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

by Daniel Yergin

  Fortunately, something of a carrot was available, what was called Section 29. This was a provision in the 1980 windfall profits tax bill that provided a federal tax credit for drilling for so-called unconventional natural gas. Over the years, that incentive did what it was supposed to do—it stimulated activity that would otherwise not have taken place. In the 1990s, the tax credit mainly supported the development of two other forms of unconventional natural gas, and gas from tight sands, the very name of which conveys the challenge.

  “FIGURE A WAY”

  But even with the incentive of the Section 29 tax credit, producing commercial-scale shale gas—another form of unconventional gas—was proving so much more difficult. In addition to Mitchell, a few other companies were also tackling the problem, but they became discouraged and dropped out. In 1997 the only one of the major companies working on shale gas development efforts in the Barnett region shut down its office. Only Mitchell Energy and a few other smaller independents were left. George Mitchell would just not give up. “It was clear to him that Barnett held a lot of gas, and he wanted us to figure a way to get it out,” recalled Dan Steward, who led the development team. “If we couldn’t, then he would hire other people who could. He had a way of getting things out of people they might not know they could deliver on.”

  The introduction of 3-D seismic much improved the understanding of the subsurface. Still, Mitchell Energy had not yet cracked the Barnett’s code. “All sorts of experienced, educated folks,” said Steward, “wanted to bail out of the Barnett.”

  Indeed, by the late 1990s the area was so much off the radar screen that when people did forecasts of future natural gas supplies, the Barnett did not even show up. Mitchell Energy’s board of directors was becoming increasingly skeptical. After all, when almost two decades of effort were added up, it was clear that the company had lost a good deal of money on the Barnett play. But George Mitchell would not give up; he insisted that they were getting closer to cracking the Barnett’s code.3

  BREAKTHROUGH

  Fraccing—otherwise known as hydraulic fracturing—is a technique that was first used at the end of the 1940s. It injects large amounts of water, under high pressure, combined with sand and small amounts of chemicals, into the shale formation. This fragments underground rock, creating pathways for otherwise trapped natural gas (and oil) to find a route and flow through to the well.

  Mitchell Energy had been experimenting with different methodologies for fraccing. By the end of 1998, the company finally achieved its breakthrough: it successfully adapted a fraccing technique—what is known as LSF, or light sand fraccing—to break up the shale rock. “It was the trial-and-error approach that Mitchell Energy used that ultimately made the difference,” said Dan Steward.

  George Mitchell recognized that developing the Barnett was going to take a lot of capital. He had also been at it as an independent for sixty years and that was a long time. He had other interests; he had developed the Woodlands, the twenty-five-thousand-acre new community north of Houston. He put Mitchell Energy up for sale. Three other companies looked at the company but they all decided, after due diligence, to pass. It appeared to all of them that while Mitchell’s pursuit of shale gas, fraccing included, may have been an interesting idea, it was a commercial flop.

  The team at Mitchell went back to work on the shale, further developing its capabilities, deepening its understanding—and producing a lot more natural gas.

  One of the companies that had passed was another independent, Devon Energy, from Oklahoma City. But in 2001, its CEO, Larry Nichols, noticed a sudden surge in gas supply from the Barnett Shale area. “I challenged our engineers as to why this was happening,” said Nichols. “If fraccing was not working, why was Mitchell’s output going up?” The answer was clear: Mitchell Energy had indeed cracked the code. Nichols did not waste any more time. In 2002 Devon acquired Mitchell Energy for $3.5 billion. “At that time,” added Nichols, “absolutely no one believed that shale drilling worked, other than Mitchell and us.”

  Devon, for its part, had its own strong capabilities in another technology, horizontal drilling, which had begun to emerge in the 1980s. Advances in controls and measurement allowed operators to drill down to a certain depth, and then drill on at an angle or even sideways. This would expose much more of the reservoir, permitting much greater recovery of gas (or oil) from a reservoir.

