re: For the technical folks..

Not sure about the Q or Enterprise but the H.P.1 full capacity is 42,000 Bbls and 70 MMCF PD.

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Flow up the annulus and then entering the casing at the seal assembly or down the annulus and up through the float collar.

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Either situation once it is closed in at the surface the annulus will become pressured up and most likely not be able to hold 10k+ pressure. Unless there is some super high strength 16" that isn't in typical spec book, 16" will never hold that. You would just have to hope there is a good cement job on the outside of 16" to increased your integrity, but I wouldn't put money on it.

Only way 16" wouldn't be exposed is if there was trully a wet shoe, and there was a good cement job on outside of 7". All very unlikely from the information that has come out.

Yes it would, but this rupture would occur at a shallow depth. The KW fluid would have enough hydrostatic head to kill the well.

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MountainTiger

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I agree with you, but a full column of water in the well would not allow the well to be static with it shut in. Full column of oil, and some gas, would be less hydro. head than it would be with water. So with one bubble of gas in the well would migrate up (expand) and increase pressure, times that by "x" amount of bubbles.

Yes pressure decreases as you move up the well. According to Boyles law the gas bubble has less pressure exerted on it and must expand. As it expands and gets to the surface it is taking up more and more volume slightly compressing the oil. Pressure decreases on the bubble, but the bubbles expansion begins to increase the pressure of the system. Until the oil, cannot be compressed anymore, which it only slightly compresses under high pressure. So gas bubbles would stop expanding at some point.

The blow out occurred by this same phenomenon, except the weak point was at the seal assembly.

As you see below, 16" isn't very strong. Depending on which 16" was ran.

let's work through the actual situation:

We know the reservoir pressure was measured via wireline to be 13.0 ppg equivalent mud weight at 17821'. This works out to 12046 psi.

The critical casing strings in this discussion are the following (as seen on the wellbore schematic):
16" 97# P110 Hyd 511 -- burst at the connection is 6660 psi (slightly lower burst than the pipe body)
9 7/8" 62.8# Q125 Hyd 523 -- burst of 13,840 psi

keep in mind these are differential pressure ratings, and there is always at least the pressure exerted by a full column of sea water applied to the backside of these strings of pipe (this is ultra conservative, it's usually something higher)

So if the well is shut in at the mudline, the pressure trapped immediately below the closed blind shear rams would equal:

Reservoir pressure - (height of the column of reservoir fluid) x the pressure gradient of the oil
12046 psi - (17821'- 4970') x 0.35 psi / ft = 7548 psi.

This is based on the oil gradient being a sort of standard .35 psi / ft. If the oil were lighter due to the presence of more gas, the pressure would be higher.

You can see that this pressure is well below the burst rating of the 9 7/8", and if the well were flowing up the 7" x 9 7/8" string, you have no risk of bursting that casing.

However, it becomes more complicated if it is flowing in the annulus behind the 7" x 9 7/8" string, as this pressure is applied to the 16" and 22" casing. I omitted the 22" from this discussion, because it is very well cemented at surface and backed up by a well cemented string of 28" casing and the 36" conductor casing as well. What really complicates things is the presence of burst disks in the 16" string as well, that are designed to relieve trapped annular pressure that would build when the well is producing. this is done so that you have a controlled release of the pressure that is reliable and does not compromise the structural integrity of the casing by rupturing it.

To make a more detailed study of it, you need to know what the burst disks were set to blow at, pore pressure data for the sand and shale behind the pipe, and additional cementing data.

oilfieldtiger,

Thank you for the excellent analysis. That is consistent with what I know and what I think I know and what I've heard.

The only thing I disagree with (and it's an academic point, unrelated to the rest of the discussion) is the bit about bubbles rising in the column. The bubbles don't apply a pressure to the fluid as they expand. The bubbles are allowed to expand because the pressure in the fluid is decreasing. But it's really not important.

How we got off on this tangent was when it sounded to me like you said that the upper part of the well would "feel" the reservoir pressure. I must have misinterpreted what you said because your number of 7500 psi is in rough agreement with my 8000-9000 psi. (I was assuming a lower density for the fluid due to the presence of more gas than usual.) So I think we're in violent agreement here.

oilfieldtiger

Are we for sure that the BOP was faulty before they took the kick, and if so what was wrong with it? Confused on the whole situation with the rubber sealers coming up in the return mud. Had someone tell me it was bc they accidentally shut the BOP when pulling pipe and it tore the seals. But that doesn't make sense bc they close the annulars, pull pipe until a joint hits then close rams, to insure that there isnt a joint in the rams.

There is not gas in the well bore. Everything in the well bore is liquid or solid... no gas. The reduction in pressure is not relevant because that the high pressures there are no gas bubbles. It is not until the oil pressure drops up a whole lot that the methane entrained in the oil comes out as a gas.

If the gas caused the pressure to go up in the well bore then the increase in pressure would make the gas go back into the oil which would decrease the pressure. This is impossible things reach equilibrium they do not continually expand and contract like that.