The Quest: Energy, Security, and the Remaking of the Modern World

by Daniel Yergin

  For many years, oil sands—sometimes called tar sands—had seemed, at best, almost beyond the fringe of practicality and were generally dismissed as of little significance. Yet over the last few years, the oil sands have proved to be the fastest-growing source of new supplies in North America. Their expanding output will push Canada up in the rankings to be the fifth-largest oil-producing country in the world. The significance for the United States is great. If the “oil sands” were an independent country, they would be the largest single source of U.S. crude oil imports.19

  The oil sands are found primarily in the northern part of the Canadian province of Alberta, including an area known as the Athabasca region. These sands are composed of viscous bitumen embedded in sand and clay. This asphaltlike bitumen, a form of very heavy oil, is a solid that for the most part does not flow like conventional oil. That is what makes its commercial extraction so challenging. But when the weather is warm, a little bit of the bitumen does ooze out of the ground as thick, tarlike liquid. In earlier centuries local Indians would use that seep to caulk their canoes.

  In the first decades of the twentieth century, a few scientists intrigued by these seeps, along with promoters lured by the visions of riches, began to make the trek to the Athabasca River in northern Alberta and the isolated outpost of Fort McMurray—a cluster of a dozen log buildings connected to the outside world by mail delivery four times a year, weather permitting. The expeditions found indications that the sprawling swampy lowlands around Fort McMurray were rich in oil sand deposits, but there was no obvious way to extract the resource. In 1925 a chemist at the University of Alberta finally found a solution for separating the bitumen from the sand and clay and getting it to flow—but only in his laboratory. Decades of research failed to overcome the baffling challenge of extracting a liquid oil out of the sands in any commercial way.

  But a few refused to give up on the oil sands. One of them was J. Howard Pew, the chairman of Sun Oil, who, as one of his colleagues said, was “enamored of the resource up there.” In 1967 Sun launched the first at-scale oil sands project. “No nation can be long secure in this atomic age unless it is amply supplied with petroleum,” said Pew. “Oil from the Athabasca area must of necessity play an important role.” The sands at what was called the Great Canadian Oil Sands Project were mined, and then treated above ground so as to turn the bitumen into a liquid. But for many years the results from the Great Canadian Oil Sands were anything but great. The venture encountered one engineering problem after another.20

  In addition to the great technical challenges, the operating conditions were daunting. In the winter, the temperature dropped to–40°F. The swampy terrain, known as muskeg, freezes so hard that a truck can be driven on it. In the spring, it turns into such a swampy bog that a truck can sink so far into it that you lose it.

  The business environment was also tough. In the 1970s Canada adopted a highly nationalistic, high-tax national energy policy. It may have reflected the temper of the time, but it was ill suited for a high-risk, multiyear, multibillion-dollar enterprise. Development stalled as companies packed up and went elsewhere to invest.

  MEGA-RESOURCE

  It was not until the late-1990s that the oil sands finally began to prove themselves as a large-scale commercial resource, facilitated by a crucial tax reform and less-rigid government intervention, and by major advances in technology. The mining process was modernized, expanded in scale, and made more flexible. Fixed conveyer belts were replaced with huge trucks with the biggest tires in the world, and with giant shovels that gather up oil sands and carry them to upgraders that separate out the bitumen. Refining processes then upgrade the bitumen into higher-quality synthetic crude oil, akin to light, sweet crude oil, which can be processed in a conventional refinery into gasoline, diesel, jet fuel, and all the other normal products.

  At the same time, a breakthrough introduced an alternative way of producing oil sands—not with mining but rather in situ (Latin for “in place”); that is, with the crucial link in the production chain done in place—underground. This was very significant for many reasons, including the fact that 80 percent of the oil sands resource is too deep for surface mining.

  The in situ process uses natural gas to create superhot steam that is injected to heat the bitumen underground. The resulting liquid—a combination of bitumen and hot water—is fluid enough to flow into a well and to the surface. The best-known process is SAGD—for steam-assisted gravity drainage, and pronounced as “sag-dee.” It has been described as “the single most important development in oil sands technology” in a half century.21

  Altogether, since 1997, over $120 billion of investment has flowed into Alberta’s oil sands, now defined as a “mega-resource.” Oil sands production more than doubled from 600,000 barrels per day in 2000 to almost 1.5 million barrels per day in 2010. By 2020 it could double again to 3 mbd—an output that would be higher than the current oil production of either Venezuela or Kuwait. Adding in its conventional output, Canada could reach almost 4 mbd by 2020.

  Yet the development of oil sands brings its own challenges. The projects are large industrial developments in relatively remote areas. In terms of new oil development, they are among the highest in cost, especially when competition heats up for both labor and equipment. The offsetting factor is that there is no exploration risk, the resource does not deplete in the way that a conventional oil well does, and the projects will have a very long life.

