We are looking at options for doing deepwater sand clean outs with coil tubing. These are on failed we gravel pack welled wells. We are still in the very early stages of understanding the feasibility of this and would welcome any feedback on any experience doing similar. In particular, we are worried about ECD / return rates. The wells have quite a small pore pressure frac gradient window and we will need to use a riser with over a 7” I.D. to get the Crown plugs out.
Some of the questions we have in particular are:
Do we clean up to the FPSO or the vessel? – The FPSO has the advantage of ensuring we will defiantly have the ability to stay below the frac gradient, and there is no containment issues. But has the disadvantages of potentially plugging up the tree as the well will need to be choked back, issues around control i.e. vessel in control of the tree and pumping to an FPSO that has no control of that well. Cleaning up to the vessel will come with challenges around sand disposal, as there is potential for a significant quantity. Oil disposal (in a cost effective manner, trying to avoid a full well test spread) as we are currently unable to bull head the completion volume.
Any experience on the best type of coil tools for sand clean outs – Do we jet or run a motor? If jetting is, there any risk of destabilising the formation/Gravel pack around the area of failure.
Any comments on other items would also be gratefully received.
I once (about 18 years ago) carried out a very successful sand clean out by running the CT open ended (lot's of risk mitigation required to get that approved) and using water injection to the CT annulus, and the pressure drop across the tubing end caused a vacuum and literally vacuum cleaned (reversed) the sump out.
Not sure that would be allowed anywhere today.
Was so successful that at one point the skips were struggling to keep up with sand returns which were centrifuge cleaned at surface. But that was a WI well, and by the sound of it your pore pressure wouldn't like the hydraulics.
You should perhaps consider a foam clean out. This will lift and hold the sand, and the reduced hydrostatic will assist return flow.
Now, your 9-5/8" landing string will be an issue and will act as a vertical separator, exacerbated by foam break down in a pressure drop .
So, thinking 'outside the box' a little, I would look at running an additional deep set LV just above the SSTT
After pulling the CP's bullhead foam to displace oil in the LS, as it sounds as if circulation with a liquid to the return line via the XO will not work, and bullheading liquid in the 9-5/8" LS won't be effective anyway.
You might plan to put the isolation sleeve in the tree anyway to keep sand only in the main bore.
Run a small diameter velocity string inside the landing string to just above the deep set LV, probably the same diameter as the top end of the completion.
Make a hang off sub of some sort placed in the landing string just below the surface tree to hang off the inner string.
This will minimise any vertical separation.
Now, when the returns arrive at surface, you either have to bite the bullet on some surface clean out kit, choke, sand separators, and associated flushing kit, or, if volumes allow, I would accept that the safest and best place for the sand is in the test separator, which will have to be dug out after, but this is very dependent on distance to the vessel.
You don't mention volumes, so you will have to do the maths on that.
For the test separator option, it needs to be on the vessel, not miles away through a pipeline, as for sure the sand would settle in the horizontal with only a few inches to drop out.
Regarding BHA, I wouldn't run a motor, no advantage to more moving parts, simple open ended nozzle end penetration and flow will be sufficient.
Yes, you will likely induce more sand into the well, but if you don't do it now it will happen later anyway, so best if it happens now while you are cleaning out.
One important matter that is often overlooked, consider the well deviation geometry. In a true vertical well, fall back can be a long way down. In a highly deviated well, returns might only have to fall a foot or less to be on the low side, and then flow can of course bypass on the high side, so figure this into the plan too.
I'm not particularly busy at the moment, so if you want any help with [remote] peer review of the plans, I would potentially save you far more than I would cost.
Good luck with it, and please, post back with the final methodology, and the outcome, and probably most importantly any issues you come across and how they are resolved.