1. How negligence caused the rig explosion and subsequent leak
2. The wrong place to drill?
3. Why top kill failed
4. The effects of toxic dispersants
5. What the real scenario is likely to be
BP's negligence - a tragedy of errors
Mike Williams was on the Deepwater Horizon when it exploded, as chief electronics technician. In an interview with 60 Minutes, he details corners being cut, safety standards set aside to save money, and the cascading effect of bad decisions that culminated in the blowout.
The following is excerpted and/or paraphrased from a letter from Henry A. Waxman, chairman of the congressional committee investigating BP to Tony Hayward and details the many breaches in safety procedures. You can read the full text here.
Well design compromise
time saved: 3 days
Deep water wells are drilled in sections. The basic process involves drilling through rock, installing and cementing casing to secure the well bore, and then drilling deeper and repeating the process. On April 9, 2010, BP finished drilling the last section of the well.
Subcontractor Halliburton recommended hanging a steel tube called a "liner" from a liner hanger on the bottom of the casing already in the well, and then inserting another steel liner tube called a "tieback" on top of the liner hanger. This provides protection from a blowout. Instead BP chose to use the much riskier single string of casing because it was cheaper.
Inadequate number of Centralizers
time saved: 10 hours
Centralizers are attached to the casing as it being lowered into the well to keep it centered in the borehole, prior to cementing it in place. If the casing is not centered then channels can form in the cement which allows highly pressurized gas to flow through any space around the casing. It becomes "difficult, if not impossible, to displace mud effectively from the narrow side of the annulus if casing is poorly centralized. This results in bypassed mud channels and inability to achieve zonal isolation." API Recommended Practice 65
Halliburton's computer analysis showed that 21 centralizers were needed for the job, and that fewer would result in a significant risk of gas channeling. BP elected to use only 6. Halliburton ran another computer model using 7 centralizers and concluded "well is considered to have a SEVERE gas flow problem." BP responded "who cares, it's done, end of story, will probably be fine and we'll get a good cement job."
Cement test skipped
time saved: 9-12 hours
A "cement bond log" is an acoustic test that is conducted by running a tool inside the casing after the cementing is completed. It determines whether the cement has bonded to the casing and surrounding formations (ie the seabed). If a channel that would allow gas flow is found, the casing can be perforated and additional cement injected into the annular space to repair the cement job.
Although a crew from subcontractor Schlumberger was present to carry out the test, it was cancelled at the last minute by BP and the crew sent home.
Incomplete mud circulaton test
time saved: 12 hours
This procedure called "bottoms up" involves circulating drilling mud from the bottom of the well all the way to the surface. It tests the mud for influxes of gas; it permits a controlled release of gas pockets that may have entered the mud, and it ensures the removal of well cuttings and other debris from the bottom of the well, preventing contamination of the cement.
Instead, to save money BP conducted only a partial circulation of mud.
Lockdown sleeve compromised
When the casing is placed in the wellhead and cemented in place, it is held in place by gravity. In a blowout the casing can be driven up the wellhead creating an opportunity for hydrocarbons to break through the wellhead seal and enter the riser to the surface. To prevent this, a casing hanger lockdown sleeve is installed.
Or not.
On June 8, 2010, after the explosion had occurred, Transocean briefed BP committee staff on its investigation into the potential causes. In the presentation, Transocean listed the lack of a lockdown sleeve as one of its "areas of investigation." Download PDF.
These next points are from the sources appearing after each point.
Faulty blow-out preventer
On at least three occasions, BP records indicate, the blowout preventer was leaking fluid, which the manufacturer of the device has said limits its ability to operate properly. After informing regulators of their struggles, company officials asked for permission to delay their federally mandated test of the blowout preventer, which is supposed to occur every two weeks, until the problems were resolved, BP documents say.
When the blowout preventer was eventually tested again, it was tested at a lower pressure — 6,500 pounds per square inch — than the 10,000-pounds-per-square-inch tests used on the device before the delay. It tested at this lower pressure until the explosion. Source: New York Times.
Mike Williams, in the 60 Minutes interview above told the reporter that one of the controllers in the BOP was no longer functioning, and also claimed that the blowout preventer was damaged when a crewman accidentally moved a joystick, applying hundreds of thousands of pounds of force. Pieces of rubber were found in the drilling fluid, which he said implied damage to a crucial seal. But a supervisor said it was “not a big deal" and ordered they proceed.
Early removal of drilling mud
Another survivor of the rig explosion said the mud was removed before the well was fully sealed with cement plugs.
In order to properly cap a well, drillers rely on three lines of defense to protect themselves from an explosive blowout: a column of heavy mud in the well itself and in the drilling riser that runs up to the rig; at least two cement plugs that fit in the well with a column of mud between them; and a blowout preventer that is supposed to seal the well if the mud and plugs all fail.
Scott Bickford, a lawyer for a rig worker who survived the explosions, said the mud was being extracted from the riser before the top cement cap was in place, and a statement by cementing contractor Halliburton confirmed the top cap was not installed. Source: Times Picayune
The wrong place to drill?
