by Russell Gold
“Well, it’s pretty much open,” she responds. “What do you think we should do?”
Jangly country guitar music plays in the background.
“I’m fresh out of ideas. You don’t have any ideas?” he asks, looking bored.
“Well, there’s one thing we could do,” she says. The music ends with the sound of the needle being ripped off vinyl. She turns to her husband, her mouth drops open in excitement, and says, “We could ghost ride the whip.”
A rap song begins with a thumping, distorted bass line. Smiley’s grandparents dance in the street on both sides of the canary yellow car as it rolls driverless down a street bordered by towering pine trees. The grandfather wears sunglasses and some sort of a doo-rag on his head. For the next minute, the couple dances as the car continues to roll forward. He puts his hands on his knees for an improbable few seconds of the Charleston. She grabs the hood and kicks her feet out. It is a suburban send-up of a dangerous Bay Area tradition.
The clip went viral. It had one million views in a year and another million the next year. I first saw it when a Houston energy investment bank included a link to it in an email to clients and reporters. The bank noted that the man was none other than Dr. Claude E. Cooke Jr., a “legend of hydraulic fracturing.” I met Cooke a couple years later, after he’d called me to talk about fracking. After a couple meetings, in which he wore immaculately pressed Oxford shirts, it occurred to me that he was the grandfather in the “Ghost Ridin’ Grandma” YouTube clip.
I watched the video again, amused by this strange connection. His claim that he was fresh out of ideas couldn’t be further from reality. Cooke has two dozen patents. Even in his ninth decade, he is filing new ones. This man, who had achieved a level of Internet fame alongside cute piano-playing cats and teenage skateboarders with questionable judgment, is an industry legend. In 2006 the Society of Petroleum Engineers honored nine men (they were all men) as “Legends of Hydraulic Fracturing” for seminal innovations. While most of the honorees had a single contribution, Cooke had three.
When Cooke first called me, he wanted to talk about how to build a better well. Fear that fracking itself could contaminate water, he argued, was misplaced. The cracking of shale generally takes place a mile or two underground and thousands of feet below freshwater aquifers. Getting to that rock, however, means drilling a long hole in the ground. A slow migration up through rock strata that would take thousands or millions of years can occur in minutes through a well. In its search for hydrocarbons, the industry builds superhighways that traverse geologic epochs. Worry about the wells, he said, not fracking.
A couple weeks after our first phone conversation, we met in his office in Conroe, Texas, a few stops on the interstate north of downtown Houston and near George Mitchell’s Woodlands development. On the walls are black-and-white photographs of a 1970s frack job in the Texas panhandle. The photos show Halliburton and Exxon engineers studying a pressure gauge that looks like an old-fashioned Hollywood movie camera. A young Cooke stands in the middle of the pack of engineers. “If there is a problem, the issue is well integrity,” he explained, fixing me with a hard stare through wire-frame glasses. If something goes wrong with a fracked well, the likely problem is faulty cement. Cooke said that people concerned about fracking were trying to fix a problem that didn’t exist and ignoring the problem of poorly built wells that was staring them right in the face. If the industry built better wells, he said, you could eliminate problems with water contamination.
The purpose of a well is to reach deep into the earth and suck out long-buried oil and gas. But wells must also be constructed to prevent unintended movement of salty water or contaminants. The industry takes many steps to make sure that the open hole it has drilled is contained, constricted, checked, and controlled. It inserts steel pipe, called casing, into the open holes and locks it into place. Then it pumps in cement to secure the pipes and achieve “zonal isolation.” This is industry jargon, he said, for keeping the gas, or salty water, in one rock from flowing into another. The cement may sound mundane, but it is big business in the oil fields. The energy industry spends about $105 billion annually to extract energy from North America using hydraulic fracturing. About $5 billion of the $105 billion outlay is spent on cementing. This is not off-the-shelf cement found at Home Depot. The oil industry uses an extensive selection of densities, additives, and ingredients. A standard guide to oil-field cementing runs 171 pages.
