Mid-February 2010
Macondo Prospect
Marianas had left the crew of the Horizon a hole eighteen inches wide and encased by steel pipe and cement, extending 3,902 feet below the sea bottom. But they’d also left a hole of a different kind, a financial one. Even before the BOP breakdown and the hurricane, the Marianas had missed every deadline set for it, and after completing less than a fourth of the well, it had used up half the hoped-for budget.
Now it was the Horizon’s turn to try to subdue Macondo.
According to the well plan, the rig’s first task would be to drill 2,500 feet farther and two inches narrower below the existing bottom and line the hole with sixteen-inch-diameter casing.
From its inception about two thousand years ago in China, the process by which human beings have drilled wells has always entailed impressive engineering—often unprecedented. In an astonishing spurt of ingenuity, driven by a desperate desire to retrieve deep deposits of brine water to produce salt—as essential to the ancient Chinese as oil is to us today—salt miners developed many of the basic strategies used by modern drill hands. They built a derrick of bamboo to support a pulley system that allowed them to raise and drop a bamboo pipe fit with an array of heavy iron drill bits weighing as much as five hundred pounds or more. Several men would stand on a wooden plank set on a fulcrum to raise the drill string, then jump off to let it fall, pulverizing the rock in the well hole. When enough debris accumulated in the well, the drillers would drive down a hollow pipe with a leather flap on the bottom, which acted as a valve. The debris would push up into the pipe, then as the pipe was lifted from the hole, the weight of the debris would push the flap closed, keeping the dirt from falling out the bottom. As the well got deeper, more bamboo segments would be attached to the drill string. If the well walls began to crumble, segments of hollow tree trunks were driven into the hole to act as a casing.
The method used on the Horizon retained an impressive similarity. Bamboo has been switched out for steel in the derrick and the drill pipe, and the drill bits are diamond-encrusted, multi-headed swivels with holes spaced regularly along their extensions that spurt oil-based drilling lubricant called “mud.” Instead of just letting the drill bit fall, the 112,000-pound top drive assembly can spin and drive the drill bit into solid rock at anywhere from 40 to 200 revolutions per minute while exerting a downward pressure of up to 20,000 pounds or more. There are a wide variety of bits for different uses and conditions, but one deep-sea bit, encrusted with synthetic industrial diamonds (diamonds created in a laboratory but with all the hardness of natural diamonds), can cost over a million dollars.
As the diamonds in the bit bore into the rock, the top drive descended down the derrick, pushing and twisting the drill pipe farther into the earth. The liquid drilling “mud” forced through the channels of the drill bit pushed the debris back up the well bore to the surface, just as a raging river carries debris downstream. When the top drive had lowered all the way to the rig floor, it was disconnected from the pipe and raised back up the derrick to await a new 93-foot section of drill pipe, made of three 31-foot individual pipes screwed together, end to end. These assembled sections hung vertically on racks in dozens of rows ten pipes deep, waiting for the driller to thrust them into the hole. Like a massive wind chime, the pipes sang as wind and waves rocked the rig. When the driller was ready, he manipulated his joystick to swing a pipe-handling machine over to the racked pipe, grasp one stand of pipe in its grip, and swing it over the open hole, directly beneath the top drive. Then he let the top drive fall gracefully on its block until it connected to the top of the stand of pipe. A floor hand scooted in with a bucket of the thick grease known as pipe dope, which acted as both lubricant and sealant. He slathered the dope on the pipe’s threads with a paintbrush, then signaled the driller, who lowered the top drive until the bottom of the new pipe met the top of the stand already in the hole. A twist of the driller’s hand rotated the top drive, which turned the pipe until it was firmly connected to the string. Then the drilling resumed.
Depending on the situation, drill pipe weighs anywhere from about 1,500 pounds per 93-foot string, to more than three tons, so by the time the bit reached the Macondo oil deposit, the top drive would be rotating and driving from 200 to 800 tons of steel pipe.
Everything about drilling got more difficult and took longer the deeper the hole went. The weight of the drill string grew incrementally, as did the force needed to turn it. The heat and pressure in the hole increased with every foot of depth. Each time a drill bit had to be changed, the thousands of feet of drill string had to be hauled up and disassembled section by section, then reassembled and lowered back into the hole. As a result, to conserve energy and resources as the depth increased, these deep wells were built like inverted wedding cakes, with the widest sections at the top and increasingly narrower sections below. The narrower the section, the less time, energy, and materials it took to drill, case, and seal it.
