Congratulations on successfully freeing the drillstring. And thankyou for providing the extra information.
You mention a small sand stringer. Did SIDPP and SICP clearly stabilise prior to starting the well kill? If the formation has low permeability, this stabilisation can take a long time and if the well kill is initiated before SICP has flat-lined, the SIDPP value can be underestimated. Had the choke pressure changed by the time the initial circulation was started or was it still 840psi?
An issue with ported NRVs, especially with heavy muds, is that they can become plugged during the initial build up phase after shutting in the well. This can be identified by the SIDPP stabilising before the SICP does.
When using a ported NRV it is worth going through the same process as for a non-ported NRV to check the SIDPP i.e. conducting a pump open test on it. Best practise for this is to very slowly pump down the drillstring recording standpipe pressure and pump strokes and plotting pressure against stokes (like performing a formation strength test). The slope of the line will change significantly when the NRV opens and, at slow pump speed, this will indicate the true SIDPP.
One explanation for the apparent change reservoir pressure is that measured SIDPP was not the true value. There was a significant difference in the initial SIDPP and SICP which was wither due to a significantly sized formation water kick or potentially incorrect SIDPP reading due to the NRV becoming plugged during build up.
A question asked during my initial reply remains the same: What was the standpipe (pump) pressure during the first circulation of the well kill?
This data should indicate if plugging of the NRV had led to an incorrect reading for SIDPP initially.
You do not mention the size of the kick. As mentioned in my previous reply, the kick must have been large to generate the 210psi difference between SICP and SIDPP. If however, the kick was small, then this would be another indication that the NRV had plugged, giving an incorrect value of SIDPP.
Another question I asked related to the choke pressure during the well kill.
Given that the influx was water and no gas has been mentioned at all, the choke pressure should remain pretty much constant during these phases of the kill. During the first circulation, if standpipe pressure was maintained constant at the correct value, choke pressure should have remained constant at around 840psi until the influx reached surface. As the influx was displaced from the well and replaced by the original 1.72sg mud, choke pressure should have fallen to 630 psi.
During the second and third circulations, the choke pressure should have remained constant at the pre-circulation values while pumping kill mud down the drillstring and then fallen as the heavier mud was pumped up the annulus.
As mentioned during my initial reply, the most common time for additional pressure to be applied to the well is while starting / stopping the pumps. With a surface BOP; during conventional well control we assume there are no annular friction losses. Any time we start or stop the pumps (or, indeed, change the pump speed) our focus must be on the choke pressure - it should kept constant.
If, after starting the pumps or changing pump speed, the choke pressure has changed, it should be adjusted back to it’s original value and the standpipe pressure given time to settle before the standpipe pressure is recorded. If the choke pressure is wrong at this point then the standpipe pressure is also wrong!
While stopping the pumps, best practise is to increase choke pressure a little before stopping the pumps. Once the pumps are stopped, choke pressure can then be carefully bled off back to the correct value.
While possibilities such as low permeability formations should not be discounted, an analysis of pumping and choke pressures during the three circulations should allow you to determine if indeed additional pressure was trapped in the well during the killing operations. The fact that you were differentially stuck at the end of the operation suggests that this is the case. As such, the 2.05 sg mud is significantly higher than the pore pressure encountered.
Under these circumstances, if you keep drilling with the 2.05 sg mud you run the risk of losses or further differential sticking as you drill ahead. A note of caution however, simply circulating back to the original kill weight mud can destabilise claystones in the open hole above you.
Steve Nas’s earlier reply gives a lot of excellent guidance and advice. As always in these instances I am a little reserved giving too much advice because we can’t see enough of the picture. For our benefit, is this a surface or subsea BOP? Is it a vertical, deviated or horizontal hole? Was there a short or long open hole section?
