The Boom (18 page)

Over the next few days, Steinsberger and Whitley kept close tabs on the well. It played a cruel joke. The pressure kept dropping as more water came out. Whatever gas was in the well was weighed down by the eight-thousand-foot column of water. The water slowed to almost a trickle as it was pumped into nearby tanks. A couple days passed. Then the water began gurgling as bubbles of gas pushed up through the well. Finally, after about five days, almost all of the water was removed, and gas began to flow. The well was connected to a pipeline and measured. It was a monster well. Gas was screaming out.

A lot of the wells at the time that were fracked using gel would roar to life and then fall off very quickly, sometimes in a week or two. “This one didn’t fall off. If a well made more than 70 million or 80 million cubic feet in the first ninety days, it was an ‘A’ well. This one made 1.3 million cubic feet a day for the first ninety days,” said Steinsberger. “It was the best well we had ever had at that point. After this well, we knew we had turned the corner.”

What Steinsberger accomplished that day was a dividing line for the energy industry and the country. Before the S. H. Griffin, engineers thought shale rocks were too dense to crack open. Gel could do the trick, but it tended to gum up the cracks, leaving no room for even tiny gas molecules to escape. Steinsberger—and most other fellow graduates of Texas and Oklahoma petroleum engineering departments—believed the United States was running out of gas. It had become a giant importer of oil. It was only a matter of time before it became a world-class importer of gas also.

The S. H. Griffin well began to change that thinking. Fifty-two years after Stanolind tested its first hydrafrac, Steinsberger had reinvented it and given birth to the modern frack industry. He had figured out how to force shale to give up its gas. There was now a bounty of energy sitting under American soil. Since this first well, more than a hundred thousand wells have been fracked in the United States. Every single one uses a technique similar to what Steinsberger first tried near Ponder, Texas. The era of the massive slick-water frack had begun. By today’s standards, Steinsberger’s well was small. He used 1.2 million gallons of water. Some modern wells use five times as much. There are other critical differences. Steinsberger’s well went straight down. Most modern shale wells, like those in North Dakota, are “horizontal.” They head straight down and then turn until they run parallel to the surface, traversing through the shale formation for up to two miles. But the breakthrough had been made. Steinsberger demonstrated that water could be used to create fractures in shale. Not only was it cheaper than using gels, it was better.

It didn’t take long for word of the well to filter up to George Mitchell. He called Mark Whitley twice a week and asked the same two questions: “What is new?” and “Have you got your costs down yet?” Whitley told Mitchell about the S. H. Griffin, but tried to keep his boss’s expectations under control. It was only the first well. Good sense dictated waiting for months to see how the well played out. But Mitchell was not particularly patient. “If you tried not to tell George about something, because you thought he would go too far, it wouldn’t go well for you,” said Whitley. Mitchell liked what he heard and told him to keep going.

If a quiet excitement was percolating in Mitchell Energy’s Fort Worth offices, people who lived near the S. H. Griffin had a different reaction. Robert Catron bought a piece of land on Tim Donald Road in early 1998. By the time he purchased a double-wide trailer and had it moved to his property, a ten-story drilling rig had been set up right across the two-lane road, about three hundred feet from his bedroom. It was drilling the S. H. Griffin well. “I was really disappointed. I had put my money down, and I didn’t want to live across the street from this,” he said years later in an interview. The truck traffic was overwhelming for a couple months. “It was a daily mess.” He didn’t even get the benefit of a nice royalty check. He owned the land, but a previous owner had kept the mineral rights. He had no idea the drilling rig was only the beginning. Several years later, he stood in his front door and counted eighteen wells being drilled. “This is nothing you want to have in your front yard,” he said, “but there’s nothing you can do about it.”

On a drizzly morning in early 2012, I met Steinsberger in Ponder, outside the redbrick bank that, according to lore, Bonnie and Clyde tried to rob. It is now home to a high-end boot maker, but the old wooden cashier cages remain. Steinsberger’s days of driving an old clunker are also over. He pulled up in a Lexus SUV. It was dark gray, the color of shale. I climbed into the passenger seat, and we set off for a brief drive over to the S. H. Griffin. As we neared the well, my map-reading skills failed me, and we made a wrong turn. Within a hundred feet, Steinsberger pulled into the entrance of a different gas well to turn around. He glanced at the sign identifying the well. He remembered it. “Some of these wells are more my kids than my own kids,” he said.

After we started heading in the right direction, confusion set in again. When Steinsberger drilled the S. H. Griffin in 1998, there were no other wells nearby. But as we drove three-quarters of a mile on Tim Donald Road, wells kept popping up. The wells were in clumps, and I had a hard time figuring out how many were in each location. Steinsberger offered to count the transmitters atop each well. Each well had its own transmitter, and they were easy to see. As Steinsberger counted the meters, I tried to keep a running tally.

By the time we turned into the S. H. Griffin, we had lost count at around twenty-five wells. We parked at the entrance to the well pad. It is a two-acre flattened rectangle, with four olive green tanks used to store any liquids that come out of the well. There are two wells on the pad, both surrounded by chin-high chain-link fences.

“It’s neat. I probably haven’t been back here for ten to thirteen years,” he said, as the car idled. “Before the S. H. Griffin number four, this was a completely uneconomic, very marginal area. To go from that to the hype we have now. So many wells have been drilled. Thousands. There are fifteen thousand wells drilled in that Barnett. That makes me feel proud.”

