PROLOGUE PROLOGUEAmerica’s rise to global economic preeminence was built first and foremost on its splendid endowment of natural resources. From the 1870s, the great Midwestern “factory farms”—where fields could be plowed in mile-long straight lines—dominated world grain output. The Lake Superior iron deposits may have been the world’s richest, and were ideal for steelmaking. Add the California gold bonanza and the great anthracite seams of Pennsylvania.
But oil was the quintessential American industry. Unlike ore and coal, oil wasn’t wrested out of the earth in pickaxe-size bites. When you found an oil deposit and drilled into it, it gushed. And as John D. Rockefeller was the first to appreciate, with most transport by pipeline, oil scaled like no other industry. For a few decades in the nineteenth century, Standard Oil had nearly the whole world market to itself.
After Standard Oil was broken up, the industry’s center of gravity shifted to the mid-continent region stretching from the Texas Gulf Coast through almost the whole of Oklahoma and into eastern Kansas. Much of this is rolling, open-sky country, and in both Oklahoma and Texas, the industry existed cheek by jowl with cattle ranching. They share a swaggering, high risk, brush-off-the-losses-and-start-over approach to the world and, especially in oil, the greatest gushers, along with sudden fabulous wealth, often came only after years of dry holes.
Oklahoma City is one of the epicenters of the shale-based gas and oil boom spreading through the geographic midlands of the United States. Some 400 million years ago, much of the region between the western slopes of the Appalachians and the eastern slopes of the Rockies was covered by inland seas. In geologic time, sedimentary mud was compressed into thin layers of relatively impermeable shale rock, trapping decaying organic matter, which was gradually transformed into the multiple hydrocarbon compounds that humans burn for artificial light and heat. Eons ago, we began to exploit the oil in surface puddles that seeped from the ground; just over a century and a half ago, we discovered that we could tap into deep-underground pools of oil and gas that had leaked from the shale formations into natural reservoirs. And now, within just the last couple of decades, we have learned how to wrest hydrocarbons directly from the shale, which could multiply America’s recoverable hydrocarbons by a factor of five, wipe out our energy trade deficits, and give a big boost to our industrial competitiveness.
Devon Energy is one the bigger independent players in the shale gas and oil industry, and by market value, the biggest of the Oklahoma independents. Compared to the global oil majors like ExxonMobil and Shell, Devon is a midsize company. By most real-world measures, it’s a giant, generating $9–10 billion in annual revenues, with free cash flow in the $4–5 billion range, and only modest debt. The skyline of Oklahoma City is dominated for miles by the new Devon headquarters, a soaring 52-story glass tower that opened in 2012. All leaders of red-state companies are fiercely resistant to federal regulation, and the board chairman of Devon, Larry Nichols—he and his father founded the company in 1971—is no exception. But he takes environmental issues seriously, and the company has won Environmental Protection Agency (EPA) and Bureau of Land Management awards for reducing emissions and other adverse environmental impacts.
On a bright morning in January 2013, I was in the back seat of an SUV driving west from Oklahoma City to visit some Devon wells at different stages of the drilling and recovery process. The driver was Tim Hanley, a media relations staffer with thirty years of local newspaper and public relations experience; Robert Brodbeck, a senior petroleum engineer was with us as a technical resource. He is in his fifties, pleasant, strongly built, with a ruddy, weathered face and a Hemingway beard. He answered questions carefully, completely, with a military-style, nothing-but-the-facts, taciturnity.
Such visits, I had discovered, are very hard to arrange—doubtless because of the controversies over shale gas and oil, and the use of hydraulic “fracking”—rock-fracturing techniques that are used to loosen the shale-bound products. I was on this one through the good offices of Robert Bryce, also on the trip. He’s a native Tulsan and a long-time Texas resident, and a veteran reporter on the energy and oil business. He’s also a fellow PublicAffairs author, and drew on his contacts to shoehorn me into this trip, then decided to come along himself to catch up on the newest rig technology. The gold star for making the trip happen, however, goes to Sarah Terry-Cobo, a smart, thirtyish reporter for the main Oklahoma business newspaper, the Journal-Record. She wangled the trip permission during a happenstance conference conversation with Nichols, so Robert and I were riding her coattails. Sarah is a self-described Okie who did her graduate work at Berkeley, worked as an investigative reporter in California, then came back to Oklahoma to take up the health and energy beats at her paper. We brought our own boots, and the company furnished hardhats, safety glasses, and fire-resistant smocks. Brodbeck looked like an exception to the fire-resistant rule, wearing a pressed flannel shirt and jeans; when I asked him, he showed me the labels. If you’re around rigs all the time, you buy only fire-resistant work clothes.
