BP Oil Spill – Options for the Next Time?

I'm from outside this technology, but my simple mind keeps coming back to a device called a "blowout preventer" that I understand is supposed to stop the flow of material if the extraction system goes "open circuit".

If the blowout preventer had correctly functioned, we would not be seeing this catastrophy happening. We would still be mourning the loss of life inthe initial rig failure.

A "failsafe" device has failed to activate. Either it was non functional (failed to operate) or incorrectly selected for the task.

The solution to this problem is to identify the ACTUAL cause of system failure and correct that issue.

I'm troubled when people want to add more "safety" features rather than ensure the ones that are already present are correctly operating.

Adding complexity to future designs will only provide additional opportunity for failure.

The question that has been on my mind since day 2 of this is "How many other rigs have blowout preventers that don't work?"

A VERY similar accident happened off North West Australia around August last year with oil leaking into the environment for months before an interception well was drilled and shut down the stream.

To my count that's 2 failures in 2 rig accidents where rig fires were involved.

I had imagined the blowout preventers to be a "failsafe" device that required a signal of some sort (hydraulic or electrical) from the surface to hold them open, but apparently I was wrong.

The other amusement that I have is that they can "thread the needle" and put pipes or caps directly onto the well head, but cannot insert a simple mechanical plug into the pipe and plug it.

Sorry for the rant and it's probably gone off topic to your original suggestion, but additional complexity doesn't make a more reliable system.

No argument about having a blow out preventer that would work correctly, every time. Until one is developed you have to look at your FMEA and evaluate how many levels of backup are required to avoid a situation like we are currently facing. If one was done, it obviously fell very short of requirements. Another famous example: Look at the original probability of failure for the space shuttle and how it met reality. It wasn't for the lack of really good engineers.

This proposal was not to add more complexity to the rig. It was to provide an external means of dealing with a catastrophic fire. Think of it as a ship deployed submersible that could separate the rig from the blowout while the firefighters are doing what they can to contain the fire.

Do they currently have a blowout preventer that can shear through drill string joints? If in a worse case scenario with the tubing or drill string being blown out of a well, is the blowout preventer designed to stop the tube or drill string in order to shear through it? If stopping the string that abruptly, what is the likelihood of causing secondary damage below the BOP?

İf you walk in to a Dupont plant one of the first people you meet is the safety officer - he is the boss in many ways with great authority, power and responsibility. You want to visit or work in his plant you will follow his rules! One thing that amazes me about the BP thing is that BP management (Hayward & Suttles) keep talking to the press and saying dumb things indicating they really don't know what is happening. İf BP had one top flight guy (Red Adair type except a different scope) running the show, calling the shots and talking they would be far better off.

What you're observing is the lack of culpability shuffle...

Some good ideas though all is mere speculation until the actual cause of failure in this event is known.

I think knowing well the various extremes available we should stay to the center of the path and examine the real options.

IMHO this situation is a fluke and the entire industry needn't be altered due to it.

Like many exploratory functions procedures are dependent upon conditions; it's not a by the numbers routine. There are inherent risks that can not be mitigated; it's a gamble.

The big question is what has changed since 1979? I can't answer that question since I have been out of the oil industry since the early 1980's.

http://en.wikipedia.org/wiki/Ixtoc_I_oil_spill

Have the means of dealing with an oil spill changed?

What has changed in BOP technology, cementing, mud control, safety procedures, etc that would classify as dramatic improvements?

Those who cannot remember the past are condemned to repeat it.

George Santayana

The incident in 79 was at something like 160 feet - a very different scenario. Probably 1000 times easier to seal it than the present one. Divers can work at 50 meters. Not being an oil field man I am not the one to say but I expect they would tell you that not much is the same. These guys (excluding top management types) are not fools or idiots. Those that can't move on from the past are also stuck in it.

I am not an engneer or oil personeel, but have a question? Why can not they remove the defective blowout preventer and replace same? This should stop oil flow and enable them to reattach pipe and recover oil, no need for driling more wells?

If you were in a boat that was sinking due to a plug in the bottom leaking. Would you pull the leaking plug?

Yes, if I had a better plug and was able to do that in a timely manner rather than just let it keep leaking and mop up the mess.

(I'm not the guest, just answering the question you posed.)

Kind of like in a sink? But wait - in that case the flow is assisting the plug - not pushing it away/resisting it. Go to a petrol station and remove the end from their air hose. Now try to stop the flow of air out of the hose by holding your finger over the end. That is maybe 4 bar pressure - a far cry from the well head. Not to mention that nothing seems to be round and open anyway.

You would install it open Russ - and tell your servo to buy a new compressor.

For what it's worth, from what I have read on how they do things and what happens when these pressure events happen, the BOP is a design done from production recovery point of view, not really from a Murphy's Law perspective.

Murphy's transmits to the whole cementing-in approach of the casing/s and stresses on the total drill string.

The BOP shear concept is not how I would "crush seal" a tube industrially.