The hole itself was just the first step of well construction, the equivalent of a pit dug in the ground for a foundation. When they reached their intended depth, 2,500 feet beyond where the Marianas had stopped drilling, they pulled the drill string up and prepared to lower a 16-inch hollow steel pipe into the hole. Even though the new part of the hole was 2,500 feet long, the 16-inch casing would be much longer, running inside the previous section of the well, from near the top of the 22-inch-diameter pipe that had been installed months earlier by the Marianas to the bottom of the new section. A protruding lip at the top of the 16-inch casing would land on a ledge built into the 22-inch casing, and hang there with only the force of gravity holding it in place until it was cemented and sealed. The drilling schedule called for this section to be completed in six to seven days. But from the beginning, the work fell behind.
Drilling wells is rarely a smooth procedure and after the drill team crossed the 4,000-foot threshold, Macondo started to “kick.” Even small amounts of gas, deep in the earth, expand exponentially as they rise to the surface. A few cubic feet at depth could become enough gas to fill the Superdome at the surface. The explosive expansion of the gas creates tremendous force and pushes everything out of the hole before it. As the Horizon’s drill team bore down—still nowhere near the oil and gas deposits highlighted on the geological surveys—they nonetheless encountered small pockets of gas flowing into the well unexpectedly.
In small doses, with enough warning, kicks can be controlled. Jason Anderson had become an expert in doing just that. Since Jason had come on the rig in Korea, he had worked his way up through the ranks—from a pump man in the mud storage pits to the assistant driller, to driller, to toolpusher—just as everyone had thought he would. At thirty-five, he was essentially a drilling foreman and was headed higher still. Life on the rig wasn’t just a job to Jason; it was a calling. He’d made a point of studying the ways a well could act up, and the art and science of keeping it under control. He knew enough that Transocean had offered him a job as an instructor at their well-control school. Jason was tempted. He wanted to keep moving up. But a teaching gig, a “land job” based in Houston, meant leaving the rig behind and Jason wasn’t ready to do that. He had his sights on senior toolpusher, then OIM. He wanted to do it all.
For the three weeks Jason spent at home every cycle, he liked to kick back, hang out with his family, play golf (badly) with his friends, go hunting (five-year-old Lacy was already talking about coming with Daddy to “boom” her first deer), or maybe take off in the camper his wife, Shelley, always kept stocked and ready to go. He, Shelley, Lacy and little Ryver, who was just starting to walk, could pile in and wander the Texas outback until it was time to fly back to New Orleans to catch the crew copter for another hitch. The brick ranch house on the rural lane in Midfield, Texas, near the Gulf Coast, was his real home, but the rig on the Gulf of Mexico was something like home, too. He spent as much time with his crew as he spent with his family, and he felt almost as essential to their well-being. Especially on jobs like Macondo.
Kicks were always troublesome, but Jason knew what to watch for and how to respond. In some ways, he was like a detective. The drilling team worked blind, essentially jamming sticks down a deep, dark hole. They could only know what was going on indirectly, by making deductions from the evidence of their measurements—and the rig and its drilling equipment were designed to measure just about everything. One of the biggest clues available was always the drilling fluid, called “mud,” for the way it looks and feels. Mud is the lifeblood of the drilling process, and is watched over and obsessed about by “mud engineers.” Nobody on the rig ever so much as smiled at the job title. On a rig, mud was serious business. An oil or synthetic oil-based concoction, it contained barite, or barium sulfate for weight, as well as various chemical additives to tailor it to specific uses and make it environmentally friendly. The mud filled the hole, preventing the walls from caving in. It also served to cool and lubricate the bit as it was forced out of jets at high pressure to carry the drilling debris back up and out of the well. The contaminated mud is processed so it can be reused, but also to learn from the debris. One of the most critical things the debris can indicate is the presence of gas, which is a flashing caution light that a well has ventured into a hydrocarbon zone.
