· How much ballooning out?
· What is the depth?
· Do you have knowledge in the area structure? Nearby faults, directions?
· Do you have any Geomechanics study done in this area to know MEM or stress regime in terms of magnitude and directions?
Most probably the ballooning occurs in cracked L.S reservoir and it is belonging to the pumping rate and pumping shut down.
To those advocating running casing to resolve this problem I would urge caution. Ballooning / wellbore breathing takes many forms.
Where you are having to increase mud density in response to increasing pore pressure, the borehole pressure against shallower formations in the open hole may start to exceed the fracture opening pressure due to increasing hydrostatic and annular friction pressures. In this case, setting a casing will isolate the weaker formations and hopefully eliminate the wellbore breathing problem.
That does NOT appear to be the case here. The problem appears to be on bottom due to penetrating significantly depleted permeable formations which in teriun have significantly reduced fracture pressures, 8-9ppg vs a static mud weight of 10.5ppg. The last shoe was only set 200ft above the top sand!.
The mud density and ECD is as low as can realistically be achieved without mud cap drilling or drilling blind. Army has not reported borehole stability problems in the formations above the depleted sands. So…what exactly will running an additional casing achieve in this case (assuming the current losses will even achieve a decent cement job?)?
Reduced hole size will probably increase annular friction pressures and this increase ECDs and thus BHP and wellbore breathing / losses issues.
Unless additional borehole support is required to allow the use of a different approach (mud cap / blind drilling) then in this situation I would not advise an additional casing.
What is the relative quantity of fluid pumped into the wellbore (LCM + Mud) and the fluid released back after ballooning?
Are you as a team familiar with ''Drilling with a mud cap''?
Agree with all comments regarding this being a perfect application for MPD.
However, if MPD is not immediately available, it might be worth getting the mud service provider to perform a wellbore strengthening modelling to determine the pore size and advise a customized strengthening treatment to seal off the loss zones
Many thanks for your valuable input Dave, Ghazanfar, Iain, Eric, Steve and Doug.
To answer Steve question:
To answer Doug question:
1. How far do you need to drill to reach TD? 28 more stands
2. If you are in a known area with high confidence of pore pressures you could consider carrying on to TD and accept the flowback on connections? This is what we consider currently while drilling to the next depleted sand.
We are still assessing MPD and its availability to meet our schedule.
In the meantime, we decided not to do cementing plug, but we are building reasonable surface mud volume to continue drilling to the next depleted sand and "accepting" wellbore ballooning. We use Geoservice mud logging company and we do not have specific EKD sensor currently. They have fingerprint software during connection so that we can compare the result with manual calculation.
Hi. I have a couple of questions.
Is it possible that the hole behavior you are seeing is from a shale lying between the sands. This might explain why you are seeing different wellbore behavior.
Before you can decide how best to proceed it is important to consider the mechanism causing your losses. When a permeable formation is depleted, not only does the pore pressure drop but also the fracture pressure. As a rough rule of thumb the FP reduction is around 30% of the depletion below the original pore pressure. Under these circumstances, severe losses initiated in such a formation will usually be associated with the creation and propagation of a fracture in the formation rather than the loss of mud or mud filtrate into the pore space of the sand. If this is indeed the case then traditional LCM material designed to form a enhanced filter cake that plugs up the pore throats will not be successful. Similarly, the opening and closing of such a fracture at different bottom hole pressures (pumps on/off) will result in the flow back you are seeing.
How much extra BHP did you apply during the “ECD Squeeze”? If you picture the losses as a fracture growing away from your wellbore, you may consider that this action is actually counter productive..and also guaranteed to generate flowback.
Bridging / wellbore strengthening / stress caging material is intended to combat losses caused by fractures rather than matrix losses. The exact mechanism of how it works is the matter of hot debate but essentially you are trying to prevent hydrostatic pressure reaching the “tip” of the fracture and so allow a reduction in the stress at this point and prevent the fracture growing further.
I note that you are already using bridging material. Is the level being maintained in the mud, especially after the lost volume has been rebuilt? You might want to discuss the size distribution of this material with you Mud Company.. finer seems to be better!
Under these circumstances you also have to keep in mind minimum BHPs required to maintain borehole stability in the impermeable formations elsewhere in the open hole.
As others have commented, MPD can help you manage the change of BHP during connections although the degree of overbalance is severe and you can only reduce the mud hydrostatic so far. It is also unlikely to be able to help you in this instance.
You might want to examine your hole cleaning capability vs pump rate to see if you can operate at a reduced flow rate. Similarly, streamlining your BHA and drillstring can reduce ECD. Anything that can reduce the change in BHP between pumps off and on will reduce your ballooning tendency.
Fingerprinting of the flow back characteristics after turning off your pumps has been mentioned and this is really the best option to gain confidence in the behavior of the well. Also keep an eye on the “big picture” of losses and gains. The Driller commonly resets his PVT gain/loss when back on bottom and circulating. Thus flow back is always seen as a pit gain. Get the mud loggers to track total mud lost and recovered from pumps off back to pumps off. That will give you a better picture of the status of your well. Obviously a net gain is not a good sign.
Hope this is of some help,
Rock Mechanic issues, Ballooning, Breathing, are very often linked to temperature effects.
To make it simple, just an example, at 2000m you pump in front of your formation a fluid 20°c below the formation temperature at that time, it is stress-wise for the formation equivalent to an increase of 0,5 sg (+4,15ppg) of ECD, you may start loosing.
As you continue circulating, your mud will warm up and the open fractures will slowly close, also probably not fully, your losses will ease.
When you stop circulating your induced fractures will close even more, giving you back their internal volumes, as the formation comes back to its static temperature.
A close footprint over the whole sequences could validate this possibility and for sure open some new approaches on mitigation practices.
PS: Addition of LCM can (according to LCM type) force these thermal fractures open in the similar way proppant is used in unconventional shale oil. My two cents.