BP's Deepwater Oil Spill - Rig Workers had Chance to Prevent Explosion? - and Open Thread
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BP's Deepwater Oil Spill - Rig Workers had Chance to Prevent Explosion? - and Open Thread
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258 comments | Comments can no longer be added to this story.
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There were questions in the old thread of what Admiral Thad Allen is requesting from BP in his last letter especially with this:
Here is what I think what he wants to achieve with that and how that will be done:
The first picture shows the well when it went wild. The blueish area is the cement that failed.
Note that there is no seal between the production casing long string and the outer casing (pink circled area). While the flow from the well came through the production casing long string, the path outside the production liner up into the annual between the production liner long string and the outer casing was and is a possible second flow path. It is what Thadmiral is concerned about.
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The second picture shows the well after the top-kill and with the unfinished relief well. The yellowish area is likely the area where the top-kill cement went.
Note: While the cement in the production casing long string has been tested by opening the well, there was no way to test the cement in the annular between the production casing long string and the lower well bore and the outer casing. The annular between those may still be open to the reservoir.
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The third picture shows what will happen in the next days.
1. The casing hanger lockdown sleeve will get installed (not shown).
2. Developer Driller II above the original Macondo well will put its drill pipe into the hole and will perforate the production liner long string just above the top-kill cement. (If the annular is pressurized from the reservoir it may take a kick doing this.)
Pumping cement into the annular in this state would be dangerous and difficult as whatever is in there now, mud or oil, has no place to go. To avoid any damage when pushing cement down in there we need some communication to be able to retrieve the stuff that the cement will replace.Therefore:
3. Developer Driller III doing the relief well will intersect below the outer casing into the annular between the long string and the well bore. This will then form a U-tube between the DDII down through the annular between the long string and the outer casing and up to the DDIII. Mud can then be pumped from one rig down the hole up to the other rig to test the communication through the annular.
4. Fresh cement (green) will then be pumped from the DDII down its drillpipe into the annular. As communication is established, whatever is then in the annular, mud or oil, can be pushed by the cement up to the DDIII.
With this the annular is then truly dead and Thadimrals point 5 demand will be fulfilled.
I seem to recall that in a permanent P&A the well head will be cut off below the mudline. If so why worry about the casing hanger and lockdown sleeve if they going to be removed?
V´Cutting the wellhead off below the mudline is only the last step of P&A.
In the first step of P&A they will have to plug the well as ordered by Thadmiral and by MMS regulations. To be able to do that without risking to lift or damage the casing, which could reopen a path from the reservoir, they will insert the lockdown sleeve. They have already taken a lead impression of the seat and Thudmiral said it looks good.
MOON. Great graphics, thank you much. "A picture speaks a thousand words" Never-the-less, I agree with ROCK. The relief well intercept is going to be the world's most expensive vent pipe for this well's annulus. The job could be done by perforating the prod casing at two differing heights. Pressure wise the two spaces would then become one pressure balanced volume regardless of what that pressure is. All this done through one BOP. These guys had enough problems communicating across one rig, never mind two.
The job could be done by perforating the prod casing at two differing heights. Pressure wise the two spaces would then become one pressure balanced volume regardless of what that pressure is. All this done through one BOP.
The job as demanded by Thadmiral can NOT be done the way you describe it - unless you drill out 4000 feet of the 5000 feet cement column in the production liner long string. I can imagine though that some people would not like that idea.
Sure they could put a big plug into the annulus at a lesser depth just the way Rockman and you describe. But that would not "allow injection of mud and cement into the annulus of the well below the current level of cement in the central casing." Nor is simple pressure likely to do that as there is, hopefully, some cement in the lower part of that annulus.
The only clean way forward seems to be the one I described.
Moon. the following is notes I took over the phone from the clever ones. I think I remembered / understood some of it.
If the annulus is open to the formation, the temperature below BOP will be going up slowly.
When did it become impossible to drizzle cement between a 9 7/8 liner and a prod case.
If you have to drill a relief well to vent an annulus, please tell the guys in the North Sea they have been f*****g it up for the last twenty years.
They have blowouts in the tied back 16.
What happens if the relief hits gas on the way in. This well has been a kicker from day one.
I am due to get my lessons in how to drill an oil well in a couple of weeks in the UAE.
I have no ideas who those "clever ones" are but they obviously also have no idea about the state of the Macondo well and the current operation.
"If the annulus is open to the formation, the temperature below BOP will be going up slowly."
Huh - why would that be. Is the seabed warm because 10,000 feet below there is some oil and gas? If there is no flow, why should the temperature change?
"When did it become impossible to drizzle cement between a 9 7/8 liner and a prod case."
When there is already stuff in there that has no way to go elsewhere.
"If you have to drill a relief well to vent an annulus, please tell the guys in the North Sea they have been f*****g it up for the last twenty years."
Venting the annulus is NOT, NOT, NOT what Thadmiral is demanding - read above!
"What happens if the relief hits gas on the way in. This well has been a kicker from day one."
The relief well is in a formation very near the original well that is by now very well known. There is no gas reservoir to hit when intervening the Macondo well with it.
The clever ones design and drill oil wells for a living.
The temperature at the bottom of the well is 262 F. Hot fluids rise, buy a larva lamp and watch it happen. It makes no difference if the fluid is in closed or open container.
A double perforation of the prod casing gives annulus volume somewhere to go, back into the prod casing. Can be separated from the cement injection stinger with a temporary casing packer.
Venting the annulus is exactly what he is doing because of the "no where to go" scenario.
The relief well injection will have "no where to go" either except into the formation or up the production casing through its new perforation. Both rigs will then be in the position that either could "suck" or "blow"
The pay zone formation is reported as having up to 40% methane in it, very high.