But the first sign of a kick is often seen in the amount of mud that returns. The well bore is filled to the top of the riser with mud. Like a full glass of water held under a faucet, any amount of new mud pumped in should be matched by overflow coming back out. The mud fluid is measured as it goes into the well, pump stroke by pump stroke, and measured again when it comes flooding back out into storage areas called mud pits, which occupy a large portion of the lower deck, just aft of the derrick.
If more mud comes out than was pumped in, that could only mean that something down in the well is pushing back, forcing the mud up and out. That would be the kick. Kicks are fairly common and occur on almost every well. They are nuisances that can become disasters if they aren’t monitored closely and managed adroitly.
Jason was intent on doing both. At the first sign of a kick, he could activate a feature of the blowout preventer called an annular preventer, a (very large) steel-reinforced rubber doughnut that squeezed tightly around the drill pipe and sealed off the space around it. This allowed the well to settle, a strategy similar to capping a soda bottle that’s about to fizz over. It also gave the crew time to pump heavier mud into the well. Mud is significantly heavier than water—which weighs about 8.3 pounds per gallon—and can be made even heavier depending on the additives put into it. Ultimately, it can weigh nearly twice as much as seawater. When you multiply by the thousands of gallons it takes to fill an 18,000-foot hole, that’s a very considerable weight, and usually enough to counter the upward force of oil and gas trying to push to the surface. It’s a very straightforward equation: The downward pressure of the mud has to equal or exceed the upward pressure of the hydrocarbons seeking to escape.
Proper use of these tools controlled the kicks. But all these maneuvers were complicated and took precious time.
Around the middle of February, when it became clear the sixteen-inch pipe section was seriously behind schedule, yet another setback for this Macondo project, the BP company men got itchy. “Let’s bump it up,” one of them said. Jason interpreted that as an instruction to push the drill harder and faster, which could get them through this troublesome section more quickly and hold down the escalating cost. But going faster meant exerting more pressure against the geological formation. And sometimes more is just too much. The terrain traversed by a well is as varied as terrain aboveground. It can range from dense, impermeable rock to pressure-compressed sand that can easily crumble when pushed too hard—which is exactly what happened.
A few days after the company man exhorted the drill team to bump it up, the bottom very literally fell out. The first sign of trouble came once again in the mud in/mud out calculus. Only this time, instead of too much mud returning to the pits, there was too little. Somewhere the walls of the well had given way and the mud was escaping into the surrounding geology. This was not good. The collapsed wall was a structural weakness in the well. But it also meant that barrels of mud were washing away. Despite its name, mud wasn’t cheap. In fact, it cost far more than refined gasoline, between $200 and $500 per 42-gallon barrel. Formation collapse was called a “lost circulation event” on the rig, because the loss of circulating mud was how it was diagnosed. Thousands of barrels’ worth of mud could escape when a well wall failed, so the mud loss alone could very quickly became a million-dollar problem.
Lost circulation could be controlled by pumping even more mud into the hole, this time containing thick and/or sticky additives—including items as humble as ground-up peanut and walnut shells. This “lost circulation material” is plastered against the walls by pressure, forming into a kind of patching material over the gaps.
But pumping and plugging took time. Between the cost of the lost mud, the cost of the replacement material, and the time it took to diagnose and patch the leak, just this first section of the well was on its way to being two weeks late and at least $14 million over budget.
Macondo was beginning to pick up the sobriquet that drillers commonly bestow on the particularly incident-prone holes they drill—“well from hell.” They don’t usually mean too much by it—just another shorthand for the generic gripe of men doing a hard job against stubborn difficulties. But some in the Horizon crew began to take the term seriously.
In late February, an ROV was cruising around the wellhead when an operator noticed something on his video monitor. There was a definite spurt coming from a joint in the hydraulic lines leading into one of the two BOP control pods. These pods, like boxes perched atop the BOP, were the modules that linked back up to control panels on the rig, and through which the BOP could be directed, whether it was opening or closing a fluid line or activating one of its hydraulically powered rams to seal the well in an emergency.
The hydraulic leak was reported to the senior BP company man, Ronald Sepulvado. Of the four company men assigned to the Deepwater Horizon, two at a time, Sepulvado was probably the most experienced, having been with ARCO oil and gas company for twenty years before it was purchased by BP. He’d worked for BP for twelve years, the last seven and a half aboard the Deepwater Horizon. He knew the rig, he knew the crew, and they trusted him to do the right thing, especially when their safety was concerned.
