A Sea in Flames - Carl Safina [15]
Perhaps the most skilled people to do a cement bond log test work for the rig-servicing company Schlumberger. They’re on the rig on the morning of April 20, ready to get to work.
BP decides instead to just rely on the pressure tests and other indicators that say that all’s well with the well. BP tells the Schlumberger workers that their services won’t be needed after all, and arranges for them to leave.
John Guide explains: “Everyone involved on the rig site was completely satisfied with the job. You had full returns running the casing, full returns cementing the casing. Saw lift pressure, bumped the plug, floats were holding. So really all the indicators you could possibly get. So it was outlined ahead of time in the decision tree that we would not run a bond long if we saw these indicators. So the decision was made to send the Schlumberger people home.”
As the Schlumberger folks board a helicopter and lift off the rig, oil and gas are already trying to get into the well, pushing hard on the cement. At 11:00 A.M., as the helicopter flies out of sight, eleven men on the rig have eleven hours left to live.
The main critical error was in not recognizing that the drill pipe pressure they were reading during the pressure test indicated that gas was already getting in—and, therefore, that the cement job had failed.
Why did it fail? People will speculate for months. Some will suggest that the cement was not allowed to set adequately before BP began altering the well pressure during the positive and negative pressure tests. Others will see that as irrelevant. Even the time required for the cement to harden at the pressure and temperature deep in the well will be subject to controversy.
Not until September and October did some of the most important pieces of this puzzle start to fit into a clearer glimpse of what happened.
First, as promised, let’s revisit the centralizers. In late September 2010, when the relief well finally intersects the original well, it will find no oil outside the casing above the oil-bearing zone in the rock. This will confirm that the oil and gas flowed first out of the sand, then down more than 80 feet outside the casing, then into the well casing and up through 189 feet of “shoe track” cement within the casing. This entire 270-foot run—down outside, then up inside the casing—was supposed to be filled with cement. It’s astonishing that the cement in the casing failed. The inner cement was designed to be a solid seven-inch-diameter, 189-foot-long plug.
Though Halliburton had recommended twenty-one centralizers to help ensure a good cement job, BP used only six. But the other fifteen would have been placed above the zone bearing the oil and gas. Above that hydrocarbon zone where the other fifteen centralizers would have gone, the engineers poured 791 feet of cement into the gap between the casing and the well wall. That upper cement, above the oil and gas, remained sound. Cement failed in and below the main hydrocarbon zone. The part of the cement job that failed was where the centralizers were, and in the reach below them, and inside the casing. The flow of gas and oil was not up outside the casing but out of the sand, then down to the bottom of the well, then up inside the casing—despite the cement there—and then out to the surface.
This seems to acquit the centralizers. So was there something wrong with the cement formulation itself?
In its September 8, 2010, investigative report, BP will blame the cement. They’ll offer several reasons why the cement could have failed: contamination with drilling or spacer fluids, contamination among the three cement parts, or “nitrogen breakout,” in which the nitrogen breaks out of the foam and forms big gas pockets.
BP will have a third party make cement samples designed to resemble Halliburton