Oklahoma City is on the eastern edge of the state’s wheat belt, one of the most productive in the country. We were driving through rolling grassland, and crossed the Chisholm Trail just west of the city. There were constant markers of the importance of the oil and gas business—chain-linked acres of stacked pipe; parking yards for giant sand trucks; a Devon gas compression and purification plant; rigs sticking up here and there in the grasslands. Near the end of the drive, we traveled a short distance on the old Route 66, the road that John Steinbeck’s Okies traveled fleeing the Dust Bowl tragedy of the 1930s. The state has preserved an original segment, just two strips of concrete, with an irregular center line, no painted markings, and no shoulders. The shale underlying this part of the state is called the Cana-Woodford, a particularly favored location since it is rich in natural gas liquids (NGLs) that can be converted into many of the same products as those from crude oil.
After about forty-five minutes, we shifted to hard-packed clay back roads, laid out in perfect squares, and finally we turned onto an asphalt road with a row of ten identical rigs each about a quarter-mile apart. Almost all the independent Exploration and Production (E&P) companies contract out drilling and well completion to oil field service companies, like Halliburton and Schlumberger, which are among the biggest worldwide. The driller specialist Devon was using on these rigs, Helmerich & Payne, is another Oklahoma company with international reach, and like Devon, illustrates what a fast ride these firms have enjoyed. In 2000, H&P had seventy-six active rigs roughly split between the United States and overseas. Revenues were $351 million with an operating profit of $46 million. In 2012, with 336 rigs, 240 of them active in the United States, revenues were $3.2 billion, with $910 million in operating profit. The company has almost no debt and threw off more than $1 billion in free cash, all of which went to capital expenditures.1
Shale drilling poses unique challenges. The shales are often very deep underground and, although they extend for hundreds of miles horizontally, they are typically only hundreds of feet thick. In contrast to conventional oil and gas wells, the hydrocarbons in shale are distributed thinly, so in order to be cost-effective the well has to access a very large area of the shale. All ten of the wells on this site will drill down about 12,500 feet then make a ninety-degree turn and extend horizontally through the shale for another mile. The horizontal portion of the pipe is perforated; once the shale is fractured, hydrocarbons will flow into the pipe all along its length, driven by the pressures from the gas in the shale. A rig site, or a pad, can usually accommodate eight to ten wells, but the ten pads at this site will each drill only two or three, due to nuances of the geology.
H&P is the highest-cost driller on a day-rate basis, but still the most cost-effective because of the speed and accuracy of its drilling. It designs and manufactures its own brand of rig, the “FlexRig.” The rig is powered by electricity generated by three large diesel engines. Electrical power allows both higher speeds and precise adjustments of drilling speeds and pressures as the drill progresses through the geologic strata. The FlexRigs—all 136 feet of them—are moved with dozers and cranes from wellhead to wellhead on the same pad, with the platform and the rest of the equipment repositioned around them. H&P has a new line of FlexRigs that are moved by hydraulic pistons on prepositioned tracks to speed up the operation even further. The pad we were visiting had three wellheads quite close together, but as the wells are sunk, the drills are maneuvered so the collection (horizontal) pipes are arrayed in parallel lengths several hundred yards apart.
Brodbeck gave us a brief tutorial on directional drilling. The drill bits—they’re diamond studded and cost about $20,000 apiece—are clamped into pipe-length holders, and turned by a rotor apparatus in the holder that is driven by the force of the drilling mud. To change the direction of the hole, the bit holders are changed for ones that are curved at the end by just a degree or two. It takes about a quarter mile of depth to execute the turn from the vertical to the horizontal. The steel casing pipes are sufficiently flexible that they bend to fit the shape of the hole as they move through it. Only a cable containing electrical wires connects the drilling apparatus to the rig.