Sepulvado discussed the hydraulic leak problem in a morning conference call with his BP supervisor, John Guide, a fifty-two-year-old engineer at BP’s campus on the western outskirts of Houston. Guide had been the Horizon’s well team leader for the twenty-four wells leading up to Macondo and he knew the business. Any issue involving the BOP definitely got Guide’s attention, and everyone else’s. Federal regulations regarding them were strict and explicit. They stated that any rig encountering “a BOP control station or pod that does not function properly” must “suspend further drilling operations until that station or pod is operable.”
Fixing the leak almost certainly would have required not only stopping drilling, but pulling the BOP up on deck—another delay of weeks, possibly months. After some discussion, Guide concluded that the leak concerned the least critical element of the BOP, the test ram—which was used to close the system off so pressure tests could conveniently be performed on various parts of the well. As for the continuing loss of hydraulic fluid, the leaky valve need only be turned to the neutral, or “block” position, and it would stop. Subsequent tests seemed to indicate that the rest of the BOP still functioned.
Guide decided that the leaky valve did not meet the standard—not functioning properly—as stated in the federal regulation. Therefore, he concluded, he didn’t need to report the leak to federal regulators, and the Horizon didn’t need to suspend drilling. The subsea crew set the valve on the leaky joint to “neutral,” or “block.” This meant that it would be depressurized, and without pressure, the leak would stop spewing fluid. If they needed to use the test ram, it would have to pressure up, which took some time. But the loss of fluid during a limited use would be negligible.
On a huge rig with so many complicated moving parts, these kinds of decisions were constantly being faced. A piece of essential equipment would start wheezing, in one way or another, but it could still be used. To get at the root of the wheeze would be time-consuming and expensive and often could grind operations to a halt. So did you just work around the issue until you could pause for repair? Or shut everything down?
In simplified, everyday terms, it was a little like driving a car that is burning oil. You can put it in the shop and pay to rebuild the engine, or wait until you have more time and money, and in the meantime just keep driving, dump in a quart of oil every time you fill the gas tank, and cross your fingers.
Mike Williams was an ex-marine who had become the Horizon’s chief electronics technician around the time they drilled the deepest well, six months earlier. He’d come to the Horizon six months before that, in the spring of 2009. Almost from the moment he’d arrived, he’d been seeing things that alarmed him.
One of his duties as an electronics tech was maintaining the fire and gas detection and alarm system, an extensive network of sensors throughout the rig tied into the rig’s mainframe computer. When he arrived, Mike found it in horrible disarray, with many of the sensors not functioning or locked out. As he set about trying to put things to rights, he stumbled on a page deep in the computer for the rig’s general alarm. He saw that the alarm had been switched to the inhibited mode, which meant it wouldn’t automatically sound if the sensors detected a potentially life-threatening situation. When he reported it, thinking he’d uncovered a serious mistake, he was told that everyone, from the OIM down, wanted it that way, so the crew wasn’t awakened at 3 a.m. for a false alarm. They wanted the watch officers on the bridge, who could see fire/ gas sensor alerts on their computers, to decide if it merited sounding the rig-wide alarm.
Williams understood the thinking—sometimes a cloud of cement dust could trigger the sensors harmlessly, waking up the sleeping crew members, leaving them drowsy for the next day’s long tour—but he didn’t agree with the conclusion. Seconds matter in emergencies.
For the last few months, Williams had been struggling with an aging computer system in the drill shack. The system was the driller’s window on all the conditions in the well and on the rig, and his control over everything from the mud pumps to the top drive. Out of nowhere, the computer would just lock up—the screen went blue, the “blue screen of death,” as it’s called. It happened all hours of the day or night. It was more than an inconvenience. When the screen froze, the driller was blind. Williams was told that on an earlier well, the screen went to blue and for a few minutes they had no way to monitor what was happening in the well. By the time they’d fired up the backup computer, they discovered they’d taken a kick.