How many wells have been constructed to withstand a lifetime in the earth? How many have effectively created a single pathway for oil and gas to flow up the inside the casing? And how many have left channels and holes in the cement outside the pipes? Considering how important these questions are, there are no satisfying answers. There is a subsubspecialty of oil-field services called, prosaically, cement evaluation. Only a tiny fraction of the $5 billion spent on cementing is used to evaluate the cement itself.
There are engineers and executives in the industry who share Cooke’s view of the importance of building wells right. So does Mark Zoback, a Stanford University geophysicist who served on the US Energy Department committee that studied shale production. To eliminate risks, he told me, “There are three keys—and those are well construction, well construction, and well construction.” Industry studies and experts concur that cement in wells fails regularly to one degree or another, although rarely catastrophically. The failures tend to be small and subtle but significant enough over time to cause problems. Gas seeping through faulty cement can get into shallow aquifers, infusing them with high levels of methane. Residential water wells that tap these aquifers can pump flammable gas up into homes. Usually, regulators will shut down the well and require the home to use water from refillable plastic “buffaloes” that sit outside the home. Sometimes, expensive ventilation pipes and filtration systems can restore potable water. In other cases, the well is lost, rendering the home uninhabitable. This is what happened in 2010 in Bradford County, Pennsylvania. State investigators found “improper” cementing and well construction. Chesapeake, the driller, paid a record fine to the state. Later, after a lawsuit, it bought out the homes of sixteen families, who moved elsewhere.
Toward the end of my first meeting with Cooke, I asked him what he would demand if he owned land and leased it to be drilled. “Well, I would be pretty sticky about it,” he responded. He said he would demand proof that neither gas nor liquids were flowing through the cement that encircled the steel pipe. I asked how he would do that. He stood up and walked to his door and politely asked his assistant to bring a two-page printout of his patents and publications. She came in and gave him the document, which he passed to me. “You see number ten?” he asked. I looked at the printout and saw a reference to a 1979 paper from the Journal of Petroleum Technology. It described a “new tool for detecting and treating flow” in the cement. “I would tell them, ‘I want you to run that tool in the well,’ ” he said.
There was only one problem. The tool—his creation—wasn’t available anymore. It had disappeared from the market. Cooke then told me he was thinking of trying to bring it back.
In 2010 Cooke woke up in the middle of the night thinking about cement and his tool for the first time in a quarter century. The Deepwater Horizon was in the news. The giant offshore floating platform had lost control of the well it was drilling in five thousand feet of water, nearly fifty miles from the Louisiana coast. The resulting explosion had killed eleven workers. BP scrambled for months to cap the half-finished well sitting on the seafloor. Millions of barrels’ worth of oil flowed into the Gulf of Mexico, making it “the worst environmental disaster America has ever faced,” according to a presidential commission that examined the disaster.
I covered the Deepwater Horizon for the Wall Street Journal. Early on, much media attention focused on the failure of the blowout preventer, a several-story-tall set of valves on the ocean floor that was supposed to deploy giant shears to cut and seal off the well. It came within two inches of clamp
ing shut, but it didn’t close off the oil flow. Soon after the blowout, many petroleum engineers began to suspect the root problem was that something had gone wrong with the well construction, and, in particular, the cement in the wellbore. Cooke was among the industry insiders who zeroed in on the cement. As the well gushed crude into the gulf like an open wound, Cooke woke up thinking about the well. He thought about his invention, called a radial differential temperature log, or RDT, and whether it could have prevented the disaster. He decided the answer was likely yes.