Key questions to answer are:
Was it an “encountered” kick ..i.e. did you drill into a new formation? Or was it an “Induced Kick” caused by losses, swabbing, barite sag etc. From your significant SIDPP the immediate assumption is that you drilled into an over-pressured formation. . Did you see any signs of drilling into a new formation? Were you at a depth where this was expected or a possibility? Was it an exploration or development well? How long is the open hole section between the kick depth and the previous casing shoe and what formations are there?
Were you drilling with a NRV (float valve) in the drillstring? If so, how was SIDPP measured, especially if you also have a mud motor etc in the string.
You don’t mention the volume of the kick but it must have been quite significant to generate a 210 psi difference in SIDPP and SICP. Assuming a formation water gradient of 1.06 SG (0.46 psi/ft) this requires about 740ft TVD of influx. Even with an influx density closer to fresh water it would still require 675ft TVD of influx. Is it water-based or oil based mud?
How was the first circulation conducted? Was the Standpipe Pressure (SPP) after pumps were brought up to kill speed as expected or was it significantly different to SIDPP + Slow Circulating Pressure? Or did you force the SPP to be this value? Did you encounter any losses? Did the pit volumes stay relatively stable? In the absence of gas, the pit level should not really change at all unless returns from the degasser are diverted somewhere.
Some data vs time is required to fully analyse the problem before being able to suggest a solution:
Unless SIDPP and SICP had not fully stabilised prior to the kill operation starting, it is unlikely that the pore pressure in an encountered permeable formation would change during a well kill. It has happened to me once but that was while drilling an in-fill well in an existing field and Production had unexpectedly switched on a nearby Water Injection well!!
In the absence of this, as long as the first circulation was conducted with the 1.72sg mud throughout, the change in SIDPP and SICP at the end of the first circulation is very likely to be trapped pressure. This could have been due to wellbore breathing (especially if losses were observed during the killing operation). However it is usually generated while starting up / increasing pump speed or slowing down /stopping the pumps. If the choke pressure (surface BOP) or kill line / BOP pressure (subsea BOPs) is not kept constant when the pump speed is changed then you will get additional trapped pressure.
If this is the case then you had 320psi of trapped pressure in the well at the end of the first circulation. What caused this is likely to have been repeated during the second circulation resulting in a further 270psi of trapped pressure at the end of the second circulation. The additional 70psi on the SICP could be due to mud weight variation
If you did not drill into a new, permeable formation when the kick was taken then both the initial kick and subsequent well behaviour could possibly be due to wellbore breathing, especially if you were not drilling with a NRV in the drillstring. However, more information about the wellbore geometry and formations as well as whether you had been seeing losses earlier in the open hole section are needed to comment further.
As to how you are differentially stuck you need to consider what formations you were drilling through prior to the kick. If you have other permeable formations exposed in the open hole section then this is likely to be where you are stuck. If you just drilled into a permeable formation having previously only been drilling through impermeable formation prior to the kick then the only place you can be differentially stuck is across the new formation. Given the initial and final SIDPP, the overbalance could be as much as 920 psi.
Should you require any further assistance and analysis regarding the event and it’s resolution please feel free to contact me at email@example.com.
Your original influx showed a SIDPP of 630 psi which requires a kill mud weight without any trip margin of 1.85 sg. The increase in SIDPP from 630 psi to 950 psi is strange and could indicate several issues.
Not enough information to fully comment but the 320 psi
pressure increase after the first circulation indicates that something was not
Then once you pump the 1.85 sg kill mud around you have a further 590 psi SIDPP.
Indications here are that errors are being made during the kill circulations, suggest that you have a detailed look at pressures, pump rates, volumes and mud weights that were used during the kill,
The mud weight increase from 1.72 sg to 2.05 sg would makes this a 1550 psi (2.75 ppg) intensity kick which is significant and that does not appear to correlate with the original kick data.
Also review this with the G&G team and see if they have explanations on the kick formation and possible pore pressures.This does not look like trapped pressures this is a case of errors being made along the way