The system was antiquated, so no matter how heroic their efforts to tinker with it, the threat of a crash would remain. They’d ordered an entirely new system—new computers, new servers, new everything—except software. They couldn’t get their old software to run correctly on the new operating system. So they were letting their sister rig, the Nautilus, work out the bugs for them before they installed the new equipment.
The Nautilus was built just before the Horizon, a nearly identical twin except that it did not have dynamic positioning capability. But the drilling mechanisms were almost carbon copies, so what worked on the Nautilus computer system should work on the Horizon’s. Meanwhile, they were limping along with what they had.
Sometime in March, Williams had been called yet again from his office near the engine room to the driller’s cabin to nurse the computer system. A contractor walked into the back. Cradled in his hands, as if he were carrying a dead bird, was a double handful of stripped rubber. Williams instantly identified it as rubber from the annular preventer—after all, it was pretty much the only rubber down in the well.
Williams glanced nervously at the rubber and said, “What the hell is that?”
“Oh, no big deal. That’s normal,” he says he was told. “It’s not a problem. This happens all the time.”
One of the advantages of using the annular preventer was that you could still do some drilling operations while it was closed by gently sliding the drill pipe through the clenched rubber. When used that way, some stripping of rubber did occur, and the driller was careful not to have the annular closed too tightly, or pull the pipe too hard.
But these seemed like awfully big chunks to Williams. Though he would be the first to admit he was no drilling expert, the incident stayed with him.
Then he remembered something: Late one night, not long before he’d seen the chunks of rubber, he’d received a call summoning him to the drill shack. When he arrived, he was told that they had been doing some pressure testing and the annular was closed, and closed tight. Williams saw 10,000 pounds per square inch on the screen. He was asked to investigate whether there had been an input to the control stick that had hoisted the block while the annular was closed.
When Williams asked why they needed to know, he was told, “Well, the block moved about fifteen or twenty feet. We need to know why. We need to know if it was inadvertent stick movement or if it went up by itself.”
They eventually discovered it had indeed been an inadvertent stick movement, and Williams now wondered if that mistake had resulted in the extensive hunks of stripped rubber.
Williams didn’t know how rubber loss would affect the function of the annular, but he did know there was nothing they could do about it until Macondo was completed and they’d pulled the BOP stack back up on deck.
Within days, Williams was called to the cabin again and told to hurry down. This time it was the BOP control panel. It had gone dead.
Because the driller is likely to be the first to notice the signs of a well about to kick, he needs to be able to activate the BOP instantly, which is why there is a panel in the drill shack, as well as on the bridge and in the subsea supervisor’s office. But the drill shack is also directly over the moon pool, and the first place likely to be engulfed in a cloud of gas if a kick gets out of control. So both the drill shack itself and the BOP panel are set up to operate in positive pressure—which means air flow is always out, and never in. That way, even if gas surrounded the shack, it can’t enter inside it. And just in case the drill shack was breached and the gas did enter, it wouldn’t enter inside the BOP panel, which has its own positive pressure within its glass case. This could be an important consideration because even a small electronic spark can ignite a massive fireball in the presence of natural gas.
What had happened now was someone had held the door to the drill shack open too long, causing it to lose its pressure purge. It was not uncommon for that to happen with all the traffic in there. In just a few seconds, pressure would build back and the purge would be reinstated.
But in this case, the purge system on the BOP panel was faulty, so while the door was open and the pressure seal was lost, the BOP panel detected the lost purge and automatically shut itself down.
By the time Williams arrived, he found the panel was back up, switched by an assistant driller to bypass mode. That meant that the panel could operate even without purge, running the risk—likely a tiny risk, but a risk nonetheless—that in an emergency situation, it would touch off a fireball.
Williams said that he had worked on that system during the last rig move and discovered how to make the automatic system work, keyed to the purge or lack of purge in the drill shack.
“Do you want me to start it back in automatic?” Williams asked.
“No,” Williams says he was told. “The damn thing’s been in bypass for five years. Why did you even mess with it?”
It sounded callous, but there were almost always two sides to every safety equation. Mike Williams wasn’t wrong to worry. While the chance of the BOP panel igniting a fireball was remote, it was a real possibility. But a potentially more troubling possibility was that if the BOP panel shut down during a gas event, the driller would be left helpless, with no way to close off the well himself. It was a catch-22 that could only be resolved with the correct parts, parts that Williams knew had been on order for some time but had yet to arrive on the rig.
