The Boom: How Fracking Ignited the American Energy Revolution and Changed the World

by Russell Gold

  So, Foster continued, what are the obstacles? An engineer responded that there were no rigs in the Barnett that could handle these kinds of wells. A few days later, Foster and a couple members of his team drove to Tulsa to meet with Helmerich & Payne, a rig outfit. He told the company that he wanted a rig capable of horizontal drilling in the Barnett. “They looked at us with their eyebrows raised,” he said. “What are you up to?” an H&P executive asked. Foster explained his theory. If the well could be turned to run directly through the Barnett Shale, perhaps the fractures wouldn’t escape into the Ellenberger and produce salt-water wells. “We think it will work,” Foster said. H&P agreed to send one of its most modern rigs to Fort Worth on a trial basis.

  Horizontal wells, in 2002, were fairly unusual. Only one of every fourteen wells drilled in the United States and Canada was horizontal. (A decade later, six of every ten wells were horizontal.) While these twisting wells were still relatively new, the industry had been drilling slant wells for decades. In 1941 oil was discovered under the Oklahoma Capitol building. Even in oil-crazed Oklahoma, tearing down the steel-reinforced concrete dome was out of the question. Instead, Phillips Petroleum set up a drilling rig across the street. The well proceeded at an angle to travel underneath the building, and for years lawmakers met atop an active oil well. The well, nicknamed the Petunia #1, was drilled from a flower bed.

  In 1986 Al Yost, the government scientist in West Virginia, and colleagues drilled a horizontal well into the Devonian Shale in southwestern West Virginia’s Cabwaylingo State Forest. This well descended for 2,113 feet vertically, and then, using pipes bent at a slight 2.5 degree angle, the drill bit proceeded slowly to the right. The pipe got stuck once, and the angle achieved was too small, forcing them to retreat a few feet and start a new shaft. The motor that drove the drill plugged up several times and broke down every ten hours, on average. But over the distance of nearly six football fields, they reoriented the well until it ran horizontally, parallel to the ground for 2,000 feet. Viewed at a remove, the well resembled a truncated capital J. The well dipped into and ran through the shale, exposing more of the rock to a rudimentary frack. Yost reported in a paper that after fracking it, the well flowed at a rate seven times higher than vertical wells in the area.

  Since that West Virginia well, the industry had gotten better at horizontal drilling. It can be done faster and with more precision. Devon drilled its first horizontal Barnett well in June and July 2002. The Veale Ranch #1H took nearly a month and a half to drill and was fracked with 1.2 million gallons of water. The well worked, although production was only marginally better than a vertical well. Five months later, in November 2002, Devon had its sea legs under it and was gaining both confidence and speed. Devon drilled its sixth horizontal well, the Graham Shoop #6, in less than a month. It used more than twice as much water as the Veale well to frack it, and more than seven times as much gas came out. In Foster’s eyes, it was a beautiful well. His misgivings about drilling shale began to melt away. But when he asked his team at the monthly Barnett meetings to explain to him why the wells were so good, blank stares met him.

  Shale wells are overachievers. The new fractures free up a lot of natural gas, which will rush into the well and up to the surface. The first few weeks that the wells are connected to a pipeline yield the highest production, and then they start to decline. A well will continue producing gas long after the gas freed up by the initial fractures travels up into the well. This gas appears to come from the shale rock itself, worming its way out and into the fractures. How this works remains not entirely understood.

  Hundreds of engineers filled out an informal survey at a shale gas conference in November 2008. “I am confident that I understand reservoir drainage” was one question. Four-fifths of the engineers responded that they weren’t confident. Several years into the all-out juggernaut of shale drilling, the experts themselves didn’t know exactly why shale production worked. They just knew it worked.

  If these engineers were puzzled about what was going on in the shales, what hope did Brad Foster have? In early 2003, he started to get production reports from Devon’s first horizontal Barnett Shale wells. They looked promising. But he wasn’t ready to pop any champagne. “We were a little bit on the pessimistic side,” he said. “We were not sure we totally understand this shit.” The world’s first modern frack well, the S. H. Griffin #4, was all of five years old at that point. It had started off producing more than one million cubic feet a day but had dropped off to a quarter of that by mid-2003. Who knew where it was going?

