Quoting shahhrs;40684ExCompanyMan
I thank you for your answers however I failed to understand what impact the leak would have on the pressure at the BOP after “sealing the well”…starting from appx 6300 and rising slowly to now about 7000 psi.
[I]When a kick is shut-in, Bottom Hole Pressure = [ Mud Hydrostatic Pressure + Hydrostatic of Kick + SICP (Shut in casing pressure) ]. The figures you quoted above reflect mostly the SICP. Note that the parted or cut drillpipe top end is beneath the shut-in BOP, but will play little role to contribution of any part of 6300 psi, because by now any pressure differential communicated from the bottom of the hole via drillpipe to the top would have equalized with SICP.[/I]
I am interested in getting yours and others comments about one of the articles i saw on Oil Drum by B K Lim who believes that the well was located on a high risk geological formation and proceeds to say following:
After quickly reaching 6,400 psi in the pressure test using the TOP CAP, the increase in the well pressure slowed down to 10, then 2 to less than 1 psi per hour. Oil and gas are obviously being forced into the “giant aquifer” which kept expanding and finding new pathways in the rock formation.
[I]All kicks when shut-in, be it pressurized aquifer formation water, oil or gas, will initially cause a rapid rise. If readings are tabulated at this stage, the pressure increases versus a uniform time interval will not be constant, ie: relatively steep graph[/I].
[I]After this initial stage of rapid rise in shut-in pressure, the increase rate or gradient of curve - ONLY IF the kick constitutes a gas component - relative to the curves previous steep gradient, will slowly level off and the difference with each subsequent pressure reading compared with the previous one will be almost constant giving a more linear but less steep curve henceforth.
At the shut-in stage of the curve, following the rapid rise to 6300 psi, 10 to 2 to 1, psi per hr, of this less rapid rise in pressure section indicates gas migration to the top for sure.
However if the rate rise for this stage stays constant at for example 10 psi /hr, (or 2 or 1 psi) then it can be safely be assumed there are no leaks and well integrity is good ie: slow increase in pressure due to gas migration. But for pressure increases to keep creeping up over days is another thing.
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[I]This could be the case after the recent shut-in, since the pressure increase rate has reduced from 10 to 1 psi per hour, and has stayed fairly constant. 1 psi per hour ( as per Thad and Kent), does not seem like much but if view over days ( what’s it now ? closing in on 7000 psi ?) it could indicate either, leak paths being filled or prised open with wellbore fluids under shut-in pressures OR seeping into the formation, finding or making new paths, but certainly has not so far, made its way into large vug or cavern as this scenario would indicate a sudden substantial drop in shut-in pressure if the cave is empty[/I] [I]or underpressured compared to shut-in pressures. OR left over of the gas that was trapped shut-in at the bottom the wellbore after the shut-in is still slowly migrating to the top but with back pressure resulting from shut-in prevent further influx into the wellbore.
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[I]If leak paths have been sought out by pressurized wellbore fluids under shut-in or even be the cause behind surface seeps, then when they open the well for bleed to conduct relief bottom kill, these wellbore fluids with no shut-in pressure to sustain invasion will reverse and flow back into the wellbore if kill pressures are lower than current shut-in pressures. Think ballooning. Weighted kill mud via the relief well under pressure of kill pumps will then replace all these vugs and cracks to ensure a proper kill not just of the wellbore but also any cracks or paths made during drilling, blowout and previous top kill attempts.
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That is why the initial 8,000 to 9,000 psi passing mark would never be reached. After 41 hours, the pressure inside the top capped well was 6,745 psi and still rising very slowly. Of course, the pressure inside the capped well would never decrease (until the reservoir is depleted) even as oil and gas are being forced further into the EGCP zone and into the giant aquifer.
As only the light hydrocarbons (methane) filter or seep through the Quaternary Sediment layers, no oil seeps would be evident at the sea floor yet. The oil would remain buried beneath the sea floor until weaknesses in the sediment developed into cracks big enough to result in active oil seeps (which would also mean a near calamity). By then the hot oil and gases from the reservoir may have tilted the world into an irreversible ecological disaster, by warming up and vaporising strata of methane hydrates into gas. The result would be an exponential increase in dissolved methane in the deep waters of the Gulf and eventually into our atmosphere. No one knows how much methane hydrates lay beneath the Gulf sea floor.
But one thing is for sure. The longer the gushing well stays “top capped”, the more severe is the environmental damage. There is no logical reason why the gushing oil could not be tapped through the LMRP TOP CAP with a floating platform or subsea facilities; rather shutting it off completely to cause further damage to the fragile sub-seabed structure and sediment."
I will appreciate being enlightened on this issue.
Thanks