The well is located in block 252 of the Macondo prospect in the Mississippi Canyon. It has a very challenging geology for drilling. The seabed is composed of turbidite sand bonded with methane hydrates.
Methane hydrates are volatile compounds — natural gas compressed into molecular cages of ice. They are stable in the extreme cold and crushing weight of deepwater, but are extremely dangerous when they build up inside the drill column of a well. If destabilized by heat or a decrease in pressure, methane hydrates can quickly expand to 164 times their volume.
Scientists are well aware of the awesome power of these strange hydrocarbons. A sudden large scale release of methane hydrates is believed to have caused a mass extinction 55 million years ago. Source: The Guardian
Additionally the hydrate/sand compound has a porosity of 26 - 30 percent. It is not only far more porous than rock, but can fall apart if the methane hydrate holding it together melts, leading to collapses in the seabed. Many believe this is already underway.
Energy and Capital reports "seismic data showed huge pools of methane gas, under tremendous pressure. Some have speculated that the pressure was up to 100,000 psi" -- that's 10 times as much as current technology is capable of handling, even if it had been functioning properly, which it was not. As mentioned above, the BOP was only tested at 6,500 psi presumably because they were afraid to test it at 10,000 psi as is federally mandated.
Anderson and Boulanger's report - PDF.
Why top kill didn't work
Top kill is the process of injecting drilling mud down into the well at high pressure in order to overcome the pressure driving oil and gas up.
It works, but only if there are no other leaks. The fact that it didn't work, and was called off early, is a good indication in itself that there are other leaks. If so, top kill can make them much worse, driving high pressure gas into the surrounding formation, eroding and weakening it further. It's like a leaky garden hose. As long as the nozzle is open, you don't notice the leaks much. But plug the nozzle, and suddenly water starts shooting from the other leaks.
Because the casing was inadequately centered and the cement never tested, it's highly likely that the casing is broken, that gas escaping under pressure from the bore hole is eroding the surrounding sea bed, which as noted above, is very vulnerable to erosion and melting. The geothermal effect of pressure means that the gas coming out of the blown well is 120 - 177 C (250 - 350 F). Methane hydrate melts at 26C (75F) and separates into methane and water. The methane will then bubble to the surface and enter the atmosphere. Methane is a 72 times more potent greenhouse gas than CO2, so not only is there oil pollution, but also methane pollution.
Here is the much-discussed post on The Oil Drum talking about the top kill failure and a whole lot more.
The effects of BP's toxic dispersant
Corexit 9500 is the dispersant BP is using to mitigate the surface slick - 1.3 million US gallons to date. It has been bannedl in the UK and Europe because it's a known carcinogen, and one the most environmentally enduring toxic chemical dispersants ever created. It is also "capable of killing or depressing the growth of a wide range of aquatic species, ranging from phytoplankton to fish." says Scientific American.
Corexit and other dispersants do not actually get rid of the oil, they only break it into smaller bits, bits that can be injested by marine life such as plankton, jellyfish, and anything that feeds on them. The dispersant itself evaporates, but that doesn't mean it goes away. It falls back to the earth as toxic rain, contaminating crops, livestock, wildlife, reservoirs and yes, us.
A class action suit has been filed in New Orleans federal court against BP and Nalco Holding Company, the manufacturer of Corexit.
I would venture to say that the main "benefit" of such a poisonous substance is purely cosmetic. It makes that ugly oil slick on the surface seem to go away. What price PR?
What the real scenario will likely be
Worse.
On May 26 former Bush energy advisor Matthew Simmons said a giant plume, 22 x 6 miles wide and 3,000 ft thick (BP denies its existence by the way) is probably coming from another leak at the wellhead or from a fissure in the seabed, 5 - 6 miles away.
This jibes with a Russian report prepared by Anatoly Sagalevich of the Shirshov Institute of Oceanography warning that the sea floor above BP's leaking oil reserve has been "fractured beyond all repair". Sagalevich is an expert on Deep Submergence Vehicles who holds the world's record for a 1,637 meter dive.
It should be noted that this story is only at the Before It's News site, and there's no other confirmation as yet. In my attempts to corroborate this story I came across statements that Sagalevich had offered to help BP but been turned down, and conflicting reports that BP asked him to help. The original story is here.
The site reports that Sagalevich said oil is leaking from at least 18 other sites, one almost 11 km from the well bore site, and that currently 2 million gallons of oil per day are flowing into the guif. That's a far cry from the 5,000 barrels BP were citing just weeks ago or even the 60,000 that is being widely cited now.
As I said in this earlier post, if the seabed were to cave in around the well head, and/or elsewhere over the deposit, the entire reservoir of oil could empty into the gulf, through the Loop Current and into the Gulf Stream. No wonder this is being compared to Pandora's Box; humans opening up something that they have no real control over and setting in motion a terrible chain reaction. This certainly has the potential to become a mass extinction event, unseen in human history and the only hope of preventing it is a couple of relief wells, that may or may not work. Not to be alarmist or anything...
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