  Devon combined the fraccing know-how (and the team) it had acquired from Mitchell with its own skills in horizontal drilling. All that required a good deal of experimentation. Devon drilled seven such wells in 2002. “By 2003,” said Nichols, “we were becoming very confident that this drilling truly worked.” Devon drilled another fifty-five horizontal wells in the Barnett that year. It did work.4

  Shale gas, heretofore commercially inaccessible, began to flow in significant volumes. Combining the advances in fraccing and horizontal drilling is what would unleash what became known as the unconventional gas revolution.

  Entrepreneurial independent oil and gas companies jumped on the technology and quickly carried it to other regions—in Louisiana and in Arkansas, and Oklahoma, and then to the “mighty Marcellus” shale that sprawls beneath western New York and Pennsylvania down into West Virginia.

  THE “SHALE GALE”

  Something was very strange about the numbers. As they rolled in for 2007 and then 2008, they showed something unexpected that did not make sense—a sudden surge in domestic production of U.S. natural gas. How was that possible ? Where was that coming from? The United States was supposed to be facing a sharp decline in domestic production—for which LNG was the only sure answer. Then it started to become clear: a technological breakthrough was beginning to make its impact felt. The rest of the industry now realized that something new was happening. And that included both major oil and gas companies, which had heretofore been more focused on big international LNG projects, and which was thought to be required to offset the apparent shortfall in North American natural gas.

  Over the next few years, the output of shale gas continued to increase. Some now started to call it the “shale gale.” As the supply increased and skills were further developed, costs came down. Shale gas was proving to be cheaper than conventional natural gas. In 2000 shale was just 1 percent of natural gas supply. By 2011 it was 25 percent, and within two decades it could reach 50 percent.

  The shale gas transformed the U.S. natural gas market. Perennial shortage gave way to substantial surplus, which turned the prospects for LNG in North America upside down. Just a few years earlier, LNG had seemed destined to fill an increasing share of the U.S. market. Instead it became a marginal supply rather than a necessity. Electric utilities, remembering gas shortages and price spikes, had been reluctant to use more natural gas. But now, with the new abundance and lower prices, lower-carbon gas seemed likely to play a much larger role in the generation of electric power, challenging the economics of nuclear power and displacing higher-carbon coal, the mainstay of electric generation. As a source of relatively low-priced electric power, it created a more difficult competitive environment for new wind projects. Shale gas also began to have an impact on the debate on both climate change and energy security policy. By the beginning of this decade, the rapidity and sheer scale of the shale breakthrough—and its effect on markets—qualified it as the most significant innovation in energy so far since the start of the twenty-first century. As a result of the shale revolution, North America’s natural gas base, now estimated at 3,000 trillion cubic feet, could provide for current levels of consumption for over a hundred years—plus. “Recent innovations have given us the opportunity to tap larger reserves—perhaps a century’s worth—in the shale under our feet,” President Obama said in 2011.5 The potential here is enormous.6

  At the same time, the rapid growth in shale gas has stoked environmental controversy and policy debate. In part, demographic differences have brought the controversy to the fore. Lower-density states like Texas are accustomed to energy d
evelopment, and encourage it as a major source of income for the population and revenues for the state government. Residents in more populated eastern states, like New York and Pennsylvania, are not accustomed to drilling in their region (although Pennsylvania is certainly long experienced with coal mining and was the birthplace of the oil industry. While some welcome the jobs, royalties, and tax revenues, others are taken aback by the surface disruption and the sudden increase in large truck traffic on what had been quiet country roads.

  But, more than traffic, the environmental debate is centered on water. Critics warn that fraccing may damage drinking water aquifers. The industry argues that this is highly unlikely, as the fraccing takes place a mile or more below drinking water aquifers and is separated from them by thick layers of impermeable rock. Moreover, the industry has a great deal of experience with fraccing: more than a million wells have been fracced in the United States since the first frac job six decades ago. Fraccing uses small amounts of chemicals; the general trend now is to disclose those chemicals.

