9.6 ppg circulating system prior to kick. Figure 10.4 ppg to kill.
SIDPP 330 PSI SICP 750 PSI
Drilling ahead with no problems 200 units BBG and 1000 Units connection gas. We deviated about 3 ft above our projected line and back into the higher porosity sand zone and kick followed.
Shampoo here are some basic calculations based on the info you have provided:
TVD = 10950 ft
MW prior to kick = 9.6 ppg
Assuming no ballooning or communication to neighboring live well....
By drilling up 3 ft TVD " abnormal" formation pressure is going to increase because pressure is highest at the apex or top of crest of the gas cap. Gas gradient is normally taken as 0.1 psi per foot.
The point I'm alluding to is that 3 ft up, even though CG> 5XBG (under balances when static) won't make a difference to enough to induce a kick under dynamic conditions and hence Rockdoctor suspicions of communication with another could be true. But.....
Was the kick taken with pumps on or off ?
Was connection or pump-off gas circulated out ? ...
..or allowed to incrementally stack in the wellbore while drilling until such point the combined effect of subsequent CG introductions into the annulus underbalanced the 9.6 ppg mud even for dynamic conditions ?
Information or opinions are solely provided for educational and/or discussion purposes on an informal public forum and should not be interpreted as a recommendation for a specific treatment plan, course of action or product/ service. Use of any of this information does not replace consultations with qualified individuals in these respective fields.
sorry for slipping in that late. I just read sequentially through this discussion, and with a geological hat on.
My thoughts along the way were as follows (in sequence): - doesn't look like simple ballooning to me...
- pressure in the fractures appears to be lower than in the matrix, could indicate communication with the producing well...
For that reason I would really observe closely what the producing well is doing and if communication with this well can be confirmed by further evidence (e.g. shutting in the producer for a short time to see what response you get in the well that you are drilling).
I would also be even more concerned about the completion of your well than about the drilling. ...
Good luck and please keep us posted about your progress and your further observations.
Shampoo,
I think 'rockdoctor' has made some good points.
Now anything I write here should be taken with a pinch of salt, because earlier on when you were tripping out, I said that I thought maybe you were OK. But I reckon I was wrong, in that you encountered significant gas on circulating bottoms-up when back on bottom.
Now things sound even more complicated.
My gut feeling is that what you initially saw was a small kick, compounded with a 'ballooning' effect, which is what you suspected to start with.
Intuition also tells me that it may have been the 'bigger minds' to whom you alluded who made the decision to cut back the mud weight to 9.55 again. Which now obviously seems wrong.
But 10.4 sounds WAAY too high without causing yet greater problems further back along your hole.
What I'd do in your position (if you can) would be to convince your 'Powers that Be' that Now is the time to stop pushing for making more hole, but instead take careful stock of what you've already observed. Maybe raise the mud weight back to 9.7+ or 9.8, do considerable circulation and flowchecks, and sit back to figure things out.
Also, now it seems accepted you actually do have a well-control situation, take the proper precautions to ensure not losing the well. Like you've got to move the pipe from time to time in a situation like this, which will mean stripping, even if only for a few feet or so. Check you've got a spare Hydril rubber to hand.
The producing well in proximity means good liaison between the production and drilling departments. If Production won't go for shutting it in (which may complicate things even more), try to reach agreement that they don't fool with it, changing choke sizes, or anything like that. Get them to share their pressure and flowcharts with you, to see if there's any correllation between what the producer was doing at the same time you were seeing your own effects on your drilling well.
And one thing 'rockdoctor' said is 110% certain. That being that completion (even if you call TD at this point and call it quits without going further) is going to call for some very careful planning in well-control terms. And completion can only be contemplated once you've got your current conditions stable, even if on a knife-edge.
Sorry if these are only generalities, rather than lots of numbers and equations. But I'm here, and you're there, and it sounds like you were calling the right shots and asking the right questions a while back. Hopefully the guys back in town have started paying attention to what you've been saying, by now.
Take it easy, and once more,don't factor luck into anything, but I wish you the best quantities of it should it turn up.
