Fixing the Gulf oil spill problem

WmCElliott

I'm gratified that their next funnel will be heated, I suppose electric heaters solve the insulation of the warm surface water for a mile through cold water.

BP does have a website dedicated to ideas for fixing the problem, and it seems to connect you to Red Adair's company directly.

Geigerclick

They will also be using Methanol in the new cap.

russ_watters

I'm a little surprised there doesn't exist any kind of valve that can be attached somewhere along the pipe, then having a slit cut in the pipe, then sliding a blast-gate type valve in place to stop the flow.

....or....since this is a 9" pipe inside a 21" pipe, why can't you just drill a 9" hole through the two pipes and insert a 9" diameter rod/pipe into the hole?

pgardn

And this is all having to be done by robot submersibles... Controlled by people that might be rockin and rolling on the surface. Pretty amazing. Amazingly difficult. I wonder how many of these things have run into each other or have gone out of commision. BP is not giving a lot up.

Its possible that we might not want to drill wells 1 mile deep anymore if we cannot fix them. On the other hand, this is a huge experiment that will get some answers. Just wish it all had never happened. Its like having a well on Mars.

This is an interesting simple view of all that has been tried so far...
http://www.nytimes.com/interactive/2...am.html?ref=us

This says nothing about using heaters, just warmer seawater and methane (did they mean methanol, I thought methane was hydrating forming the crystals? more methane solves the problem?)

Geigerclick

I would tend to agree, or we require that a relief well be drilled at the same time as the primary well at these depths.

mheslep

I believe it's because it is not practical to put enough structural strength into the riser pipe to support the loads required of any kind stop valve. The total force on any given 19" (ID) pipe cross section might be ~500 tons. I would think only the massive BOP manifold on the sea floor could handle that kind of load.

Geigerclick

That would seem to be a huge strain, and even if this were foreseen that would not be plan A or B, as we see. Frankly, a version of the Top Hat that has time to be engineered and build with simulations, with a heat exchanger and veins for methanol seems as though it could work.

Apparently there are gulf wells at 10,000 feet, and the need for a less "surgical" approach than this LMRP would seem wise. The aforementioned Top Hat, along with the fabric mention earlier would seem to be the best approach.

That, or drill a relief well along with the primary in the first place!

stewartcs

Russ,

The riser isn't designed to contain pressure. Its primary function is to provide a conduit for drilling fluids.

The max mud weight typically used in deep water isn't more than about 16 ppg so the differential across the riser at 5000-ft is about 1934-psi. So the riser isn't design to withstand typically around 2000-3000 psi normally and that's just for collapse resistance in case it is voided for some reason.

The thicker the riser is, the more it weighs, and the more tension is required at the surface to keep it stable.

CS

stewartcs

They actually deploy the BOP/LMRP stack on the end of the riser and land it on the wellhead. The LMRP/BOP stack weighs typically around 800,000-lbf. That plus the weight of the riser can be over 1,000,000-lbf depending on the depth. An analysis I performed not that long ago showed a static load of 1,400,000-lbf for a 10,000-ft riser and over 2,400,000-lbf when the dynamics were added (for a particular environment).

CS

mheslep

Interesting. I'd like to know more about the procedure - would be necessarily very slow on descent, with the load maintained while new sections of riser are attached one after the other. We see cable drops in the graphics of all the heavy gear in these Deepwater Horizon repair / salvage attempts.


With no experience in this line, tensile strength that high (700-1200 tons) sounds plausible to me for a (very stable?) riser pipe, but not the shear and compression loads that would appear if a valve was somehow inserted into the pipe and operated at this reservoir pressure - that is what I was referring to above.

stewartcs

They can typically run about three riser joints per hour. Each joint is either 75-ft (or 90-ft depending on riser design) in length. They are connected by a bolted flange typically. However there are other designs that can be used to increase the running rate.

Essentially they just connect new joints on top of each other until they reach the bottom. At that point they use a special joint called a landing joint to connect the stack to the wellhead. Then they unlock another special joint called a telescopic joint (TJ) to allow compensation of the vessel motions. The outer barrel of the TJ is connected to a tensioning system (either direct acting or wire-line type) to provide the necessary top tension to keep the riser stable.

There are of course more steps involved but that's the short version.

CS

Geigerclick

I say this seriously, I have found your posts extremely informative, and if you would be willing I wouldn't mind the long version for the sake of geek-satiation if nothing else!

mheslep

Thanks! I was having difficulty in fathoming how the load (700-1200 tons) is transferred, hand-over-hand so to speak, from section to newly-added-section.

Bernie100

Does anyone know what the approximate temperature of the oil as it comes up the well is?

Geigerclick

A google search returned too many conflicting numbers and guesses. I don't know that such information has been made public. Remember, there is a significant fraction of the spew that is rapidly expanding natural gas, so I'm not sure that it is possible to ballpark based on prior measurements of oil at that depth.

stewartcs

It varies quite a bit. I'm not certain about this well. Normally there is a pressure and temperature sensor in the stack cavity that transmits the data to the surface.

CS

stewartcs

The other steps are mundane really - like preparing the drill floor, the moon-pool area, skidding the stack to well center, hanging the string off in the riser spider, etc. Most of those terms don't mean much to the majority of the people who read this since they are industry terms given to specific equipment or to a process.

I've just given the big picture. But if you have specific questions I'd be happy to try and answer them.

CS