  Although most of the discussion is about fraccing, the biggest issue has become not what goes down, but what comes back—the water that flows back to the surface. This is the “flow back” from the fraccing job, and then the “produced water” that comes out of the well over time. This water needs to be handled properly, managed, and safely disposed.

  Three things can be done with the flow back and produced water. It can be injected into deep disposal wells; it can be put through treatment facilities; or it can be recycled back into operations. In traditional oil and gas states, the wastewater has often been reinjected. But the geology of Pennsylvania does not, for the most part, lend itself to reinjection. And so water that cannot be recycled has had either to be put through local treatment facilities or trucked out of state.

  Aboveground management of waste has to keep pace with the rapid development of the shale industry. New large-scale water treatment facilities are being developed. The industry is now recycling 70 to 80 percent of the flow back. There is also intensive focus on innovation. These include developing new methods to reduce the amount of water going in and to treat the water coming out, and the drilling of more wells from a single “pad” to reduce the footprint.

  A more recent concern is “migration”—whether methane leaks toward the surface and into some water wells as a result of fraccing. This is a controversial subject. Methane has been found in water wells in gas-producing regions but there is no agreement on how this can happen. Some cases of methane contamination in water wells have been tied to shallow layers of methane, not the mile-deep deposits of shale gas where fraccing takes place. In other cases, water wells may have been dug through layers of naturally occurring methane without being adequately sealed. It is difficult to know for certain because of a lack of “baseline” data—that is, measurements of a water well’s methane content before a shale gas well is drilled in the neighborhood. Gas developers are now routinely taking such measurements before drilling begins in order to establish whether methane is preexisting in water aquifers. A new question concerns whether there are significant “fugitive emissions” or whether those emissions are captured.

  One other subject of controversy is regulation itself. Some argue that drilling is an unregulated activity. In fact, the entire drilling process—including the water aspects—is heavily regulated by a mixture of state and federal agencies. The states are the primary regulators of drilling, including hydraulic fracturing as well as all other activities inherent in the production of oil and gas. While the federal government has ultimate authority over water treatment and disposal, it has delegated its authority to many states whose own regulations meet or exceed federal standards. The next few years will see much argument about whether the federal government should have more responsibility. There will also be much more research on the water issues, and continuing focus on advancing the technology, both for drilling and for environmental protection in areas where shale gas is produced.7

  The shale gale had not only taken almost the entire natural industry by surprise; it also sent people back to the geological maps. Very large potential supplies of shale gas have been identified in the traditional energy areas of Canada, in Alberta and British Columbia, as well as in eastern Canada, in Quebec. Chinese oil companies, recognizing significant potential for shale gas as well as coal-bed methane, have signed agreements with Western companies to develop both. Altogether the base of recoverable shale gas outside North America could be larger than all global conventional natural gas discovered to date. But only a portion is likely to be developed. Even so, the next several years are surely to see a substantial addition to the world’s supply of natural gas.8

  GLOBAL GAS

  While shale gas is, thus far, a North American phenomenon in terms of large-scale production, it is already changing the dynamics of the global gas business. For its emergence as a new supply source coincided with a rapid buildup of LNG. In 2010 Qatar celebrated reaching 77 million tons of LNG capacity—28 percent of the world total. Australia is emerging as a new LNG powerhouse, number two only to Qatar and well positioned to supply Asia—and to continue to expand. Altogether, between 2004 and 2012, the world’s LNG capacity will double. That means that what was accomplished in the first forty years of LNG development is being replicated in just eight years. But assumptions that helped underpin and drive this rapid buildup are now somewhat unhinged. The United States was supposed to be a major guaranteed market because of a projected domestic shortfall. But instead it is a marginal market.9

  This puts much more LNG at sea, literally, in search of markets. Growing Asia will absorb a significant amount, more than most had anticipated a few years ago. But far from all. Thus, the immediate impact is on Europe, which is now the world’s number one contestable market. Freely available LNG, sold on a spot basis, can take some market share away from pipeline gas, whose price is, according to twenty-year contracts, indexed to more-expensive oil.