The Barnett Shale was a riddle and a challenge. Steinsberger had approached it like a mathematician working on a nettlesome proof. There was gas in the shale. That was an article of faith at Mitchell Energy. George Mitchell himself instilled that belief. But the gas was trapped inside, and the rock was buried two miles underground. Complicating matters, Steinsberger couldn’t even see what was going on in the shale. All he had were surface measurements. (Later, instruments that could measure and map the tiny fractures became commonplace. But in 1998, early attempts had failed. The heat inside the well fried the circuitry.) This sort of challenge makes petroleum engineers tick. Steinsberger’s new well-completion technique was one of the most important technological breakthroughs of the twentieth century. Thousands and thousands of wells have been drilled into the shale. Ten trillion cubic feet of gas have been extracted. Soon after it was clear that the S. H. Griffin was a success, Mitchell started completing all its wells in the Barnett with slick-water fracks.

Steinsberger didn’t set out to solve the problem of cracking shale. It found him. When he graduated from high school in Columbus, Nebraska, he attended the community college, where his father taught, for a year. He wanted to become a petroleum engineer, so he visited colleges in Texas before settling on the University of Texas at Austin. His timing couldn’t have been worse. When he graduated in 1987, the industry was reeling from oil prices that were less than $20 a barrel. Jobs were hard to find, so he decided to backpack through Europe and Egypt for six months. While in Egypt, he was offered a job by the global oil-field service company Schlumberger. Being an overseas itinerant in the oil industry has its appeals, such as seeing the world and working in the most prolific oil fields. But it also means living in remote locations such as Egypt’s western desert or a compound behind high walls in coastal Nigeria. Steinsberger wasn’t interested. He returned to Texas and visited the university’s career placement office. He put out resumes and got one bite—from Mitchell Energy. His starting salary was $30,000 a year. His first job was as a lease operator, a glorified babysitter, in Whittier, California. He was a thirty-minute drive from the THUMS Project that had set him on course to become a petroleum engineer.

Within a couple years, Steinsberger moved to Fort Worth. His bosses there recognized that he was a talented and inquisitive engineer. He sought out challenges, and by 1995, he was wrestling with Mitchell Energy’s largest challenge: how to get more gas out of its North Texas properties. The company had drilled about two hundred shale wells, and its executives had an appetite for another fifty. If there was no improvement, the plan was to spend the money on something else that showed more promise. Steinsberger decided the best he could do was save the company some money on these wells. Mitchell Energy and the rest of the industry hired oil-field service companies to perform the frack jobs. These companies charged by the gallon for the gel and threw in the horsepower needed to pump it down the well for free. Steinsberger began using less gel in each well to lower costs. The service companies charged a 1,000 percent markup on the gels, making them extraordinarily profitable. They warned Steinsberger that high temperatures at the bottom of the well would break down the lighter (and therefore less expensive) gels, rendering them unable to convey sand all the way to the fractures. What he found was the opposite. “The wells were just as good, if not better, plus I was saving thirty to fifty grand,” he said.

Encouraged by these results, he began to wonder if he could do away with gels altogether. Water could be purchased from local cities for a fraction of the cost of gels. He wasn’t sure if the water would work, but since it cost so much less to frack a well with water, he could improve the economics of the well if it was even close to producing as much gas as a well fracked with gel. What’s more, if it didn’t work, the water wouldn’t clog up the shale. Mitchell Energy could always go back in with a gel frack.

The Fort Worth oil engineering community is tight knit and friendly. Several small companies had offices there. Engineers would often gather after work for beers and brisket at Angelo’s, a barbeque restaurant on the west side of town where dozens of stuffed animal heads peered down on diners. They golfed together on weekends and gathered at regular symposia hosted by professional organizations to learn what was new. At these gatherings, Steinsberger learned that a Fort Worth company, Union Pacific Resources, had been experimenting with water fracks in East Texas sandstones.

In a 1997 engineering paper presented at a conference in San Antonio, Union Pacific’s Ray Walker wrote about some of his successes. The conventional wisdom was that a viscous gel was required to transport the sand. If the gel was too watery, the sand would fall out and collect, uselessly, at the bottom of the pipe. The industry called these sands proppants. To show that gel wasn’t needed and neither was so much sand, Walker and several coauthors titled the paper “Proppants? We Don’t Need No Proppants.” It was a cheeky allusion, he later explained, to the famous line “Badges? We ain’t got no badges. We don’t need no badges! I don’t have to show you any stinkin’ badges!” from the 1948 movie
The Treasure of the Sierra Madre
, starring Humphrey Bogart and Walter Huston. Walker and some colleagues described in the paper how they were cutting the cost of fracking wells in half, or more, and were still getting good results. There was just one issue. “Why it works is still generally unknown,” Walker wrote.

Not that this mattered to Walker. Engineers are problem solvers. If the wells were cheaper and gas production better, problem solved. A later generation of geologists and engineers could worry about why. They were making better wells and improving their company’s bottom line. As Walker tells it, he stumbled upon water fracks by accident. A gauge that measured water volume at a Union Pacific well had broken, and before the malfunction was discovered, a young employee had pumped in much more water (and relatively little sand) than planned. In a panic, the employee wanted to know what to do. “I said, ‘Let’s just flow it back and see what happens,’ ” he said. The well was a solid producer.

But Union Pacific was working with sandstones, not shales. There is a key difference between sandstone and shale. The ability of a fluid or gas to flow through rock is measured by geologists in darcies, named after the nineteenth-century French hydraulic engineer Henry Darcy. Imagine a large wave depositing water onto a beach. Some of the water will quickly disappear into the dry sand as it drops through channels. Beach sand has a measurement of about 5 darcies. The East Texas sandstones were 0.0001 darcy, or fifty thousand times less permeable than sand. The Barnett Shale is one thousand times less permeable than the sandstones. It is about 100 nanodarcies, or 0.0000001 darcy.