Read an Excerpt

Blowout!

April 20, 2010. Though a bit imprecise, the time, approximately 9:50 p.m., marks the end of knowing much precisely. A floating machinery system roughly the size of a forty-story hotel has for months been drilling into the seafloor in the Gulf of Mexico. Its creators have named the drilling rig the Deepwater Horizon.

Oil giant BP has contracted the Deepwater Horizon’s owner, Transocean, and various companies and crews to drill deep into the seafloor forty-odd miles southeast of the Louisiana coast. The target has also been named: they call it the Macondo formation. The gamble is on a volume of crude oil Believed Profitable.

Giving the target a name helps pull it into our realm of understanding. But by doing so we risk failing to understand its nature. It is a hot, highly pressurized layer of petroleum hydrocarbons—oil and methane—pent up and packed away, undisturbed, inside the earth for many millions of years.

The worker crews have struck their target. But the Big Payback will cut both ways. The target is about to strike back.

A churning drill bit sent from a world of light and warmth and living beings. More than three miles under the sea surface, more than two miles under the seafloor. Eternal darkness. Unimaginable pressure. The drill bit has met a gas pocket. That tiny pinprick. That pressure. Mere bubbles, a mild fizz from deep within. A sudden influx of gas into the well. Rushing up the pipe. Gas expanding like crazy. Through the open gates on the seafloor. One more mile to the sea surface.

The beings above are experiencing some difficulty managing it. A variety of people face a series of varied decisions. They don’t make all the right ones.

Explosion.

Fireball.

Destroyed: Eleven men. Created: Nine widows. Twenty-one fatherless kids, including one who’ll soon be born. Seventeen injured. One hundred and fifteen survive with pieces of the puzzle lodged in their heads. Only the rig rests in peace, one mile down. Only the beginning.

Blowout. Gusher. Wild well. Across the whole region, the natural systems shudder. Months to control it. Years to get over it. Human lives changed by the hundreds of thousands. Effects that ripple across the country, the hemisphere, the world. Imperfect judgment at sea and in offices in Houston, perhaps forgivable. Inadequate safeguards, perhaps unforgivable. No amount of money enough. Beyond Payable.

Deepwater exploration had already come of age when, in 2008, BP leased the mile-deep Macondo prospect No. 252 for $34 million. By 1998 only two dozen exploratory wells had been drilled in water deeper than 5,000 feet in the Gulf of Mexico. A decade later, that number was nearly three hundred.

With a platform bigger than a football field, the Deepwater Horizon was insured for over half a billion dollars. The rig cost $350 million and rose 378 feet from bottom to top. On the rig were 126 workers; 79 were Transocean employees, 6 were BP employees, and 41 were subcontractors to firms like Halliburton and M-I Swaco. None of the Deepwater Horizon’s crew had been seriously injured in seven years.

Operations began at Macondo 252 using Transocean’s drilling platform Marianas on October 6, 2009. The site was forty-eight miles southeast of the nearest Louisiana shore and due south of Mobile, Alabama. As the lessee, BP did the majority of the design work for the well, but utilized contractors for the drilling operation. Rig owner Transocean was the lead driller. Halliburton—formerly headed by Dick Cheney, before he became vice president of the United States under George W. Bush—was hired for cementing services. Other contractors performed other specialized work.

The initial cost estimate for the well was approximately $100 million. The work cost BP about $1 million per day.

They’d drilled about 4,000 feet down when, on November 8, 2009, Hurricane Ida damaged Marianas so severely that the rig had to be towed to the shipyard. Drilling resumed on February 6, 2010, with BP having switched to Transocean’s Deepwater Horizon rig.

By late April, the well would be about $58 million over budget.

Being a deepwater well driller—what’s it like? To simplify, imagine pushing a pencil into the soil. Pull out the pencil. Slide a drinking straw into that hole to keep it open. Now, a little more complex: your pencil is tipped not with a lead point but with a drilling bit. You have a set of pencils, each a little narrower than the last, each a little longer. You have a set of drinking straws, each also narrower. You use the fattest pencil first, make the hole, pull it out, then use the next fattest. And so on. This is how you make the hole deeper. At the scale of pencils-as-drills, you’re going down about 180 feet, and the work is soon out of sight. As you push and remove the pencils, you slide one straw through another, into the deepening hole. You have a deepening, tapering hole lined with sections of drinking straw, with little spaces between the hole and each straw, and between the sections of straw. You have to seal all those spaces, make it, in effect, one tapering tube, absolutely tight.