" buy a larva lamp and watch it happen. "
I'm all over that, gotta have mood lighting when you eat your ...grub.
lol
moonie - The last report from Thad was that the top of cmt in the prod csg was around 15,000'. And that's what your picture shows. No drilling required: GIH to 13,000' and perf. Then perf at 15,000' and fill the same annulus you're targeting with 2,000' of cmt. From you well bore diagram it seems you achieve the same results. If so I see making the intersect with the RW an additional and unnecessary procedure.
But I still suspect there's something they aren't telling us to explain why they still might want to use the RW.
RM,
Has the cement top inside the production casing changed? As I remember it, the cement top inside the casing was estimated at 5,000' from the bottom which would place it at around 13,304'. I think Moon's excellent graphic depicts the status accurately.
Cementing the annulus above the 13,304' would be simple but if taken literally, the Admiral wants the annulus cemented from the 9 7/8" casing shoe at 17,168' which presents a bit of a challenge.
Like you say, there is probably somethings they are not telling us.
I doubt these directives come out of the blue. They probably sit down and decide the next step. Since Obama has to perpetuate the Boot-On-The-Neck image, a terse statement is issued demanding that BP do exactly what BP decided was the next logical step.
The relief well mantra is more political BS. The relief well is no longer a factor but since Obama spouted that the relief well will be the ultimate solution to the blow out, the relief will be completed so the Obama and Chu can take their victory lap. Probably right before the mid-term elections.
Sorry to get political but I think it's the reason certain things don't make sense.
NU
NU - Maybe memory fails me but I recall a 5,000’ cmt column estimate: 2,000’ in the annulus and 3,000’ in the producing csg. But even if my memory is correct it doesn’t mean their estimate is correct. But the annulus can be cmt'd anywhere and isolate the reservoir. If there’s a 2,000’ cmt in the annulus does it matter if the bottom is at 15,000’ or 10,000?. Either way the reservoir can’t flow to the surface up the annulus. Why is it important to get the annular cmt that deep.? Again, maybe for some reason they aren’t telling us.
I can buy the political motivation for the RW but only to a degree. Could make the American people feel all warm and cozy. But how W&C are they going to feel if they wake up one morning and see the RW rig burning, another 11 dead hands and 50,000 bopd flowing into the GOM? Not that I think there’s a great probability of that happening. But there is always a possibility of it. I have one rule when making an operational decision: if things go bad can you still justify the reason for the decision? Like we all know now: there is the plan and then there’s what happens.
Rock, Looking at the schematics that Moon so nicely supplied, I think there is a very logical reason for having the Annulus plug adjacent to the column plug. It looks to me like that is the only place where you can guarantee a non-by-passable annulus plug. If the annulus plug were placed higher up in the well and did not overlap the column plug then there is some, yes pretty slight as long is there is not production casing failure, possibility for the reservoir to get around both plugs. Far fetched admittedly but possible. By using the RW and applying the annulus plug at the bottom you have overlapping cement and an almost zero potential for reservoir bypass of either plug. I'm going to bet the science coaches maybe saw that possibility also, and are taking the belts and suspenders approach. Your approach absolutely plugs the annulus but without the overlap of both plugs it leaves open the very slight possibility of a bypass fault. Keeping in mind that the Gov't side of the equation probably has not let loose of the thought long held thought that somewhere there was a casing probable / potential failure. Anyway just a thought.
There is a very good forensic reason to do this, find out the real TOC for the original cement job. According to the diagram it is supposed to be at 17,260 and the bottom of the casing above is 17,168, so there is an easily accessible annular space of less than 100 feet that should have mud, not cement or oil. If they intend to pursue criminal charges, the standard of proof is beyond a reasonable doubt. So resolving all reasonable doubts is in the best interest of justice for all.
So once they have completed the necessary preliminaries as outlined above, I'd say tell John Wright, "Drill, Baby, Drill". But as I have said before, with the uncertainites of using nitrified cement at these depths, it is not outside the realm of possibilities that he will hit cement, not mud. One of BP's recommendations on the issue of cement is to have the API do research on deep well cementing, a recommendation that I heartily concur with.
From what I can gather, the accepted practice is to inject the nitrogen into cement at 1000 psi. That would be fine for using to cement in newly spudded wells at hydrostatic pressures less than 1000 psi, or 2.262 ft of seawater (1,000 = 2262 x 8.5 x .052). The cement would foam when pumped and reduce its effective density for use in soft sediments. Doing the same thing at 18,000 ft is a whole different issue!!!!
moonie - Again...outstanding graphics. Mucho thanks for the contribution. No doubt we'll continually go back to them as the process goes forward.
Thanks Rockman - the drawing of the casing string is of course stolen from BP. I just added some color spots.
But just one question regarding your drawings, Moon. Where's the drillpipe / cement stinger which fell downhole? It's not going to be as easy as you project.
FH
The cement pumped during the kill is a now a massive 5,000 feet column. The drillpipe below the bop that fell off was 3,000 feet long. It is buried in the cement and will not interfere with the outlined operation.
The graphics have the depth readings no to scale) on the left.
Does this operation account for the oil that was seen leaking from the well head at its entrance to the sea floor? Bp was watching this leak for quite some time last night.
The procedure is not taking place yet and there is no oil leaking at the wellhead at all.
Thanks for the graphics, I've been wondering how they would take care of the problem.
Moon, wonderful graphics especially for us non-oil patch folk. Finally have the thing knitted together in my mind. Small request. Would you have a similar graphic of the casing hanger lockdown sleeve?