Information or opinions are solely provided for educational and/or discussion purposes on an informal public forum and should not be interpreted as a recommendation for a specific treatment plan, course of action or product/ service. Use of any of this information does not replace consultations with qualified individuals in these respective fields.
sorry for slipping in that late. I just read sequentially through this discussion, and with a geological hat on.
My thoughts along the way were as follows (in sequence): - doesn't look like simple ballooning to me not any more the ballooning is still there which is becoming problematic now as it is disguising the kicks which are become substantially worse. With each incremental density increase the balloon effects are further increasing. We have weighted up once again to 11.1 ppg to control the influxes. Following circuation the well takes immediately 150 - 200 bbls fluid. I hope we don not know the bottom out. - ECG might be close to formation strength, but was the FIT really an FIT or a limit test? Looking into what is going on here the FIT test was based on an arbitrary number picked out of thin air. FIT to 10 ppg but drill with 11.1ppg? Confused to say the least. - has certainly encountered a dual porosity system with fractures, the FIT (if it was really an FIT) might have been the fracture propagation pressure.There has definately been a direct correlation between our kicks and abnormal pressures when we get off course directionally and venture into the higher porosity zone. Ultimately we want to be drilling in the lower section of the oil bearing zone so we can fracture up into it. We are off course and drilling it the GOC area and above. - static mudweight appears slightly underbalanced against the pressure in a relatively low permeable rock matrix. - pressure in the fractures appears to be lower than in the matrix, could indicate communication with the producing well.This is interesting but yes across each fracture zone we cross we loss approx 20 - 30 bbls of mud before we stabilize.
For that reason I would really observe closely what the producing well is doing and if communication with this well can be confirmed by further evidence (e.g. shutting in the producer for a short time to see what response you get in the well that you are drilling).This is a valid point and i will be sure to investigate this further if the operator is will to provide the information
I would also be even more concerned about the completion of your well than about the drilling. I don't know whether there will be a requirement to complete selectively on some intervals, and thus a cemented liner has to be run. If yes, I would clearly put a strategy in place to get writ of the connection gas before running the liner, and this might necessitate shutting off the fractures that you encountered, at least temporary. I also would include a strategy for the producing well during your liner running and cementation. Another great point. We are running a tie back liner with swell packers in the open hole.
Good luck and please keep us posted about your progress and your further observations.
Appreciate the advice and the good luck, i will need it, been up for 36 hrs on the choke now and no relief in sight.
Too tired to post replies, on the choke again for the 7th time in 48 hrs.
No worries, some one here will be keeping tabs on you. If you can in effect catch 10 min of sleep every hour or equivalent or 20 min every 2 hr it will amount to 4 hr every 24 hr....but watch your step and dont' trip..i always do when i do 18 to 20 hr days. Look after No.1.
If the live well you suspect has communication with your well is a producer, you might want to consider asking them to increase flow rate or production from it.
This is where term "relief well" originated from, prior to the days when we actually drilled wells to kill one that's blownout.
Information or opinions are solely provided for educational and/or discussion purposes on an informal public forum and should not be interpreted as a recommendation for a specific treatment plan, course of action or product/ service. Use of any of this information does not replace consultations with qualified individuals in these respective fields.
Was connection or pump-off gas circulated out ? ...
Negative.
I have just noticed a trend with one particular driller. Bottoms up is 80 minutes. At the 80 minute mark of our current circulation and connection gas at surface he shut the pumps down to make a connection. The gas was accounting for about 30 bbls of volume in the annulus. So now we have 30 bbls gas reducing our hydrostatic and no ecd. A bigger influx soon to follow. Now with the pumps back on after connection we circulate out 6000 units from the firsts bottoms up and our BGG remains at 3000 units. After the second bottoms up comes to surface and we see the connection gas again 6000 units he shuts the well in. We have had no problems over the previous tour and current mud weight 10.8ppg and it seems that this driller is using poor drilling practices. Does this make sense as to why we are haveing these well control issues?
Was connection or pump-off gas circulated out ? ...