There were six H&P employees on site. The driller runs the rig and supervises the derrick man, the motor man, and two roughnecks. They all work twelve-hour shifts for seven days, seven days on and then seven days off. The sixth man, the tool pusher, has the same seven-days-on, seven-days-off tours, but stays on location throughout his days on. Devon is represented by a drilling superintendent and engineer team for each three or four rigs, plus a drilling manager per rig. Since the rigs operate 24/7, four men are needed for each position. The drilling manager at this rig, Tim Taylor, is a great cheerful bear of a man, I’d guess in his mid-fifties. His career has taken him throughout the world, with significant spells at the Aramco sites in Saudi Arabia. He enthused over the new drilling rigs—drilling times have been cut in half compared to just a few years ago. Tool and pipe handling is now very mechanized. The pipes come in thirty-foot lengths. They were once craned up to the drilling platform and wrestled into racks by the roughnecks but are now automatically loaded onto a conveyor belt, stood up in the rig, and connected into ninety-foot “threefers,” all by machine, reducing the number of pipe changes.
Oil and gas field workers are typically big men, heavy around the neck and shoulders. Although mechanization has eliminated a lot of the heaviest work, it still requires a lot of fast, strenuous, coordinated action. Pipe changing is one of the most routine tasks. As the drill pushes to the limit of its pipe, two roughnecks position themselves on the platform and, using giant ratchet wrenches hanging on chains, disconnect the well pipe from the drilling mechanism, swing in a new length of pipe, and lock it into place, all in about thirty seconds, all the time getting spattered by the cascade of drilling water and mud from the disconnected pipe. (A drain pan captures the fluids and they’re recycled.) Twelve hours of that, plus all the routine rig maintenance tasks, adds up to a solid workday, with no space for shirkers.
The drilling cab housing is the nerve center of the operation. Much of the drill routine is preloaded into the computer, and an array of digital displays tracks the progress both visually and numerically. But since nothing ever goes completely as planned, the driller plays a crucial role, rather in the way an airline pilot earns his pay during high-stress moments. The driller for this rig, Artie White, a young man of about thirty, has been with H&P for eight and a half years. He worked every rig job for the first three years before being promoted to driller. When we were there, a tool had broken in the well—it happens—and Artie was carefully backing the drill out, using mud to clear any small metal filings from the break. Because the shifts are so long, I asked Tim about lagging attention during long periods of computer control, a well-known issue for airline pilots. He explained that there are arrays of alarms if a value varies outside of the programmed range, and the driller’s displays, as well as the alarms, display throughout the company on its internal web. Tim pulled them up on his Smartphone for me. So a driller is never completely on his own. Later I asked Norm Naill, Tim’s boss, what a driller got paid. He guessed between $28 and $32 an hour, with good benefits. Part of the 84-hour duty stretches also counted as overtime, so the gross annual pay would come out to between $77,000 to $88,000, with perhaps a 10 percent bonus on top of that. The roughnecks’ annual pay was lower, of course, but not that far behind. So these were all young guys making a very good living on the ground floor of an industry that looked to keep expanding for a long time.
After a couple of hours at the rig, as we were getting ready to leave, I was standing with Tim, and he beamed, “Charlie, I can’t believe I get paid to do this work. I’d be happy to do it for free. I’ve been doing it for a lot of years and I still love every minute of it!”
The next stop on our tour, about a half hour away, was a well in the “completion” stage—actually fracturing the rock and collecting the product. There were three wells on the site, in the form of three stubby, capped pipes sticking up out of the ground, festooned with connection points, valves, and gauges. (The trade calls them “Christmas trees.”) Fracturing takes place in stages. The horizontal well pipes on these wells were about a mile long, and they were doing ten different fracturing events, each one for a 500-foot portion of the shale. The entire fracking process for each well was assumed to take thirty-six to forty-eight hours, on the usual 24/7 two-shift workday schedule. Halliburton was the completion contractor, and everyone on the site wore the company’s bright red coveralls.
The well pad was in a flat, excavated area about fifty yards long, with a further excavated area behind it. There was an array of control trailers where we entered, then the rig and the three wells in a tight row, and to their left several closed sand trucks and chemical tanker trucks. Four six-inch pipes ran on the ground from the first wellhead through the length of the site, passing between an array of eighteen forty-eight-foot-long red Halliburton trucks arrayed tail-to-tail in two neat nine-truck rows. Each of them was a 2,000-horsepower diesel engine with a cab and wheels. Behind them was a mixing tank called the “blender,” and behind that in the second excavated area, ten water tanks. The average Devon well on this site, with three-plus miles of well pipes per well, takes about 7.5 million gallons of water, including drilling and fracking, or roughly twenty-three “acre-feet” of water—picture a square one-foot-deep pool measuring about 1,000 feet on one side.
