by Russell Gold
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.
Steinsberger wanted to learn more about what Union Pacific Resources was doing, even though the company was drilling into such a different rock. He got permission to observe one of its frack jobs in East Texas. He then called up Walker and asked for a meeting. Walker thought that Steinsberger wanted to discuss a possible job at Union Pacific. Steinsberger had a different agenda. When he arrived at Walker’s office, he took out a bunch of well data and maps of the Barnett Shale. Where did he think would be a good place to try a water frack? Walker was ecstatic. He even offered data and engineering to help Steinsberger sell the idea to his bosses. It is hard to imagine Silicon Valley engineers helping a competitor pitch an idea for a new breakthrough design for a smart phone, but th
e Fort Worth community of petroleum engineers was collaborative. In their eyes, they weren’t only trying to generate a profit for their companies. They had a higher calling. The United States was running out of energy. Anything that could be done to reverse that trend was worth doing. A new approach to getting gas out of the rock would help the country and their companies.
After Steinsberger’s four false starts, the S. H. Griffin first showed that using a massive slick-water frack would open up shale. Still, the idea was so revolutionary that it took time for the rest of the industry to accept it. Many engineers simply weren’t ready to concede that it was possible to frack shale rocks and get gas out. “I ignored it,” recalled Kenneth Nolte, an engineer at another oil company who spent his career on smaller fracks targeting sandstones and other more porous rocks. He couldn’t wrap his head around fracking shale. Shale was an impermeable barrier, not a source of gas. “It is just as startling as saying ice doesn’t freeze anymore,” he said.
At first Mitchell Energy decided to keep quiet and not broadcast its success. But internally, the company welcomed Steinsberger’s breakthrough. By the end of 1998, six months after the S. H. Griffin, it was using slick-water fracks for every well it drilled. And it began going back into old wells fracked with gel and refracking them with water. This technique also worked. Under oil industry accounting, the value of an exploration company correlates closely with its proven reserves. These are oil and gas deposits that have been discovered and can be extracted with existing technology and current prices. If the company could go into hundreds of already drilled wells, add water, and raise its production, under accounting rules it could add around 750 million cubic feet of gas reserves for all of its wells. Steinsberger had literally increased the value of Mitchell Energy by a couple billion dollars.
Steinsberger told me he didn’t receive a raise or any bonus. George Mitchell never called to congratulate him. But he no longer worried about getting fired. Before the S. H. Griffin #4, the industry had been fracking its wells for nearly five decades. It had used hydrochloric acid, nitroglycerin, napalm, thick gels, and even nuclear bombs. Steinsberger showed that there was a simpler way: water, lots and lots of water.
A few years later, Steinsberger set out on his own, a fracker for hire. He estimates he has had a hand in drilling more than one thousand shale wells. Several small operators have hired him to work on the shale developments in Texas, Pennsylvania, West Virginia, Alabama, and Arkansas. He’ll go anywhere in the United States to drill wells, he said, except for the booming North Dakota oil field. “Too cold.”
After we left the S. H. Griffin, we drove around the area. Steinsberger talked a bit about plans to frack some wells in the famed Permian Basin. An enormous geological area that covers much of West Texas, it contains some of the largest oil fields ever discovered. Until a few years ago, it was considered played out. The oil had been extracted. Big oil companies had sold off the leases, and production had plummeted. But in recent years, companies have returned to the Permian Basin. Using fracking, production is rising again. Fracking is no longer just to get at gas. In the Permian, the target is oil—good old-fashioned Texas tea.
We headed south on Tim Donald Road, past the twenty-five or so wells. Another half mile on, we passed a large industrial facility that looks out of place amid the houses and ranches. It belongs to Chesapeake Energy. There is a two-story beige building that strips liquids such as ethane and butane—used by petrochemical plants to make plastics—out of the gas. There are a couple large compressors that send the gas into a pipeline for delivery to the Gulf Coast. A minute later, Tim Donald Road ends, taking a tight turn to the right. Ahead of us was a new drill pad behind a private house, the earth flattened, packed down, and ready for the drilling rig. In the distance, a rig was at work, lights blinking up and down its steel scaffold to alert any low-flying airplanes to its presence.
On the morning we met, it had been nearly fourteen years since Steinsberger fracked the S. H. Griffin. Gas was still flowing from the well. It had produced 2.3 billion cubic feet of natural gas. While prices for gas have risen and fallen over the years, it has generated about $11 million worth of gas. There’s likely another half billion cubic feet still to come, although each year the amount declines.
Most of the gas that a shale well will produce in its lifetime comes out in the first year or two. After a couple years of dramatic declines, the well will slow down and decline for years. How long shale wells will produce is a matter of some controversy in the energy industry. If a shale’s tail, as it’s called, is long and its decline slow, the wells being drilled will generate gas for decades to come, creating a nice flow of fuel for the country. But Wall Street wants energy companies to increase production year after year. And since their shale wells might decline by 60 percent in the first year and another 30 percent in the next year, these companies need to keep drilling hundreds or thousands of wells just to keep production flat.
