap will be filled by unconventional oil sources, with production from Canadian oil sands quadrupling.
The increasing reliance on unconventional oil will require a substantial reshaping of the oil industry, notes the Financial Times. The super-majors — Shell, Total, Exxon and Chevron — are all investing heavily in Canada and Venezuela. Others, including the Chinese oil companies, are looking at countries as diverse as Madagascar to exploit the heavy oil.
There are two downsides to the holy grail of unconventional oil. First is the huge ecological cost. Take Canada’s oil sands development: Some 150,000 square kilometers of Alberta’s boreal forest could be dramatically transformed into an industrialized landscape, much of it strip-mined.
Oil sands are heavy, molasses-like, and need huge amounts of energy and water to upgrade them to a refinable product. According to the Pembina Institute, Canadian oil sands operations are licensed to divert 350 million cubic liters of water a year — twice that used by the city of Calgary. Each day, enough energy to heat more than three million Canadian homes is used to produce oil sands. Producing a barrel from oil sands produces three times more greenhouse gas emissions than a barrel of conventional oil.
The second challenge is whether it is technically feasible to convert unconventional oil at a competitive price, even given the relatively high oil prices at the moment. “The ability to extract this heavy oil in significant volumes is still non-existent,” argues Matthew Simmons, a leading peak-oil advocate. “It’s like turning gold into lead,” as pristine areas are sacrificed for little benefit.
Andy Rowell is contributing editor to Oil Change International’s The Price of Oil, and co-author of The Next Gulf - London, Washington and Oil Conflict in Nigeria (Constable & Robinson).