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Fixing the Gulf oil spill problem

by WmCElliott
Tags: fixing, gulf, spill
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russ_watters
#37
May31-10, 09:39 PM
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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
#38
May31-10, 11:46 PM
P: 621
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
#39
Jun1-10, 07:19 AM
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Quote Quote by pgardn View Post
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?)
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
#40
Jun1-10, 12:14 PM
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Quote Quote by russ_watters View Post
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.
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
#41
Jun1-10, 03:08 PM
P: 101
Quote Quote by mheslep View Post
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.
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
#42
Jun1-10, 03:15 PM
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Quote Quote by russ_watters View Post
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?
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
#43
Jun1-10, 03:18 PM
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Quote Quote by mheslep View Post
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.
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
#44
Jun1-10, 03:47 PM
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Quote Quote by stewartcs View Post
They actually deploy the BOP/LMRP stack on the end of the riser and land it on the wellhead.
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.


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
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
#45
Jun1-10, 03:55 PM
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Quote Quote by mheslep View Post
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.
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
#46
Jun1-10, 04:08 PM
P: 101
Quote Quote by stewartcs View Post
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
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
#47
Jun1-10, 04:31 PM
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Quote Quote by stewartcs View Post
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. S
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
#48
Jun1-10, 06:57 PM
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Does anyone know what the approximate temperature of the oil as it comes up the well is?
Geigerclick
#49
Jun1-10, 07:32 PM
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Quote Quote by Bernie100 View Post
Does anyone know what the approximate temperature of the oil as it comes up the well is?
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
#50
Jun1-10, 09:29 PM
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Quote Quote by Bernie100 View Post
Does anyone know what the approximate temperature of the oil as it comes up the well is?
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
#51
Jun1-10, 09:33 PM
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Quote Quote by Geigerclick View Post
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!
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
stewartcs
#52
Jun1-10, 09:40 PM
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Quote Quote by mheslep View Post
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.
Each joint is basically sitting in what we call a gimbaled riser spider. The spider sits over the well center on the drill floor while running or retrieving riser. The joint sits on a load shoulder in the spider and holds the entire riser string (with stack on the bottom of last joint) while the next joint is stabbed in and bolted up. The draw-works (big hoisting system) then picks up the string of riser so the spider can be opened partially and then lower down the full length of the joint that was just made up. The top of the new joint is the landed in the spider again (which is now closed around the joint again) and the process repeats.

It's called a spider since that's what a lot of the older ones looked like! The oilfield is notorious for naming equipment for common day things that they look like!

CS
Geigerclick
#53
Jun1-10, 10:09 PM
P: 101
Quote Quote by stewartcs View Post
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
They certainly have little meaning to me! Heh, thanks for hitting the high notes in this case, I feel sufficiently informed on this now.
mheslep
#54
Jun2-10, 01:35 PM
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Quote Quote by stewartcs View Post
Each joint is basically sitting in what we call a gimbaled riser spider. The spider sits over the well center on the drill floor while running or retrieving riser. The joint sits on a load shoulder in the spider and holds the entire riser string (with stack on the bottom of last joint) while the next joint is stabbed in and bolted up. The draw-works (big hoisting system) then picks up the string of riser so the spider can be opened partially and then lower down the full length of the joint that was just made up. ...
Yes, I should have guessed there would be a hoist in the works somewhere. Thanks again.


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