  Larry Nichols said later that the company was acting with what he characterized as “excessive conservatism.” The lack of data led Devon to inch forward, instead of break into a run. “What we wanted to see was, Okay, it peaks, and we know it goes down at a very steep rate; where does it flatten out? If it flattens out at one level, you make a lot of money on that tail. Or does it continue on down and flatten out at a lower level?” he explained. Until time passed and he had real production data, he decided to “tread water” for a couple years.

  Devon was following a time-tested method: drill a little, wait a little, drill a little, wait a little. In technical terms, the company was asking whether the decline curve would be exponential or hyperbolic. Exponential decline means that production falls off until it just peters out. Drawn on a graph, it looks like a straight line. Hyperbolic decline features a dramatic drop followed by a flattening out. If the declines were hyperbolic, as Foster thought they would be, then shale gas could be profitable under the right circumstances. But until he knew for sure, neither he nor Larry Nichols wanted to risk too much money drilling the Barnett.

  In June 2002 Devon held a Barnett coming-out party for Wall Street analysts in a Dallas suburb. There were 1,043 wells in the Barnett, it explained, but there was room for another five thousand. It was using fourteen rigs in the Barnett. At that pace, it had a fifteen-year backlog of wells to be drilled. Not only wasn’t Devon in any hurry, it had planned exploration around the world that would take a lot of money to finance. Ramping up spending in the Barnett wasn’t a top priority. There was no need, Devon thought, to go out and find other shales similar to the Barnett. There weren’t any. The company declared that it was “unique.” It couldn’t have been more wrong.

  That fall, I decided to take a drive around the Barnett to see for myself what I had been hearing about in corporate presentations. Back then, you had to go looking for signs of gas development. The rigs were few and far between. I drove to a slight rise so that I could gain a vantage point to see above the strip malls and chain restaurants and find a rig. I saw one off in the distance and spent the next half hour taking wrong turns down cul-de-sacs until I found it. It had been erected in a field a couple hundred feet behind a cluster of suburban houses. Neighbors said it was loud. That it was lit up like an oversized Christmas tree at night annoyed them. This type of close proximity between homes and drilling pads was becoming the new normal. For the first time since the early 1900s, when oil extraction in Los Angeles began, an urban drilling campaign was under way.

  In July 2003 Devon offered me a tour to show off the Barnett. I met a couple company employees at a Shell station off Interstate 35. Nearby, several trucks idled, waiting their turn to fill up from a metered municipal fire hydrant. We visited a drill pad and a large plant that took the gas and stripped out ethane, butane, and propane. Fracking hadn’t entered the national discussion. The tour was a way for Devon to talk about its horizontal wells and demonstrate how it was getting gas out of the ground. Fracking wasn’t a curse word. Not yet, anyway. Devon didn’t even call it shale gas back then. My tour guide, a former Mitchell employee named Jay Ewing, called it “unconventional gas” to separate it from the normal way of drilling for the fuel. Years later, I met him again and spent another few hours driving around the Barnett. On the second tour, he showed off the three-story-tall sound walls that Devon built around its drilling pads to cut down on the noise and be a better ne
ighbor. This time he told me his full name. My first official tour guide to the new world of fracking was none other than J. R. Ewing.

  Back in the early days of the Barnett, Devon was far and away the largest holder of gas exploration leases in and around Fort Worth. It wasn’t, however, the only one. There were several small companies making a modest profit on the margins of the old Boonsville Bend gas field. It was soon clear that fortune had smiled on them. They were in the right place at the right time. They held thousands of acres of drilling rights, obtained when leases could be had for a few dollars per acre and held in perpetuity by dint of an existing well that dribbled out a couple hundred cubic feet of gas a month. These lucky few became the first multimillionaires of the shale boom.