And here’s why: the last, narrowest straw pokes through the lid of a (very big) pop bottle with lots of soda containing gas under tremendous pressure. As long as the lid stays intact and tight, there’s no fizz. But only that long. Everyone around you is desperate for a drink of that pop, as if they’re addicted to it, because their lives depend on it. They’re in a bit of a hurry. But you have to try to ignore them while you’re painstakingly working these pencils and straws. And you’d better keep your finger on the top of the straw, or you’re going to have a big mess. And you’d better seal those spaces between sections of straw as you go down, or you’re going to have a big mess when you poke through that lid. And before you take your finger off the top of the straw, you’d better be ready to control all that fizz and drink all that pop, because it’s coming up that straw. And if, after poking a hole in this lid that’s been sealed for millions of years, you decide you want to save the soda for later, then you’d better—you’d better—have a way to stopper that straw before you take your finger off. And you’d better have a way to block that straw if the stopper starts leaking and the whole thing starts to fizz. If it starts to fizz uncontrollably, and you can’t regain control, you can get hurt; people can die.

The real details beggar the imagination of what’s humanly and technologically possible. Rig floor to seafloor at the well site: 5,000 feet of water, a little under one mile. Seafloor to the bottom of the well: about 13,360 feet—two and a half miles of drilling into the seabed sediments. A total of 18,360 feet from sea surface to well bottom, just under three and a half miles.

Equally amazing as how deep, is how narrow. At the seafloor—atop a well 2.5 miles long—the top casing is only 36 inches across. At the bottom it’s just 7 inches. If you figure that the average diameter of the casing is about 18 inches, it’s like a pencil-width hole 184 feet deep. Nine drill bits, each progressively smaller, dig the well. The well’s vertical height gets lined with protective metal casings that, collectively, telescope down its full length. At intervals, another telescoping tube of casing gets slid into the well hole. The upper casing interval is about 300 feet long. Some of the lower ones, less than a foot across, are 2,000 feet long. The casings and drill pipes are stored on racks, awaiting use. Casings are made in lengths ranging from 25 to 45 feet; the drill pipe usually comes in 30-foot joints. They are “stacked” in the pipe racking system. You assemble three at a time and drop approximately 90 feet in, and then repeat. When you get ready to put the casing in, you pull all the drill pipe out. Rig workers also remove the drill pipe from the hole every time the drill bit gets worn and needs changing or when some activity requires an open hole. Pulling the entire drill string from the hole is called “making a trip.” Making a trip of 10,000 feet may take as long as ten or twelve hours. The uppermost end of each casing will have a fatter mouth, which will “hang” on the bottom of the previous casing. You will make that configuration permanent with your cementing jobs. When you want to start drilling some more, you have to reassemble the drill pipe and send it down.

On drillers’ minds at all times is the need to control the gas pressure and prevent gas from leaking up between the outside of the casings and the rock sides of the well. At each point where the casing diameter changes, the well drillers must push cement between the casings and the bedrock wall of the well. This cements the casings to the well wall. It controls pressure and eliminates space.

Drillers continually circulate a variety of artificial high-density liquid displacements or drilling fluids, called “mud,” between the drill rig and the well. The circulating fluid is sent down the drill pipe. It causes the drill bit to rotate, then leaves the drill bit and comes up to the surface, carrying the loose rock and sand that the drill bit has ground loose. Because the well is miles deep, the fluid creates a miles-high column of heavy liquid. (The drilling fluid is heavier than water. Imagine filling a bucket with water and lifting it; then imagine that the bucket is three miles tall. It’s heavy.) That puts enormous downward pressure on the entire well bore. As the drill digs deeper, the drilling “mud” formulation is made heavier to neutralize the higher pressures in the deepening depths. But that heavier fluid can exert so much pressure on the shallower reaches of the well (where the ambient pressure is less) that it can fracture the rock, damage the well, seep away, and be lost into the rock and sand. Steel casings can protect weaker sections of rock and sand from these fluid pressures.

Because things fail and accidents happen, a 50-foot-high stack of valves sits on top of the well on the seafloor. Called a “blowout preventer,” it is there to stop the uncontrolled release of oil and gas when things go wrong in a well. If something goes seriously wrong below, the valves pinch closed, containing the pressure. The blowout preventer is relied on as the final fail-safe.

