our carbonate reservoirs (with low permeability but large natural fractures) with
diesel oil based mud (mud weights up to 1.9sg) and complete wells with cemented
liners that we perforate underpressure later on.
drilling fluids contractor says the diesel oil that filtrates or penetrates the
reservoir later on can get mixed with water produced during cementing job and
create sticky material and thus considerably damage the formation.
Do any of
you have encountered similar scenarios? What mitigations were in place? Is the
risk really high?
information will be appreciated.
I have used both WBM and oil based muds for drilling carbonate reservoirs.
Choice is usually a balance between easy of drilling (well engineering/drillers) and formation damage (production technologist).
Why not drill an easy well with WBM take some cores and formation oil samples. Then do some duplicate formation damage work with core sub samples saturated with formation fluid. Take some core samples and ensure your core is full of reservoir fluid. Then test sub samples for damage from, whole OBM, OBM filtrate, cement fluid and excess mix water from setting cement - and see if you have any change in permeability.
One should always base reservoir fluid type selection on physical formation damage testing.
If you are worried about water from the cement job then ensure you have a very low fluid loss (less than 50 mls with no free water) which you should be programming for a production casing anyway.
Do you have any movable formation water present across your reservoir zone ?
I would be more concerned with material in my reservoir such as "asphaltenes" precipitation with aromatics from your diesel than water from my cement job.
Be careful when using diesel mud ensure full HSE equipment is used, separate laundry equipment for work and normal clothing and address dermatitis prevention with all staff every month.