It is impossible to know if his tool would have detected cement problems on the Deepwater Horizon, but it is possible that using better cement evaluation tools would have helped. A couple days before BP lost control of the well, the company’s foreman on the rig ordered a full suite of diagnostic tools to make sure the cement had set and formed a solid seal. Oil-field service company Schlumberger sent a team to the rig by helicopter. To most people, Schlumberger is not as well known as Halliburton, which vaulted into the public eye after Dick Cheney, its chief executive, left the company to join George W. Bush’s presidential ticket. Despite a lower profile, Schlumberger, or Big Blue, as it is known, is the largest Western oil-field service company in the world, followed by Halliburton, aka Big Red. Schlumberger’s crew arrived on the Deepwater Horizon on April 18, 2010, two days before the well blowout. BP had ordered a cement bond log as well as more sophisticated tools, including an isolation scanner, which is similar in some respects to Cooke’s tool.
The crew members waited for two days to run the tests and then BP sent them home. They departed by helicopter ten hours before the explosion. The tests were never run. Schlumberger charged BP $128,000 for its workers and tools, even though they didn’t do anything. The bill was a rounding error for a well that cost about $100 million. However, the well was running over budget and had taken more time than expected. Running the Schlumberger tests would have required eight hours. BP relied, instead, on another test to determine if the well was secure. The test results were confusing and anomalous. Instead of stopping work to figure out what was going on, workers aboard the drilling rig decided to press ahead. The federal government would later file criminal charges against two BP workers responsible for running and interpreting this test. The cement had not created an effective barrier, and without detecting this failure, BP and the crew were dangerously vulnerable.
Shales aren’t high-pressure reservoirs, like the one encountered by the Deepwater Horizon drilling rig. When BP’s drill bit reached the targeted sandy reservoir, a combustible mixture of natural gas and petroleum liquids in the pressurized “pay zone” pushed its way up and out of the well and onto the floor of the drilling rig, where it ignited with lethal results. Drill into shale and nothing will happen. Companies need to smash the shale into submission before it gives up its hydrocarbons. Cooke understood this distinction. But the basic principle of well integrity is the same, he thought. If a company spends the time and uses tools to determine if a well is cemented, the well will be safer for the workers and have a much lower chance of contaminants coursing through tiny channels outside of the pipe, reaching the surface, or finding a way into a shallow drinking-water aquifer. “A channel doesn’t have to be very big to carry a lot of fluid; a finger is enough,” said Cooke.
The problem with a tool like Schlumberger’s isolation scanner is that it is so expensive. It is generally used only in the industry’s most challenging wells, if then. It relies on four transducers that emit high-energy pulses. The tool Cooke invented was simpler. It was a fancy thermometer. And as Cooke told me once by email, “Temperature measurements are cheap.” Because the tool is less expensive to manufacture, Cooke believes it could be widely deployed in the thousands of shale wells being drilled every year. Each could provide a measure of assurance that the well wouldn’t leak and leave behind an environmental mess.
The shortcomings with cement—both in deepwater wells and less complex onshore wells—are one of the industry’s best kept secrets. The industry talks regularly about the protection against dangerous blowouts and groundwater contamination that cementing wells provides. But cementing, despite huge technological improvements, remains an imperfect science. In an exhaustive report of the causes of the BP Deepwater Horizon offshore catastrophe, a national commission noted that “cementing an oil well is an inherently uncertain process. . . . Even following best practices, a cement crew can never be certain how a cement job at the bottom of the well is proceeding as it is pumped. Cement does its work literally miles away from the rig floor, and the crew has no direct way to see where it is, whether it is contaminated, or whether it has sealed off the well.” While it sets, the cement is exposed to extreme heat, pressure, and contaminants. Hairline seams can appear in the cement, or even larger finger-sized holes, that undermine cement effectiveness. The cementing crew is left with incomplete and indirect measurements. It can be like trying to determine someone’s gender by looking at his or her shadow through a telescope.
“Why doesn’t the oil industry pay more attention to cementing problems?” Cooke asked rhetorically during one of our meetings. “I answered my own question over a period of time: because it costs money to do it, and there is no pressure to do anything.”
