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Trapped Pressure during Well Control
11 April 2019

We have had a situation where the BHP changed significantly during well killing

The operational steps are as following
  • Drilling with 1.72 sg Mud weight at 3300 m, where influx was suspected
  • Shut in the well and measured SIDPP and SICP , where SIDPP was 630 and SICP was 840 psi.
  • Based on the above SIDPP, a KMW of 1.85 sg was prepared, and well killing was started through driller's method.
  • After 1st circulation once the influx was out [ It was confirmed as water, due to reduced chlorides level], the SIDPP and SICP both were same at 950 psi. There was however no reason for this rise in SIDPP.
  • The initial KMW of 1.85 was pumped, after which the SIDPP was 590 psi and SICP 660 psi. This meant a new KMW of 2.05 sg
  • We then successfully managed to kill the well with 2.05 sg, but during the killing we found that the string is stuck.
Since we have circulation possible,this is a probable case of differential, but the question is the well balanced at 2.05 sg, how can it be a differential ?

Also, is it possible that the 950 psi shown when the influx was outs was actually the trapped pressure that forced us to increase the MW?

Does anyone has experience with trapped pressure with well control and what is your technical understanding on this case? 
10 answer(s)
Drilling Engineer / Supervisor
Total Posts: 6
Join Date: 15/11/18
Hi Umair,

There is a mix up in your description on the third point, It is clear that you used Driller's method. Your statement should have read: "We started the first circulation"

All I can figure out is that the SIDPP did not stabilize before the first circulation commenced. 
Drilling Specialist/Well Engineer/Training Consultant
Kingdom Drilling
Total Posts: 389
Join Date: 10/01/05

in WBM If best practices and a very cautious abc detailed well engineered kill is not carefully implemented?
during kill well could have fractured?
cross flow resulted?

You also could have communicated with a deeper higher pressure zone ( we have experienced this before) 

in wbm depending on nature of formations present a fracture extension in failed formation can result. Without having reviewed all the evidence it’s difficult to pin point exactly what happened. 

I would go back three steps gather all evidence and speak to my well control guru whom I know can figure out exactly what went wrong. 

You have not mentioned what the people on the rig stated. Note this important part of evidence evaporates the fastest. 

Consultant Well Engineer and Trainer - HPHT, Deepwater and MPD Well Delivery and Well Control,
Welltrain Limited
Total Posts: 15
Join Date: 09/12/09


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?

  • Did it remain constant?
  • How does the Initial Circulating Pressure (ICP – obtained by subtracting the SIDPP from the standpipe pressure during the first phase of the driller’s method kill) compare to slow circulating rate pump pressure? 


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.


SPREAD Associates
Total Posts: 12
Join Date: 26/09/13
I am still not sure about The third bullet of your statement. If KMW (1.85 sg) was prepared and driller’s method (ICP = FCP) was used for the kill then the formation was subjected to excess pressures. With KMW the Wait&Weight should be used and FCP should be close to the SPR pressures, if W&W was used then the situation needs further deep analysis.
Drilling Engineer
Pakistan Petroleum Ltd
Total Posts: 22
Join Date: 02/08/15

  • This is a wild cat Exploratory well, so very little data from G&G is possible.
  • This was a surface stack, vertical well, with only 200 m of open hole section
  • This was an encountered kick and not an induced one, since we were drilling when we got it and not tripping
  • The float valve was ported,hence we could take SIDPP
  • We are using WBM
  • No losses were encountered in the whole process
  • The formation has remained the same, as per G&G it was a sand stinger.
Latest update is that we have sucessfully freed the string, using detergent pills and jarring, but the question remains " Was it trapped pressure or errors in killing the well which resulted in different SIDPP values"
D&C Project Coordinator / Decommissioning
Society of Petroleum Engineers
Total Posts: 24
Join Date: 25/01/16
The initial shut in pressure on drill pipe, and assuming no float valve in the BHA, should represent the pore pressure.  The coinciding annular pressure was higher.  This would mean an influx of formation fluid that is lighter then the drilling fluid.  Use the mud log to not the total influx prior to shut in.  Calculate the volume as height around the BHA and drill string.  Then the gradient difference of the drill fluid and influx fluid can be defined.  Possibly there is a mountain or volcano in the earth system where the water is hot.  What was the temperature in Vs temperature out when circulation the returns?
Norwell Engineering
Total Posts: 22
Join Date: 17/09/07
Steve has comprehensively addressed the potential issues over pressures, but highlights a good point.  If this is a water kick, and volume for pressure can be a multiple of 2 in water, it was large.

Additionally, you circulated the well a couple of times, with a lot of extraneous pressure.  Without knowing the mud type or formation I'd look at the mechanism from formation instability & contaminated mud.  Any solution shouldn't be focused directly on differential sticking, even recovering the string could leave you with formation issues.  In the long run it might be more cost / time effective to cut, plug back and drill it again (As long as you are comfortable that you can address the original issue).


Consultant Well Engineer and Trainer - HPHT, Deepwater and MPD Well Delivery and Well Control,
Welltrain Limited
Total Posts: 15
Join Date: 09/12/09


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:

  • Why did I take a kick”?
  • Why and where am I stuck? 

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:

  1. SIDPP and SICP vs time between shut in and final stabilisation
  2. Stand Pipe Pressure and Choke Pressure vs Time during the first, second and third circulation.
  3. PVT pit volumes/ levels throughout the operation

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

SPREAD Associates
Total Posts: 12
Join Date: 26/09/13
The job log is confusing, if the MW was increased to KMW then circulating using driller’s method does not make sense. If you still have full circulation and it is 100% certain that the influx was water, consider lowering the MW to the first calculated KMW, observe and plan forward.
Well Engineering Consultant and Instructor
Olango Consulting
Total Posts: 27
Join Date: 23/03/16


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.

  • The initial shut in pressure had not stabilized and the pressure was still rising before the kill commenced. Ballooning or supercharging during the kill circulation.
  • Additional influx entered during the circulation
  • Incorrect mud weights pumped

Not enough information to fully comment but the 320 psi pressure increase after the first circulation indicates that something was not done correctly.

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

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