You have probably come across well test interpretations that show a negative skin of -5 to -3 together with low permeability formation (for example, 4 md). What is the reason for this?
– Vertical oil well
– Not hydralically fractured well
– Carbonate res.
I have two interpretations, and I would like you to share yours as well:
1. Fractures/fissures intersecting the wellbore: Even if the rock around the well has low permeability, the presence of a few highly conductive pathways (fractures/vugs) can allow faster flow through those paths, resulting in negative skin.
2. Local effect of previous acidizings: The near-wellbore zone may have been locally stimulated, while the average reservoir permeability remains low. Wherever there is an increase in k, a negative skin may be obtained.
Reminder: the low reservoir permeability also needs to be verified: was the permeability low from the beginning (due to the tight nature of the reservoir rock), or has it decreased over time as a result of activities such as drilling, completion, workover, and so on.
I shared this post on LinkedIn and got great comments:
- This is a very interesting buildup here. I have two points regarding this test. 1 the half slope represents a fracture response, so the well might be fractured, as what we have in hydraulic fracturing and not a dual porosity medium. The second concern is the end of buildup which I suggest you check for the drift in gauge. The rise in derivative curve might be drift effect.
- Sometimes acidisation in carbonate rock creates wormholes long enough to intersect with each other from different perf holes. These sometime depict themselves as near wellbore fracture system or even as a ‘hydraulic’ fracture response on the derivative (though not as well defined as a real hydraulic fracture response would be). This has been seen despite acidising below the fracture gradient pressure.
- You may consider verifying the interpretation using additional sources of information. Fractures intersecting the wellbore can be confirmed through FMI open-hole logs. If a Production Logging Tool (PLT) or Distributed Temperature Sensors (DTS) are deployed across the perforated interval during the test, they can also help identify zones with active fractures by detecting fluid movement or temperature anomalies associated with fracture flow.
- The derivative also suggests no WBS. This is also an important take away: without WBS, the next-to-the-wellbore response is properly picked (1/2slope line). Otherwise, we may still interprete it as a low kh and high negative skin case but without supporting evidence from the derivative itself.
- Great comments by all. Indeed, PTA interpretation has to be done holistically, accounted for all evidences beyond pressure transient data. First the qualitative interpretation from the derivative needs other data (geology, seismic, logs, etc.) To support, and quatitative interpretation (kh, s, boundary locating, etc.) needs proper QC of all input data (rock and fluid properties, test rate, production history, etc.). Thanks for sharing a real life example with the interpretation supporting by other real life data/info.
- There are different types of Skin, if you refer to the total skin I understand that it might be puzzling. You might want to have it reviewed by a PTA specialist. Contact me.
Author: Sadegh Salmani