Nor does the BOP appear to to have integral depth compensation, or provision for the power of an extreme event to activate/drive it, yet the force is there and trigger parameters are unmistakable. Such a design would remove reliance on a surface signal or power supply and is independent of the depth.

I think two areas should be re-designed;

The fixing/sealing of the casing

The BOP

So I have.

So the game is; can you guys figure out what I have to sell - if BP should they call.

This BOP concept is controversial in my mind as I don't understand why a BOP is not employed to choke-off or seal the casing rather than the seemingly dubious cementing process?

The gap between the casing and other pipes is not only sealed at the top I believe. How do you manage that with the BOP?

From what I understand, this well was a problem from the start with high levels of gas in the mud column. My understanding (Correct me if I am wrong):

In order to eliminate the risk of ejecting the drill string or tubing you would need to be able to close the annular blowout preventer as soon as your sensing systems detected a problem. In order to do that it would likely need to be an automated system to engage the BOP with the following inputs.

Return mud flow substantially exceeding input mud flow or exceeding the input flow of the seawater displacing the mud.

Loss of hook block load indicating the drill string or tubing is being unweighted.

Before the annular BOP is engaged, the rotary table would need to be shut down if in the middle of drilling operations.

Would need to shut off any well circulation or displacement operation. If this happens in the middle of drilling operations you can stick the drill string forcing you to have to come in with recovery tools to recover what you can.

With this said, what is the likelihood of an automatic shutdown being used on a well that is known to have high concentrations of gas causing kicks?

I could see in the case of a problem well that the automatic annular BOP activation may not be effective and possibly shut down the well repeatedly. Would the rig crew have to resort to manual BOP activation in that type of scenario? If so, we are back to my earlier question regarding the ability of a BOP to function when the drill string or tubing is being ejected. That is a lot of mass to stop.

Is this a correct appraisal or am I missing something?

I want to caution on using technical manual documentation to critique actual field operations.

I really don't want to get into actual field operations either. My questions were really more basic.

Is a BOP designed to handle only the static loads of annular sealing or shearing through a non-moving drill string or tube?

Is this a realistic design criteria? Can a situation exist that would allow ejection of the drill string or tube during a kick? If so, what mass and velocity are we talking about?

If you can't guarantee a static situation for the BOP to operate in, what are the design parameters in order to seal a moving drill string or tube?

Here is an article describing some of the design limitations of the BOP indicating 260 separate "failure modes" that "could require pulling of the BOP." It makes for some interesting reading. I am amazed that it came out.

http://www.theengineer.co.uk/channels/process-engineering/bp-now-capturing-16k-barrels/day-at-deepwater-horizon/1002390.article

Good link KDS.

I'm not sue how one "pulls a BOP" on a gushing well with a suspect and leaking casing*, but at least the current 'solution' is not stressing the casing more at present.

(*confirmed again in Anonymous's link Link to article here)

But I think in terms of this thread - "Next time" - you'd have to assume all of this could happen - through to even to 'worse', that the casing and BOP are ejected from the well.

"Estimated 9,000 psi" is a lot.

What the original breakthrough and pressure rise was, is any ones guess.

Just curious your estimation of time from when the gas exceeded the BOP to surface release at the rig platform?

Surviving witnesses stated the mud spewed out after the first explosion?

I don't know, but from that early set of blame game, from what the BOP guy said, about 15 to 30 seconds of running about ensued before it all went terminal, and somewhere in there he hit the kill button, and it failed to shut off.

But it seems to me the BOP did at least partially or substantially shut down and is currently a major restriction to the flow (or the casing leaks would not be growing/eroding).

Or the time - so velocity - so pressure? = good question.

Another "I don't know" - but given the riser is full of mud the first pressure empties it - the gas event occurs - then say the annulus closes and part shear occurs - the mud is then forced back up the drill string - either blowing thorough it, or due to the part shear, back up the riser.

Here is the hang-off clamp I was describing in the initial entry:

http://www.docstoc.com/docs/3759575/BP-ATLANTIS-J-Lay-System-Introduction-GMC-is-the-project

http://books.google.com/books?id=x1bmWQxDLYcC&pg=PA41&lpg=PA41&dq=%22hang+off+clamp%22&source=bl&ots=H9k-Iusw9m&sig=BRNuZpLGpeup8-Sa3erMt60eZzc&hl=en&ei=ah4cTOmgEMPHnAeok_nwDQ&sa=X&oi=book_result&ct=result&resnum=9&ved=0CDEQ6AEwCA#v=onepage&q=%22hang%20off%20clamp%22&f=false

http://www.offshore-mag.com/index/article-display/42932/articles/offshore/volume-59/issue-9/departments/technology-focus/high-capacity-dp-crane-pipelay-vessel-designed-for-ultra-deepwater.html

Here is a NY Times article and the link for the supporting documents. It is an interesting read:

http://www.nytimes.com/2010/06/21/us/21blowout.html?hp

http://documents.nytimes.com/documents-on-the-oil-spill