We're currently using invert diesel emulsion mud (70/30) for deep gas wells and see significant increase in gas production rates vs previously used biopolymer clayless mud.
Despite sufficient increase in production we're concerned with a probability of formation damage due to addition of third phase to the system (gas-water) and reducing gas flow?
What would be your experience, and what type of mud would you recommend for gas condensate fields (average water rate 2-4m3/day) with carbonate and sandstone reservoirs (lower carboniferous - visean).
Any help would be greatly appreciated!
I looked at the report not overly impressed. Did you tell them what you wanted ?
Do duplicate sample tests for all formations.
Water samples look like drinking water.
Mud properties unusable PV much too high.
No fluid loss properties.
How are you planning to produce the well? Make sure your FD report duplicate this.
Recommend you also look into the effects of "condensate banking", whereby condensate drops out of the gas phase inside the near wellbore rock, due to drawdown effects in tight rock (such as the Visean). The condensate then restricts free flow from gas.
You can find several (SPE) papers on this phenomenon.
Warm regards, Jorrit
Thank you colleagues for finding time to look into the question.
I'm attaching mud testing report for community's interest - table 1.2. summarizes the permeability studies (witer II is an invert emulsion diesel\water mud and Biokar is a clayless bio-polymer WBM).
The initial question about addition of the another phase to the formation (gas-water-condensate in formation + diesel mud filtrate) was based on the phase permeability distribution chage that is often observed at oil fields during water flood oil exctraction.
What do you mean by addition of a third phase (gas-water) to the system?
What actually is happening.
For a diesel OBM in HTHP wells (never advised for your rig crew breathing, skin problems or cancer risk) I would do the basic conventional formation damage tests .You will need an approved laboratory to evaluate a diesel mud system.
As Scott said do the testing!
If you have a core samples look at the barytes particle size distribution possibly with addition of calcium carbonate. Also look at the base OBM system ensure you have no spurt loss, reduce fluid loss to as low as possible with additives. Evaluate whether the diesel, the whole mud, the water phase, plus all individual mud additives include any fluid loss control additives are non damaging and compatible with the formation and formation fluid. Formation damage prevention is not often so simple !
Best of luck Ian
Dave - it might be that an OBM using diesel is so rare these days that nobody has the experience to reply?
I know they are still regularly used Offshore Mexico, so maybe someone in that neck of the woods could help?
If the OBM is getting better production, then all other things being equal it would appear that the use of a WBM is causing formation damage (higher skin factor).
As Ian Petitt said in another post, using a WBM in an HPHT well is problematical and if the spurt loss is not being controlled, then this could be causing the higher skin factor - at least in the sandstone.
But really it needs the Operator &Fluids Company to do a proper investigation of formation / drilling fluid compatibility, preferably using core plugs rather than just cuttings samples returned from the well.
All the best
As part of our spring-cleaning efforts, I check the activity of members.
In this discussion, Oleksandr didn't receive a reply.
Perhaps some of our more active members might be able to contribute a response.
And, remember, if you can't help, you are likely to know someone who can and you can always forward the SPREAD email to them.