  One environmental challenge arises from the local impacts of mining development, which are visually dramatic. But they are also limited. To date, the entire footprint from mining oil sands is an area that adds up to about 230 square miles of land in a province of Alberta that is about the size of Texas. When part of a surface mine is exhausted, the operators are required to restore the land to its original condition. Mining wastes, a sort of yogurtlike sludge, are deposited in tailing ponds. These toxic ponds, like the rest of the industry, are regulated by the province. Recently the regulatory authorities have required new processes to further reduce the impact of these pools. Altogether the tailing ponds cover an area equivalent to about 66 square miles.22

  The other significant environmental issue is definitely not local and is also the most controversial. This is greenhouse gas emissions, in particular carbon dioxide (CO2), associated with the in situ production process. These emissions are higher than the emissions released from the production of the average barrel of oil because of the heat that must be generated underground to get the bitumen to flow.

  How much greater is the impact compared with conventional oil? The best way to assess the impact is from a “well to wheels” analysis. That measures the total CO2 emitted along the entire chain, from the initial production to what is burned in the auto engine and comes out the tailpipe. A range of studies finds that a barrel of oil sands adds about 5 to 15 percent more CO2 to the atmosphere than an average barrel of oil used in the United States. The reason the difference is so small is that, by far, most of the CO2 is produced by the combustion in an auto engine and comes out of the tailpipe.23

  The technologies for producing oil sands continue to evolve, and increasing ingenuity is being applied to shrinking the environmental footprint and reducing the CO2 emissions in the production process. As the industry grows in scale, it will require wider collaboration on the R&D challenges not only among companies and the province of Alberta but also with Canada’s federal government.

  Yet the very scale of the resource, and its reliability, puts a premium on its continued evolution of this particular industry. Oil sands are, after all, an enormous resource. For the 175 billion barrels of recoverable oil sands is only 10 percent of the estimated 1.8 trillion barrels of oil sands “in place.” The development of the other 90 percent requires further technological progress.

  ABOVEGROUND RISKS

  The only other concentration of unconventional oil resources in the entire world that rivals Canada’s oil sands is the Orinoco belt in the
interior of Venezuela. There, too, the oil is in the form of bitumen embedded in clays and sands. With new technologies and a good deal of investment, the potential output of the Orinoco is huge. Yet what might have been anticipated in terms of supplies from the Orinoco has been much reduced in recent years—not because of limits of the resource itself but because of what has happened aboveground.

  May Day, 2007, began in Venezuela with a show of strength. The army swept in to seize oil facilities in the Faja, the Orinoco Oil Belt. This was a prelude to the moment when President Hugo Chávez, dressed in red fatigues, took to the platform in the industrial complex of José to announce to assembled oil workers what was already obvious—he was taking over this vast industrial enterprise. “This is the true nationalization of our natural resources,” he proclaimed as jets streaked overhead. To underline the point, behind him hung a giant banner that read, “Full Oil Sovereignty. Road to Socialism.” His audience was oil workers who had traded their normal blue helmets for revolutionary-red helmets and had donned red T-shirts celebrating nationalization.

  This was one of a long series of steps by Chávez to subordinate the country’s political institutions and economy to his Bolivarian Revolution. But the Orinoco was a unique prize. Covering 54,000 square miles and stretching 370 miles, it contains an estimated 513 billion barrels of technically recoverable reserves. But that is far larger than what currently is economically recoverable. And, as in Canada, the overall potential is still that much greater—as much as 1.3 trillion barrels.

  The Orinoco’s bitumen is very difficult to produce. Like the oil sands in Canada, the extra heavy oil (EHO) of the Orinoco Belt is so heavy and gunky that it cannot easily flow. Limited production began in the 1970s, but was greatly constrained by costs and technology.

  To extract significant amounts of resource and then refine it into flowing oil would require a great deal of investment and advanced technology. In the 1990s Venezuela had neither. The Orinoco was too big and complex for the state oil company, PDVSA, to go it alone. The Orinoco became the most high-profile part of the petroleum opening, or la apertura, under which in the 1990s Venezuela invited international companies back as partners or service providers.

  A half dozen international companies partnered there with PDVSA, investing upwards of $20 billion. They also pushed the technology. Within a decade, the joint ventures had gone from nothing to more than 600,000 barrels a day, with the promise of much more to come.

  But with Chávez’s Bolivarian Revolution, it was clearly only a matter of time before the Orinoco was taken over. And what better day than May Day to announce, as Chávez did, that the Orinoco had to be nationalized “so we can build Venezuelan socialism.” He declared, “We have buried the ‘petroleum opening.’ ” And for good measure, he thundered, “Down with the U.S. empire.”

  Some of the Western companies remained, but in more subordinate roles. New operators—Vietnamese and Russians, among others—came in. The Venezuelan government held out the objective of tripling the Orinoco’s output to 2 million barrels per day by 2013. Others questioned if even current production levels could be maintained, given the financial and technical challenges. After all, oil output elsewhere in Venezuela was already in decline because of lack of investment and loss of managerial talent.

  Still, May 1, 2007, was a day of triumph for Chávez. It was a little more uncertain for the workers, who had to listen to his speech for an hour and a half under the hot sun and were unsure about their new owner. “Our bosses made us come,” said one worker. “We didn’t want to get fired.” And, to make sure that everyone showed up, attendance was taken on the buses that ferried them to the speech.