Cooke was born in El Dorado, Arkansas, in the midst of an oil boom. Nearly everyone’s father worked for an oil company. His dad worked on wells for Magnolia Petroleum, a forerunner of today’s Exxon Mobil. Pride in the dangerous, tiring work passed from one generation to the next. Cooke recalled that in the small oil-field elementary school, if a kid made a disparaging remark about your father’s employer, there would likely be a fight. While his own father’s formal education stopped short of a high school diploma, Cooke’s mother had higher aspirations, first for herself and then for her son. She attended college and wanted a degree in chemistry, but her father didn’t believe that science was an acceptable profession for women. Settling for a teacher’s certificate, she poured her dreams into her son. From the time he was a little kid, Cooke said his mother told him, “You are going to get a PhD. You are going to have plenty of education.”
Cooke never strayed from the path his mother laid out for him. After attending Louisiana Tech University, he went to the University of Texas and earned his PhD in a field of physics that dealt with the interaction of molecules. Then he returned to the industry that dominated his youth. For three decades, he was a standout at Exxon’s research facility in Houston, a concentration of talented scientists who threw off innovations that helped transform a superstition-soaked industry from one that ran on hunches into one that embraced science to solve problems. When Cooke started work at the research center, in 1954, there were still wildcatters around who used witching twigs to find oil. By the time he left in 1986, the industry could send sound waves through thousands of feet of rock, process the bounced-back signals through some of the world’s fastest computers, and find oil. This technique was invented at Exxon’s research facility in Houston. “I spent thirty-two years there, and I enjoyed every day of it,” said Cooke.
Over the years, he made his share of innovations. One was the radial differential temperature logging tool. It looks like a long, skinny metallic pool cue that drillers lower into oil wells to figure out if the cement hidden away behind the pipes had set properly. It is a high-tech whirligig on the end of a long steel tube that spins in the well and can sense minute fluctuations in temperature that are telltale signs of water or gas flowing through cement. In most wells today, companies run what’s called a cement bond log. The CBL uses acoustic signals to “listen” to the pipes. Cement that has adhered to the outside of the pipe, creating a solid seal, makes a different sound from cement that has left even a microscopic gap. But a cement bond log can’t tell if there is a channel an inch or two away from the outside of the pipe where high-pressure gas is flowing. The cement bond log, said Cooke, gives drillers a false sense of confidence.
“What the industry says will determine whether or not a c
ement job is adequate, I don’t agree with. The industry says you run a cement bond log,” he said, banging his open palm on the table to punctuate the last three words. “They say if you get a good bond, you get a good cement job. That is not true. Not true.” Another two palm slaps. “You can have flow in the annulus, in channels, through the cement, or between the cement and the formation.” The cement bond log is a good test, he said. “It is necessary, but not sufficient as a mathematician would say.” The industry is fooling itself—and fooling the public, he believed. The industry needs to run better cement evaluation tools down wells. Think of it as preventative medicine, he said, to find problems before they spin out of control.
The government issued Exxon Patent 4,074,756 in 1977 for his invention. A series of field tests showed that it was better than a CBL at finding leaks. Cooke was canny. He didn’t pitch the tool to his Exxon bosses as a leak-detection device. Instead, the tool’s original purpose was to determine if the cement had created a good enough seal to keep oil production healthy. Not long after he had a working prototype, an Exxon colleague working on the sprawling King Ranch in South Texas called him. “There’s too much water in the well, and it’s choking off the oil flow,” his colleague said. “Get down here with that tool and figure out where the water is leaking into the well.” Another call came from an Exxon team in Germany. For a year, he went around the world with the tool, running it down Exxon wells. As the RDT was lowered into the well, the tool deployed two small prongs that pressed up against the inside of the well and then rotated in circles. This rotation gave a 360-degree view of what was hidden behind the pipe. Since a small channel of gas or water will create a slight fluctuation in the pipe’s temperature, he calibrated the tool to detect a difference of less than 0.01 degree Fahrenheit. “In many cases, I found flow behind casing, in some places where it had not been known. There was no other technique that would have detected it,” he recalled. With his RDT, he could accurately find leaks and shut them down by puncturing the well and squeezing in new cement.