This demand helps explain why there are so many wells in and around the original S. H. Griffin. This drilling has created a glut. There isn’t enough demand for the fuel. Yet wells are still being drilled here in the Barnett, even though, with natural gas fetching less than $4 for every thousand cubic feet, it is not clear if these wells will make enough money to pay for the cost of drilling them.
“Our country has to develop more ways to use natural gas. That is just the way it is. We are not going to run out of natural gas in our lifetime or our kids’ lifetimes for sure,” Steinsberger said. “Are we going to export natural gas? Or are we going to try to find more uses so that we can try to diminish use of coal and oil?” He admitted that he doesn’t spend too much time thinking about such policy concerns. He’s an engineer and focuses on the job at hand. Where to drill? How can he design the optimal frack job? How can he keep costs low?
We made our way back to Ponder and parked at a gas station cafe with a couple Formica tables and chairs. We grabbed coffees and talked over country music and conversations at nearby tables. He still marvels that the industry found so much gas from reservoirs that were overlooked just a few years ago.
“A lot of people still think you drill a well into a big lake of gas or oil, and that is how it comes out. That’s not true,” he said. “The Barnett is the tightest thing in this building except for the metal. It is harder than that cement. It is harder than anything else in here. It is a very tight formation. It is hard to believe oil and gas can come out of that.”
7
LARRY WAS THE BRAKE
Nick Steinsberger’s breakthrough in 1998 couldn’t have come at a better time for Mitchell Energy. The Mitchell family was facing both personal and professional crises. The price of oil was collapsing, dragging down the stock price of Mitchell Energy. Mitchell owned a majority of the publicly traded shares of Mitchell Energy, and most of his wealth was wrapped up in the stock. He had pledged sizable donations to the Houston Symphony, a performing arts center in the Woodlands, and a think tank he had created by borrowing from a syndicate of ten banks. His Mitchell Energy stock collateralized the loans. As the stock price fell from $35 to $10, the banks clamored for more collateral. Todd Mitchell, his son, tried to keep the bank syndicate from foreclosing the loan and seizing Mitchell Energy stock. If the banks had demanded the stocks, George Mitchell would have lost control of his company. At the same time, George Mitchell was being treated for prostate cancer, and his wife, Cynthia, was showing early signs of Alzheimer’s disease.
As news of the new fracking success filtered up to Mitchell and the board, they set a plan in motion. The company would double its pace of drilling Barnett Shale wells, increase its value, and then find a buyer. By 1999, the Mitchell family had decided it was time to get out of the oil and gas business. It hired Goldman Sachs to sell the family firm. No one wanted to buy it. The company had achieved a technological breakthrough that was so revolutionary and violated so many basic tenets of finding oil and gas that workaday engineers weren’t prepared to believe
it. A data room was set up in Houston where prospective buyers could look at a wealth of information on Mitchell’s wells and acreage. A few companies visited it, but left befuddled.
Mitchell’s timing was terrible. Oil prices were low, and big oil companies were focused on megamergers to drive down costs and put them in a position to compete for giant, unimaginably complex overseas projects that often cost tens of billions of dollars. BP kicked off this consolidation spree in 1998 when it bought Amoco and then, a few months later, Arco. Exxon swallowed Mobil in 1999, reuniting two of the largest pieces of Rockefeller’s Standard Oil. A year later, Chevron and Texaco joined together, and Conoco and Phillips Petroleum joined a year after that. Wall Street rewarded these marriages. With the exception of big deepwater fields in the Gulf of Mexico, analysts and industry engineers considered the United States picked over and used up. A Big Oil executive proposing buying a gas field in North Texas not only would have been swimming against the current but also would have been putting his career in jeopardy.
Even the smaller energy companies that focused on the United States weren’t particularly interested. Jeff Hall, part of a Devon Energy technical team that assessed potential acquisitions, traveled to Houston to examine Mitchell Energy. He was underwhelmed. “My view was, ‘Eh, this is kind of a marginal deal,’ ” he recalled. “It looked like a bunch of old, tired conventional production.” Even the new Barnett Shale wells didn’t pique his interest. He remembers thinking these wells took a lot of work and a lot of money. And for what? He returned to Oklahoma City and prepared to brief senior management. Devon was a company that liked to purchase other companies. Hall’s job was to be the naysayer and dowse the company’s acquisitive enthusiasm with cold water when the data didn’t warrant it. He came to the meeting to discuss a Mitchell acquisition with a bucketful of ice-cold water. One of the stumbling blocks, Hall told Devon’s chief executive, Larry Nichols, and other managers was that no one on the assessment team understood how the gas was being produced out of the shale. “We turned up our noses because we didn’t think it would work,” Nichols recalled. In April 2000, after a few months during which the data room drew as much interest as a clunker on a used-car lot, Mitchell Energy ended the sale.