Designs vary. This rig had a 300-ton blowout preventer manufactured by Cameron International. A blowout preventer’s several shutoff systems may include “annulars,” rubber apertures that can close around any pipe or on themselves; “variable bore rams,” which can seal rubber-tipped steel blocks around a drill pipe if gas or oil is coming up outside it; “casing shear rams” or “super shear rams,” designed to cut through casing or other equipment; and “blind shear rams,” designed to cut through a drill pipe and seal the well. Blind shear rams are the well-control mechanism of last resort. Though often designed with redundant equipment and controls, blowout preventers can fail. On occasion, they have. Neither casing shear rams nor blind shear rams are designed to cut through thick-walled joint connections between sections of drill pipe. Such joints may take up as much as 10 percent of a pipe’s length. So having redundant shear rams ensures that there is always one shear ram that is not aligned with a tool joint.

The drilling fluid is the primary stopper for the whole well. If you’re going to remove that stopper, you’d better have something else to hold the pressure. Usually, that something else is several hundred feet of cement. On the night of the explosion, as rig workers were preparing to seal the well for later use, drillers were told to remove the drilling fluid and replace it with plain seawater—in essence, to pull out the stopper. The cement did not hold. And in the critical moment, the blowout preventer failed. The consequent gas blast was the blowout.

That’s what went wrong. But so many things had gone wrong before the blowout that assistant well driller Steve Curtis had nicknamed it “the well from hell.” Curtis, thirty-nine, a married father of two from Georgetown, Louisiana, was never found.

Right from the start—beginning with Hurricane Ida forcing the Marianas rig off the well location—various things didn’t proceed as planned, or struck people as risky.

The Deepwater Horizon, built at cost of $350 million, was new in February 2001. In September 2009, it had drilled the deepest oil well in history—over 35,000 feet deep—in the Gulf of Mexico’s Tiber Field.

It was a world-class rig, but it was almost ten years old. The wonderful high-tech gadgets that were state of the art in 2001 did not always function as well in 2010. Equipment was getting dated. Old parts didn’t always work with new innovations. Manufacturers changed product lines. Sometimes they had to find a different company to make a part from scratch.

The world has changed a lot since the rig was built. So has software. More 3-D, a lot more graphics. Drillers sit in a small room and use computer screens to watch key indicators. Depth of the bit, pressure on the pipe, flows in, flows out. But on this job, the software repeatedly hit glitches. Computers froze. Data didn’t update. Sometimes workers got what they called the “blue screen of death.” In March and April 2010, audits by maritime risk managers Lloyd’s Register Group identified more than two dozen components and systems on the rig in “bad” or “poor” condition, and found some workers dismayed about safety practices and fearing reprisals if they reported mistakes.

Risk is part of life. And it’s part of drilling. Yet drilling culture has changed, with much greater emphasis on safety than in the past. Many people still working, however, came up the ranks in a risk-prone, cowboy “oil patch” culture. A friend of mine who worked the Gulf of Mexico oil field in the 1970s says, “It was clear to me that I was way underqualified for what I was doing. Safety didn’t get you promoted. They wanted speed. If we filled a supply boat with five thousand gallons of diesel fuel in twenty-five minutes, they’d rather you disconnect in a big hurry and spill fifty gallons across the deck than take an extra three minutes to do it safe and clean. I’d actually get yelled at for stuff like that. Another thing that was clear: if you could simply read or write, you could pretty much run the show. They actually gave oral exams to workers who couldn’t read. I was still a kid, but pretty soon I was put in charge of a supply boat because I could read and write. That was the culture then.” Another friend, now a tug captain, says, “Never in the four years I worked the rig did I hear anyone say, ‘Let’s wait for better sea conditions.’ We were always dragged into situations we didn’t want to be in, doing things I didn’t think were safe. Now it’s a lot better. It used to be the Wild West out there.”

When you pump drilling fluid down the well, it comes out the bottom of the drill pipe and circulates up between the drill pipe and the wall of the well, and comes back to you. For every barrel of drilling fluid you push down, you’d better get a barrel back. If you get more—that’s really bad, because gas and oil are coming up in your fluid. If you get less—that’s really bad, too. Drillers call it “lost returns.” It means the returning fluid has lost some of its volume because fluid is leaking into the rock and sand of the well’s walls, sometimes badly. Sometimes there are fractures in the rock and the fluid’s going there. When it’s leaking like that, you can’t maintain the right pressure in the well to tamp down the pressure of oil and gas that wants to come up from below.