  This not only creates greater competition among gas suppliers, pushing down price. It also has wide geopolitical impact, for it upsets a four-decadeold economic and political balance that has proved so durable that it even survived the upheaval that was set in motion by the collapse of the Soviet Union and the fall of communism. The new gas competition is central to the complex and evolving relationship among a much-expanded European Union, the Russian Federation, and the other newly independent states of the former Soviet Union, some of whom are now members of the European Union.

  The development of the gas market in Europe is embodied in the web of pipelines that crisscross the European Continent. Look at the pipeline map from the 1960s, and all one sees are a few strands of string. Today such a map looks like a big bowl of spaghetti. Local gas markets had earlier developed in different parts of Europe. But the real European gas market only began with the development of the Groningen field in Holland in the 1960s, followed by the offshore oil and gas fields in the British sector of the North Sea.

  In the 1970s, a new pipeline brought the first Soviet gas into Europe in the 1970s. It came with a strong geopolitical tone. West German Chancellor Willy Brandt signed the first Soviet gas deal in 1970 as a key element in his Ostpolitik, aimed at reducing Cold War tensions, normalizing relations with the Soviet Union and Eastern Europe, and creating some common interest between East and West. “Economics,” as Brandt put it, was “an especially important part of our policy.” He specifically, if indirectly, wanted to reestablish contact with communist East Germany, which had been cut off completely by the construction of the Berlin Wall in 1961. The dependence flowed in both directions; this gas trade, for the Soviets, became a major—and crucial—source of hard currency earnings.10

  Over the years that followed, the gas business would be built up and managed by a handful of Western European transport and distribution companies joined together by 25-year contracts with the gas export arm of the Soviet Ministry of Gas Industry.

  “WOUNDED BY A FRIE
ND”

  By the early 1980s, major discoveries in West Siberia had propelled the Soviet Union ahead of the United States as the world’s largest gas producer. Inevitably, those big new supplies provided further impetus to sell more gas into Western Europe.

  The Soviets and the Europeans began to plan for a large, new, 3,700-mile pipeline from the great Urengoy field in West Siberia. But before it was ever built, the proposed pipeline created a bitter rupture in the Western alliance, prefiguring the controversies over the geopolitics of European natural gas that continue to the present.

  The Reagan administration became alarmed at the prospect of a much larger East-West gas trade. It had launched a major arms buildup to counter Soviet military expansion; the last thing the administration wanted was additional hard currency earnings from natural gas financing the Soviet militaryindustrial complex. It also feared that greater reliance on Soviet gas would create vulnerable dependence that the Soviets could exploit to pry apart the Western alliance and that—in a time of crisis—would give the Soviets crucial leverage. The American administration warned that the Soviet Union could use dependence on its natural gas to “blackmail” the Europeans by threatening to turn off the heat and stoves in Munich.11

  The Reagan administration struck back at the proposed new pipeline. It imposed a unilateral embargo that prohibited companies from exporting the billions of dollars of equipment that was essential to the construction and the operations of the pipeline. It applied not only to U.S. companies, but to European companies whose equipment was based on U.S. technology.

  The Europeans, however, were as determined as the Soviets to go ahead. They wanted both the diversification away from the Middle East and the environmental benefits from reduced coal use. They also wanted the revenues and the jobs, as well as the opportunity to expand their export markets in the Soviet bloc. Even Reagan’s closest ally, British Prime Minister Margaret Thatcher, looking at the loss of jobs in an area of Scotland with 20 percent unemployment, pushed back. Given her relationship with Reagan, she took the embargo very personally. “We feel particularly wounded by a friend,” she said. The British government ordered the British companies that had contracts with the Soviets to ignore the embargo and to go ahead and ship their goods. Moreover, it became apparent that the Soviets could replicate some of the supposedly proprietary technology, albeit at higher cost. Thus the embargo would only delay, not prevent, the new pipeline from going ahead.12