  Dick Lowe, owner of a small local explorer called Four Sevens Oil, told me his business strategy was nothing more complex than to copy Devon. Under Texas rules, Devon had to file monthly statements about the wells it drilled and how much gas they produced. When Lowe saw Devon’s production figures, he followed its lead. “As soon as we saw what their horizontal wells were doing, we started drilling all of our wells horizontally,” he said. This was in 2003. Three years later, he sold the company for $845 million.

  Chief Oil & Gas also rode on Devon’s Barnett coattails. One day in 2005, company owner Trevor Rees-Jones explained the secret of his success. He was a small wildcatter who stayed close to home. Until the Barnett came along, he drilled and operated a lot of wells near Fort Worth. On a tour of his Dallas office, he explained what happened by pointing to a wall near a copy machine. “I was banging my head against the wall,” he said, “and one day the wall gave in.” He soon sold the company’s Barnett holdings in a series of deals worth nearly $4 billion.

  Before Devon, these companies had copied Mitchell and leased aggressively, creeping closer and closer to Fort Worth until they headed into the city itself. Sarah Fullenwider, the city attorney, began to grapple with how to zone these wells only a few months before Devon bought Mitchell. She had moved to Texas a couple years before from North Carolina, where oil and gas regulation wasn’t on the state bar exam. She called around the country searching for other cities with ordinances she could copy. Meetings on the rules continued into the fall, including on the afternoon of September 11, 2001. Everyone was in shock and thought that carrying on normal work might help keep city workers calm, Fullenwider recalled. Finally, in December, officials passed a local ordinance requiring, among other things, that companies build an eight-foot-high masonry wall around a well within six hundred feet of a school, house, or park. The new rules didn’t even merit a front-page article in the local newspaper. Fullenwider was surprised by how congenial the process was. “People were just used to it,” she said. “It’s just Texas.” Local drillers were happy with new rules. Lowe told me that nothing was off-limits. “We could drill a well in our parking lot. We could drill a well on the courthouse steps. We could drill a well in the middle of TCU [Texas Christian University] Stadium,” he said.

  Neither Four Sevens nor Chief held patents that made them valuable. Neither company had any proprietary technology process, made a better widget than competitors, or had smarter engineers. They were bought for one thing and one thing only: their acreage. Four Sevens held 39,000 acres in the Barnett, locked up by existing production. New Barnett wells could be drilled on this property without difficult negotiations with the landowners. Chief held 169,000 acres. These were real estate transactions, not energy deals. The domestic energy industry was turning a corner. In the past, success came from an ability to find the biggest buried troves of oil and gas. Geologists used superstition (drill atop cemetery hills), hard work (George Mitchell poring over the squiggly lines of well logs late into the night), and, later, supercomputers processing seismic data to use sound waves bouncing off rock to find “bright spots” that indicated oil deposits. But in the Barnett, the gas was everywhere.

  Some parts of the shale were better than others, held more gas, or were thicker, but wells found gas. In this new world, companies thought the key to success was speed. How quickly can you lease up thousands of acres atop a shale? This was the job of men (and a few women) rifling through files in county courthouses to research who owned the gas rights, and then knocking on doors to get leases signed. A military nomenclature emerged. Companies deployed armies of these “landmen” to capture acreage. A land war began.

  Devon’s genetic makeup didn’t fit well in this new energy world order. It was too cautious. It could move fast to make a deal, but then it would become conservative when it came time to lease and drill. It preferred to spend time driving down costs. But if Devon was content to take it slow, a crosstown competitor would soon begin taking a different approach. Before Chesapeake Energy began investing billions of dollars to snap up every drillable acre it could find and kicked the shale boom into overdrive, the company needed to see this newfangled gas production firsthand. Its introduction was accidental.