Jason Anderson would always tell anyone who’d listen how much he loved his work. But on this well, he was feeling the pressure. Doing things right, the way he’d taken such pride in learning, sometimes meant taking more time. The wear on the rig that went unattended and the mechanical breakdowns, combined with the exhortations from the BP men to hurry, were all starting to make him uncomfortable.
When this hitch ended and he went back home, he confided in his dad, Billy, a former high school football coach who’d gotten into the offshore business himself and steered Jason to his first rig job. Jason told his dad about the pressure to just get things done even if it meant cutting corners. In the past, he’d always been able to talk the company men out of something when he really felt it was important. This time, he told his dad, the pressure was more intense than ever, and he was worried he was losing the argument.
It was an odd coincidence, but even as his worries peaked, surveyors for a risk management company showed up on the Horizon, contracted by Transocean to conduct a confidential survey. The survey suggested that Jason’s concern was shared by others. An analysis concluded that a significant number of workers worried that the quest to keep drilling always trumped the need for maintenance, forcing them to work with equipment that was becoming unsafe to use.
One man’s comment to the surveyors summed up the general frustration. “At nine years old, Deepwater Horizon has never been in drydock,” he said. “We can only work around so much.”
Both Transocean and BP put a lot of money, time, and effort into promoting the “core value” that any worker at any time could stop work he deemed unsafe. But half the workers surveyed said they feared that if they spoke up, especially about things being controlled by managers in Houston, they’d face serious reprisal.
With that fear hanging in the back of your mind, it could be hard to speak up. It wasn’t even just speaking up. What if you made your case, and the boss said, “I hear you, but we’re going ahead and doing it my way,” or the more common “I told the beach, it’s in their hands now.” How far were you going to go? The decisions were never black-and-white. Drilling a well was intensely complex and inherently risky. If you wanted to be 100 percent safe, you probably should never board a rig in the first place, nor start digging a hole in the ocean. And since risk was never entirely eliminated, you were never debating safety and danger in absolute terms. Millions of dollars were spent in accordance with percentages: How much was it worth to reduce the risk of a bad outcome from 1 percent to a half a percent?
After all, the Horizon had been drilling wells for a decade now, and nothing catastrophic had ever happened.
When his three weeks were up, Jason headed back to New Orleans and Port Fourchon, Louisiana, for that helicopter ride to the rig. At Macondo, things were starting to get interesting.
Up to this point, the hole had been passing mostly through sand and rock. The little pockets of gas it had hit along the way were mere soap bubbles compared to where they were headed—a fifty-foot-deep lake of liquid oil and natural gas permeating spongelike sandstone. Squeezed on all sides by billions of tons of rock exerting pressures of around 25,000 pounds per square inch, once pierced, it would explode to the surface as if a giant had stomped on a tube of toothpaste.
And the whole point of well construction was to build in such a way that the enormous force of upwelling oil and gas could be controlled, neatly shuffled into pipelines and sent harmlessly away to refineries. Job one was to ensure that this pipe they were sinking down, under enormous pressures deep inside the earth, did not leak. That would have been easier if a well were a single seamless cylinder of thick steel from top to bottom. But Macondo, and all deep wells, had to be made of pipes with seams and screw-together ends, and with smaller pipes hanging from larger ones—each connection a prime invitation to a leak. The first defense was to make sure that every individual section of the well was sealed up tight with cement.
Aboveground—pouring the foundation for a new house, say—cementing sounds simple enough. A plywood form is nailed together outlining the perimeter of the foundation, a cement truck backs up, dangling its cement chute over the mold, and pours down liquid cement until the form is filled. When the cement is fully cured, workers break off the plywood and the foundation is complete. What the homeowner does not see is more complicated. The humidity, ground temperature, and location all determine the amount and types of material—rocks, chemicals, silica—that go into the slurry to ensure the right drying time and strength of the hardened product.