  And so there, under that hot sun at the Jose Industrial Complex, was both the spectacle of another victory for the Bolivarian Revolution and its leader, and at the same time, a very visible demonstration, amid one of the world’s richest concentrations of resources, of the meaning of aboveground risk—in this case clad in revolutionary red.24

  MOTHER NATURE’S PRESSURE COOKER

  Despite the diversity of the range of unconventional oils, a common theme ties them together. It is all about finding a way to unlock resources whose existence may have long been recognized but for which recovery on a commercial scale had seemed impossible.

  Those breakthroughs are yet to happen with what is called oil shale. Oil shale contains high concentrations of the immature precursor to petroleum, kerogen. The kerogen has not yet gone through all the millions of years in Mother Nature’s pressure cooker that would turn it into what would be regarded as oil. The estimates for the oil shale resource are enormous: 8 trillion barrels, of which 6 trillion are in the United States, much of it concentrated in the Rocky Mountains. During the gasoline famine of World War I, National Geographic predicted that “no man who owns a motor-car will fail to rejoice” because this oil would provide the “supplies of gasoline which can meet any demand that even his children’s children for generations to come may make of them. The horseless vehicle’s threatened dethronement has been definitely averted.” But then early hopes for oil shale were completely buried by its high costs, lack of appropriate technology, and an abundance of conventional oil.

  At the end of the oil crisis decade of the 1970s, amid the panic and shock of the Iranian Revolution, a vigorous campaign was launched in Washington, D.C., to create a new industry that would provide 5 million barrels per day of synthetic fuels and, in addition, give the nation “a psychological lift of ‘doing something’ instead of just doing without.” The Carter administration instituted an $88 billion program that would cost many tens of billions of dollars to develop those “synfuels” as the way to ensure energy independence. Oil shale was at the top of the list. Petroleum companies announced major projects. But within a couple of years, the projects were abruptly terminated. The oil shale campaign was done in by the rising surplus of petroleum in the world market, the falling price, and the way in which the costs for developing oil shale were skyrocketing—even without any commercial production having begun.25

  Yet today a few hardy companies, large and small, are at work on oil shale again. They are still trying to find new and more economic approaches for speeding up nature’s time machine and turning kerogen into a commercial fuel without having that several-million-year wait. One line of research parallels the in situ process for oil sands and seeks to heat the kerogen underground.

  There are still other types of unconventional oils that may grow in scale and importance over the next few years, notably oil made by processing coal or natural gas. The former is done, notably, in South Africa; and the latter, in Qatar. Both require heavy engineering. But high costs hold back both processes from further significant expansion, at least so far.

  TIGHT OIL

  The newest breakthrough is opening the prospect of a big new source of oil, something that was not even expected a few years ago. This new resource is often confusingly called “shale oil,” which can be totally mixed up with “oil shale,” which it is not. Thus, both for clarity’s sake and because it is found in other kinds of rocks as well, it is becoming better known as tight oil. People have recognized for a long time that additional oil was locked inside shale and other types of rock. But there was no way to get this oil out—at least not in commercial volumes.

  The key was found on the fringes of the industry, in a huge oil formation called the Bakken, which sprawls beneath the Williston Basin across North and South Dakota and Montana and into Saskatchewan and Manitoba in Canada. The Bakken was one of those places where smaller operators drilled wells that delivered just a few barrels a day. By the late 1990s, most people had given up on the Bakken, writing it off as “an economically unattractive resource.”26

  But then the impact of the technology for liberating shale gas—horizontal drilling and hydraulic fracturing—be came evident. “As shale gas began to grow, we asked ourselves ‘Why not apply it to oil?’ ” said John Hess, CEO of Hess, one of the leading players in the Bakken
. The new technologies worked. Companies rushed to stake out acreage, and a boom in tight oil began to sweep across the Bakken. Production in the Bakken increased dramatically, from less than 10,000 barrels per day in 2005 to more than 400,000 in 2010. In another several years it could be 800,000 barrels per day or even more.27

  The technique is spreading. Formations similar to the Bakken, with such names as the Eagle Ford in Texas, and Bone Springs in New Mexico, and Three Forks in North Dakota, are becoming hot spots for exploration.

  Although still in the early days of tight oil, initial estimates suggest that there might be as much as 20 billion barrels of recoverable tight oil just in the United States. That is like adding one and a half brand-new Alaska North Slopes, without having to go to work in the Arctic north and without having to build a huge new pipeline. Such reserves could potentially be reaching two million barrels per day of additional production in the United States by 2020 that was not even anticipated even half a decade ago. Although there is hardly any calculation of the tight oil resources in the rest of the world, the numbers are likely to be substantial.

  What all the unconventional resources have in common is that they are not the traditionally produced onshore flowing oil that has been the industry staple since Colonel Drake drilled his well in Titusville in1859. And they are all expanding the definition of oil to help meet growing global demand. By 2030 these nontraditional liquids could add up to a third of total liquids capacity. By then, however, most of these unconventional oils will have a new name. They will all be called conventional.28