Sometimes, carbonate reservoirs just don’t make sense especially when you are dealing with low resistivity pay (LRP).


For an LRP reservoir (virgin with no prior production), you’d notice sections or layers with lower resistivity readings in the same oil bearing formation interval. Or, you might also see consistently lower resistivity reading in a fully oil bearing reservoir.

Amazingly, when these LRP intervals are put on production, they produced 100% oil!

If we are not careful, we might accidentally ignore these pay zones.

In another case, I’d see a water like signature above my OWC, or even my FWL for a virgin reservoir. What the heck?

I got so confused, until I found about Low Resistivity Pay (LRP).

An LRP zone is a hydrocarbon bearing zone that looks like a water bearing interval on your open-hole resistivity log. Over this zone, the production data shows little or no water cut. Even the mud logs shows strong hydrocarbon show.

We know that in Low Resisitivity Low Contrast Reservoir, the resistivity is lower than expected. The normal conventional tools wont' cut it.

The factors that affect the low resistivity low contrast include bed thickness, grain size, mineralogy, structural dip, clay distribution and water salinity or any combination of the above will affect the well logging instrument to measure lower resistivity response than would ordinarily be expected inside a good productive formation. This response of low resistivity-low contrast is due to the low vertical resolution of the conventional logging tools, which can not measure thin-bedded pay zones.

To detect a potential an LRP interval in a carbonate reservoir, I use these six generic indicators to detect a potential LRP interval:

  • Appears in the same formation interval.
  • Porosity is medium to high.
  • Resistivity is less than 3 Ohm-m.
  • Formation water is very saline.
  • Mudlog shows strong shows.
  • Production shows zero to little water cut.

An LRP interval occurs when:

1. The LRP interval is in a transition zone phenomenon.

2. Deep high saline mud invasion.

3. Presence of conductive minerals such as pyrite.

4. Presence of microporosity that holds significant volume of capillary-bound water

5. Anisotropic effect for high angle wells within thin reservoirs. Tight carbonates are often affected by deep invasion of conductive mud filtrate, which consecutively affects deep resistivity reading.

To validate an LRP, I look at the core description, core reports, NMR logs, production data and nearby wells for comparison.

The biggest indicator to look for is the amount of produced water when we put the well on production.

In an LRP, the water is immobile. Expect little or no water production across interval with high water saturation. Done right, you might add a lot of reserves just by looking for LRPs!

So, here is the ideal way of going about it.

1. Try using Thomas-Stieber method was used to determine the shale distribution in the reservoirs and its properties.

2. If you can, try to use the tri-axial resistivity where you can resolve the horizontal resistivity (Rh) and vertical resistivity (Rv).

3. Then calibrate the calibrate the resistivity model which using Hagiwara macroscopic anisotropy approach.

4. Use Waxman-Smits equation to calculate the final fluid saturation.



  1. SPE-177709-MS Evaluation of Water Saturation in a Low-Resistivity Pay Carbonate Reservoir Onshore Abu Dhabi: An Integrated Approach