Cementing a well is even more complex and much more difficult. You can’t just pour cement in at the top and let gravity pull it down. You first have to get the correct mixture of chemical additives figured out, then find a way to pump the cement so that it flows out the bottom of the pipe and is forced up the thin annulus space between the pipe and the well wall, which is where the seal needs to be. As you pump the cement, it has to be untouched by any contaminants—like drilling mud or seawater, one or the other of which fills the hole at all times. Any mixing of those things with the cement will destroy its chemical integrity and render the cement job worthless. And you need to be certain, without being able to see it, that the cement went exactly where you meant it to go, and rose to an exact height in the annulus. To recap: The goal is to pump cement into spaces a couple of inches wide and completely submerged in water or mud without letting the water or mud contaminate the cement, using only tools that can be lowered through a narrow opening and operated from thousands of feet above.
It sounded like a trick even David Blaine wouldn’t dare attempt. But the rig had its own magicians. They had nothing up their sleeves, but they did put a “shoe” on the bottom of the casing. The shoe had rounded edges that helped guide the casing as it was lowered to the bottom without scraping the sides of the hole or getting caught on ledges. A high-pressure nozzle that could pump mud or cement was lowered down into the casing pipe. To make sure that the pipe was clean and free of debris, mud was pumped through the pipe and out ports in the shoe. It hit the bare bottom of the hole, which forced it back up. The shoe, and the high-pressure flow coming out the holes in the shoe, prevented the mud from flowing back up the pipe. It had nowhere else to go but up the space between the outside of the casing and the bare wall of the hole until it came back out the top, carrying any debris with it.
After the mud had been circulated through the pipe, cleaning it out, the rig measured and pumped something called spacer, a water base with additives to make it friendly to cement. You could count on rig terminology to tell it plain: Spacer was there to put a space between the mud now filling the well and the cement soon to follow. It pushed the oil-based mud ahead of it up the annulus, readying the space for cement. A device called a plug was inserted into the pipe. The plug was like a cork within the tube. It had two parts, a top half and a bottom half, each of which had polymer edges that made a tight seal against the interior of the pipe.
When cement pumping began, an instrument called a “plug dart” was shot down a tube and hit a trigger in the top of the cement plug that unlocked the bottom half of the plug. The force of the cement flow through an opening in the top half of the plug pushed the bottom plug down the pipe. The plug in turn pushed the spacer ahead of it, out the holes in the shoe at the bottom of the pipe, where it made the U-turn at the well bottom and pushed up the annulus.
Back in Houston, engineers had run a computer model of the cement job, which had calculated the exact amount and chemical composition of cement and forcing pressure needed to ensure that the annulus was filled to the desired height and density. The cementer on the rig only needed to make sure the right amounts of additives were mixed in at the right times and count the number of pump strokes it took to push that amount of cement down the hole. When that number was reached on the stroke counter, another dart was sent down the pipe. This one sealed the hole in the top plug and released it to move down the pipe behind the full load of cement. Now they began to pump mud again. The high-pressure flow of the mud forced the top plug down behind the bottom plug, with the premeasured amount of still-uncontaminated cement between them. It was like a cement motorcade with armed guards in the front and the back.
As the bottom plug neared the shoe, it hit a barrier, called a float collar. The motorcade slammed to a halt. But as the pumping continued, the pressure increased to the point where a rubber membrane in the bottom plug ruptured, allowing the cement to flow through a valve that opened like a trapdoor in the float collar. The mud pressure continued to press down on the top plug, which pushed the remainder of the cement out the trapdoor and through the holes in the shoe. Just like the mud and spacer before it, the cement made the U-turn from the bottom and up the annulus, displacing the spacer.
Finally the top plug bumped down on the bottom plug, both snug against the float collar, and the pumping stopped. Gravity pulled at the cement now in the annulus, creating a slight backflow through the holes in the shoe, reclosing the trapdoor in the float collar. By measuring the “returns,” the amount of mud that got pushed out of the well by the inflow of cement, the cementing team could see that it was the full amount, and therefore could assume that all the cement had been pushed where it was needed. Now all they had to do was wait on the cement to harden. Even that had its own acronym: WOC, for Waiting on Cement. It was no joke. If they didn’t wait long enough before they began to work the well again, the cement job, however perfect when it went in, could be ruined by stress before it had properly hardened. They just had to sit and wait, not the easiest thing to do on a rig, especially one so badly behind schedule.