In a March 2010 incident, the rig lost all of its drilling fluid, over 3,000 barrels, through leaks into the surrounding rock and sand formation into which they were drilling.

BP’s onshore supervisor for this project, John Guide, later testified, “We got to a depth of 18,260 feet, and all the sudden we just lost complete returns.”

BP’s senior design engineer, Mark Hafle, was questioned on this point:

Q: “Now, lost returns, what does that mean in plain everyday English?”

Hafle: “While drilling that hole section we lost over 3,000 barrels of mud.”

Three thousand barrels is a lot of barrels. At over $250 per barrel for synthetic oil-based mud, that’s $750,000.

A high-risk pregnancy is one running a higher than normal risk for complications. A woman with a high-risk pregnancy needs closer monitoring, more visits with her primary health-care provider, and more careful tests to monitor the situation. If BP can be called the birth parent, this well was a high-risk pregnancy.

Several times, the well slapped back with hazardous gas belches called “kicks,” another indication that the deep pool of hydrocarbons did not appreciate being roused from its long sleep.

At around 12,000 feet, the drill bit got stuck in rock. The crew was forced to cut the pipe, abandon the high-tech bit, and perform a time-consuming and costly sidetrack procedure around it to continue with the well. The delays cost a week and led to a budget add-on of $27 million.

The work had fallen forty-three days behind schedule, at roughly $1 million a day in costs. At a “safety meeting,” the crew was informed that they’d lost about $25 million in hardware and drilling fluid. Not really safety information. More pressure to hurry.

High-risk pregnancy, added complications. On April 9, 2010, BP had finished drilling the last section of the well. The final section of the well bore extended to a depth of 18,360 feet below sea level, which was 1,192 feet below the casing that had previously been inserted into the well.

At this point, BP had to implement an important well-design decision: how to secure the final 1,200 or so feet and, for eventual extraction of the petroleum, what kind of “production casing” workers would run inside the protective casing already in the well. One option involved hanging a steel tube called a “liner” from the bottom of the previous casing already in the well. The other option involved running one long string of steel casing from the seafloor all the way down to the bottom of the well. The single long string design would save both time (about three days) and money.

BP chose the long string. A BP document called the long string the “best economic case.” And though officials insist that money was not a factor in their decisions, doing it differently would have cost $7 to $10 million more.

BP’s David Sims later testified, “Cost is factor in a lot of decisions but it is never put before safety. It’s not a deciding factor.”

Sims was John Guide’s supervisor. Guide described the long string design as “a win-win situation,” adding that “it happened to be a good economic decision as well.”

Guide insisted that none of these decisions were done for money.

Q: “With every decision, didn’t BP reduce the cost of the project?”

Guide: “All the decisions were based on long-term well-bore integrity.”

Q: “I asked you about the cost of the project. Didn’t each of these decisions reduce the cost, to BP, of this project?”

Guide: “Cost was not a factor.”

Q: “I didn’t ask if it was a factor. I asked if it reduced the cost. It’s a fact question, sir. Did it not reduce the cost, in each case?”

Guide: “All I was concerned about was long-term well-bore integrity.”

Q: “I just want to know if doing all these decisions saved this company money.”

Guide: “No, it did not.”

Q: “All right; what didn’t save you money?”

Silence.

Q: “Which of these decisions that you made drove up the cost of the project, as opposed to saving BP money? Can you think of any?”

Guide: “I’ve already answered the question.”

Q: “What was the answer?”

Guide: “These decisions were not based on saving BP money. They were based on long-term well-bore integrity.”

Some people called the long string design the riskier of two options. Greg McCormack, director of the University of Texas at Austin’s Petroleum Extension Service, calls it “without a doubt a riskier way to go.”

But others disagree. Each of the two possible well casing designs represented certain risk trade-offs. One called for cement around casing sections at various well depths, providing barriers to any oil flowing up in the space between the rock and casing. The other called for casing sections seamlessly connected from top to bottom with no outside barriers except the considerable bottom cement. Investigators would later focus lasers on this aspect of the well design for weeks after the well blew. The cost savings led many to believe that this was a cut corner that resulted in the blowout. Months later, however, it became clear that this decision was not a direct cause of the disaster.