Bright blue lines of flexible irrigation tubing snaked through the grassland to the tanks, bringing water either purchased from local farmers or recycled from Devon’s own treatment facility. During fracking, water is pumped into the blender where it is mixed with a variety of chemicals to reduce friction and keep the pipes clean, as well as sand of a specific grain size, to prevent fractures from reclosing. One of the big thirty-foot-long sand trailers had been stood on its front end and locked into a sand dispensing machine; it looked like a prehistoric reptile that had stumbled headfirst into a tar pit. The proportions and mixing speeds of the chemicals and the sand were all computer controlled.
When it’s time for the actual fracking, the fluid, or “slurry,” flows through the four pipes between the eighteen diesels, with the capacity to generate 12,000 psi inside the well (but 2,000 psi of “backpressure” is withheld as a safety margin). Apart from the airport-scale noise of the eighteen trucks generating 36,000 diesel horsepower and the visible vibrations in the feed pipes, there’s not much that is noteworthy about a normal frack. The liquid flow is in a closed system—from the tanks through the blender and the powerful gauntlet of diesels into the well, with the bounceback captured in the drainage tanks.
We were at the fracking site for about two hours, so we took potluck on what we saw, which happened to be the perforating of the stage, an intricate and fascinating technology of the kind that evolves over many years with microcontributions from hundreds of craftsmen. The perforating gun tubes were studded with stainless steel openings about an inch wide that fired shaped charges to punch holes through the steel and cement casing.
The team was working on the fourth stage of a frack when we arrived, and we stayed until the perforating guns were in position. Another well-paid thirty-something sat in front of an array of digital displays, much like those in the drilling cab, scrolling rapidly through length markers of the well pipe. As he landed on the proper location, he would say “firing,” a red square would flash on the screen, and an adjoining screen would show a visual pressure wave in the shale. A consulting engineer representing Devon marked each firing and its numerical location. Not taking any chances, a roughneck outside the trailer held the tautly stretched control wire in both hands, confirming each time that he had felt the vibration.
The next work phase would involve extracting the used guns from the well, cleaning any debris, and setting the plugs to isolate the fracking site, all before the pumping started. Because of the length of the pipe, Brodbeck estimated that it would take 2.5–3 hours to complete the fracking. But we were running out of time, and so we headed off for the last station, the first Devon fracking water recycling plant.
Central Oklahoma is typically well-watered, Brodbeck told us, pointing to the treeline of the North Canadian River visible in the distance. It is a distant tributary of the Arkansas River, is typically fast-flowing, and feeds a system of recreational lakes created by Oklahoma City. But the state, like much of the southwest United States, had been locked in a three-year drought, and concern was growing about falling water tables.
All shale drilling sites have holding tanks for used fracking water. Deep rocks are full of noxious elements, and fracking water’s violent trip into and out of the rocks leaves it heavily contaminated. Devon is one of the first companies to create their own centralized collection and treatment facilities in order to reuse both fracking and produced water. Brodbeck estimated that in Cana-Woodford, they recover 40–50 percent of the water and can reuse 90 percent of it. Assuming 45 percent recovery, that would allow them to extend their water supply by about two-thirds. Recovery rates vary considerably by local geology and often even from well pad to well pad.
The operation would not be feasible without a dense concentration of wells, like Devon’s in the Cana-Woodford. The center of the operation is a twenty-one-million-gallon plastic-lined holding field—a small lake—to hold the treated water. Water is trucked in constantly from the Devon wells in the area and treated through a standard filtering and sedimentation process. The clean water drains into the lake, and is tapped by irrigation pipes like those we had seen at the fracking site. The 10 percent of the water that is not reusable is a fairly noxious mixture of salts and metals. But the volumes are modest, and the company has dug a disposal site, where the waste is injected thousands of feet under the surface, that will serve, one hopes, as its permanent home.
Devon hasn’t released the exact cost of the facility, but it certainly cost the millions the company claims. Since water is badly underpriced throughout America, the plant could not be cost-effective, but it is the right thing to do, and at some point should probably be required of all companies. And Devon deserves credit for staying in front of the curve.