  A week after Devon’s 2002 presentation to Wall Street analysts, Chesapeake acquired Canaan Energy. Chesapeake CEO Aubrey McClendon had been pursuing Canaan for more than a year. When Canaan rebuffed McClendon’s initial offers, he used bare-knuckled tactics pioneered by corporate raiders in the 1980s. “We believe it is clear that management’s plan is not working,” McClendon wrote in an open letter to Wall Street after buying up 7.7 percent of the company’s stock. “If given the opportunity, most Canaan shareholders would prefer to sell their stock at a premium to us rather than waiting on management’s plan to work.” Canaan capitulated.

  McClendon wanted Canaan because of its wells in western Oklahoma. The two companies’ wells were so close together that Chesapeake workers heading out to service their own wells would drive past Canaan wells. Bringing together the companies could reduce costs. Now that he owned Canaan, the brash executive needed to figure out what to do with another small Canaan asset, a minority stake in some exploratory acreage south of Fort Worth. In the Canaan deal, the Barnett position was “an afterthought,” McClendon said, and “probably a liability.” He decided not to do anything with it. Hallwood Group, a Delaware holding company with energy assets, owned the majority stake in the partnership, which meant that it got to call the shots and decide where and when to drill. Chesapeake went along for the ride, writing checks for its share of costs when Hallwood sent invoices. Hallwood was an ambitious and technically competent operator. It copied Devon’s horizontal wells and began increasing the size of fracks. It also ventured into Johnson County, slightly south of Fort Worth, where there were no rocks to keep the fracks from breaking out into the Ellenberger and creating giant saltwater wells.

  Bill Marble, a Hallwood energy executive, described the challenge in heroic and somewhat grandiose terms. “The Ellenberger is still there, waiting to ruin every well with a torrent of water. But we have learned to respect it, not fear it,” he said. Johnson County was the home of “shattered dreams [and] dry holes,” Marble said. By early 2004, Marble and Hallwood had learned to tame Johnson County. In January he gave a presentation at the Fort Worth Petroleum Club. The club was up on the thirty-ninth floor of a downtown skyscraper. The windows faced north, toward the area where almost all of the Barnett Shale activity had taken place. The fifty-six geologists and engineers who attended had their backs turned on Johnson County.

  Marble shared the results of Hallwood’s latest wells to the south. It had learned to conquer the Barnett, using horizontal wells, even when the rock was above the Ellenberger, he boasted. The room was flabbergasted. “Hallwood flips this data up, and the whole room just said, ‘Wow,’ ” recalled Keith Hutton, a former executive vice president of operations with XTO Energy, the largest company in Fort Worth. The message was clear: the Barnett Shale extended straight through the city and probably included several counties to the west as well. Geologists knew that the rock extended far and wide. Hallwood demonstrated that the industry could make profitable wells across many counties. XTO began to buy up companies for
their acreage. Five years later, a member of XTO’s board of directors named Jack Randall called up Exxon CEO Rex Tillerson to sound him out on a deal. Randall knew Tillerson from their days together in the University of Texas marching band. Randall played trumpet; Tillerson played drums. They met in Tillerson’s office in August 2009. Randall said that XTO was looking for a buyer. “I think we’ll be interested,” said Tillerson. Three months later, Exxon agreed to buy XTO and its shale assets for $31 billion and assume $10 billion of the smaller company’s debt.

  In June 2004 Hallwood drilled the Lakeview #1H overlooking Lake Pat Cleburne. It used a massive amount of water to fracture the rock, much more than typical, and produced one of the best wells ever in the Barnett. It roared to life at 6.8 million cubic feet per day. Due to its minority stake, acquired as part of the Canaan deal, Chesapeake owned a piece of this home run. News of this well made it up to Oklahoma City, where McClendon decided it was time to get in on the shale game. Wall Street was talking it up, and Chesapeake’s big competitors were acquiring stakes in and around Fort Worth. Later that year, Hallwood put some of its Johnson County acreage up for sale. Chesapeake rushed to be first into the data room and made a bid it hoped would freeze out competitors. But Hallwood thought it could get more and kept the auction going, eventually settling on another company. When that bid fell apart, Hallwood called Chesapeake in late November. The next morning, McClendon flew to Dallas and over breakfast bought the assets for $277 million.