Negative.
I have just noticed a trend with one particular driller. Bottoms up is 80 minutes. At the 80 minute mark of our current circulation and connection gas at surface he shut the pumps down to make a connection. The gas was accounting for about 30 bbls of volume in the annulus. So now we have 30 bbls gas reducing our hydrostatic and no ecd. A bigger influx soon to follow. Now with the pumps back on after connection we circulate out 6000 units from the firsts bottoms up and our BGG remains at 3000 units. After the second bottoms up comes to surface and we see the connection gas again 6000 units he shuts the well in. We have had no problems over the previous tour and current mud weight 10.8ppg and it seems that this driller is using poor drilling practices. Does this make sense as to why we are haveing these well control issues?
Best to educate the driller's TP first and later stand there when the TP explains and conveys your requirements to him.
CG trends in terms of magnitude can remain constant or keep increasing in magnitude with each subsequent connection. It seems you are dealing with the latter type.
If the situation allows it, it is best to first circulate out all connection gas slugs out of the lagged stack over the MGS. You might need more than one circulation to observe a drop in BG gas if you can afford it.
Weigh-up gradually by one point. As SD2 mentioned , you dont want too heavy a mud, so its going to be a trial and error balancing act, pun not intended.
Next perform a dummy connection with pumps off, zero stroke counter and observe gas trends. If the CG after after this weigh up drops ...good.
Next weigh up again by another point or two and do the same until such time you get acceptable gas levels or minuscule CG that your ECD, HSP and MGS can handle. This is time consuming but it is one way to ascertain the best mud wt limits to employ for your well's situation.
You can also use a slower ROP so that only one or maybe 2 slugs of CG is in the stack per bottoms up, enough for your static HSP or ECD to counteract and cope with ie: one connection per bottoms up.
Depending on the make, you might also want to check the choke valve for wear if you have been using it for quite a while now
Information or opinions are solely provided for educational and/or discussion purposes on an informal public forum and should not be interpreted as a recommendation for a specific treatment plan, course of action or product/ service. Use of any of this information does not replace consultations with qualified individuals in these respective fields.
Whether you have a ported or non-ported check valve is very important to know, as PJ has inferred above. It will be located somewhere in your MWD / Rotary steerable / motor assembly, so ask your directional people what sort it is. This is something easily overlooked (take it from one who knows), and whichever type is installed without reference to client preference, and according to what's to hand. A lesson I learned the hard way. Personally (as a result of that experience) I will no longer allow a ported check valve to be used. They make reading SIDPP a lot easier, for sure, but offer an unwelcome flowpath if you've actually taken a kick. It's surprising: that hole (the 'port') is very small, but can allow a remarkable amount of fluid through if there's a big pressure differential, and if that flow is allowed to continue, the hole will start to wash out, and become bigger. Also the flow may cause turbulance and vibration leading to further failure of other components.
For 'ported' check valve, read 'check valve deliberately designed to leak'. They ought to be outlawed.
AK
There is that float info AK ha ha, good thing we are running non-ported
« Last Edit: Apr 13, 2012, 4:06am by sostraightup »
Yeah, I was sure there had been discussion about the merits and demerits of ported vs non-ported floats. Well done for finding it in the Ali Baba's cave of information which this site has become.
A ported float is an invention to 'make things easier', and I'm terribly wary about those sorts of things. Heck, these days if you buy something like a washing-machine, it's got so many different programs that you need a degree in computer science and spend a fortnight reading the manual before being able to wash a pair of socks.
I still occasionally think back to the event which turned me off ported floats for life. It was scary, and ate up millions of dollars and days of time. Nobody hurt, nothing broken, but we lost the well and most of the drillstring (including some very expensive third-party downhole kit). And I also wonder how things might have turned out had we had a non-ported float instead. Because the float is not a piece of well-control equipment, and had we treated it as such, we might have ended up getting into an even worse bind, should it have failed at a crucial moment.
I now won't run ported floats, and I advise against them. But it's not hard and fast. The jury's still out, and each to their own opinion.
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