Fire on the Horizon (17 page)

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 com
mon 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?