I took a semester of ‘Well Logging and Formation Evaluation’ class back in college. I had no appreciation of well logs, but I liked the class nonetheless.
I used to think that well logs were so awesome that they could tell us everything. Boy, I was dead wrong!
I soon realized that they are five things well logs couldn’t do:
#1: See beyond your well with well logs.
Not directly. You can’t see farther than what a logging tool can measure.
In fact, well logs won’t measure any more than a few feet beyond your well bore. Some even measure a few inches into the formation. Even PLT and pulsed neutron logs sees within the wellbore.
But, if we have more well logs spread over the field, then we can start propagating the reservoir properties acquired from the well logs across the reservoir. The more well logs were have, the clearer the reservoir picture becomes.
Recently, technologies like Electromagnetic Imaging Tomography and Pressure-Pulsed Neutron Logging allows simultaneous logging in different wells.
#2: Each log sees the same thing.
Each logging sensor sees differently. A specific logging tool measures according to its limited depth of investigation, vertical resolution and the target properties.
(I can’t seem to point the right source for this image. It’s everywhere on the net.)
Say we want to measure porosity from four different logging tools – Density, Sonic, Neutron and NMR. Although different porosity logging tools can produce similar porosity outputs, they see separate volumes of investigations, measure specific rock properties, and use different methods/physics of measurements- and they are sensitive to different factors too.
An NMR tool measures only a few inches from the sensors, while Neutron logs sees further than the invaded zones. The NMR log may give porosity values that are around the invaded zones. In contrast, the Neutron log may see porosity from the invaded zone plus some parts of the uninvaded zone.
If our mud filtrate is brine and the formation fluid is light hydrocarbon, the resulting porosity values from NMR and Neutron might be different. The resulting NMR porosity (which only sees inside the invaded zone) might be higher than the Neutron porosity values (that are measuring the porosity from the invaded zone and the uninvaded zone).
Regardless, expect the resulting processed porosity values to be similar after performing borehole and environmental corrections. If I expect to get 15% porosity, I should get something close to that value, not 35% or 0.5%.
#3: What you see is what you get.
Apparent log readings will be different from the final/actual log values.
The logs measurements are affected by and not limited to the tool geometry, tool physics, borehole environments (including well trajectory), and invasions.
Take neutron log readings in a gas bearing zone and in a shale interval for example. Let’s say from our knowledge we know that the actual porosity is around 20 p.u.
In the gas bearing zone, you will notice that the neutron reading will be super low. Neutron can’t see a lot of hydrogen, thus the lower neutron log reading.
In the shale zone, you’ll see higher apparent neutron porosity due to clay bound water effect. In both cases, the apparent neutron values (one from the gas interval and once from shale interval), are wrong.
Find out the real porosity value by combining some other informations like the density log porosity or sonic log porosity.
Use other logs like MDT to supplement your basic logs. (Source: SPE.org)
#4: What you measure is what you get.
Logs cannot measure the reservoir properties directly. Logs measure specific rock properties so we can derive the actual parameters we need.
When we measure porosity, we are actually measuring from electron density, acoustic travel time of the rock, hydrogen index or mean T2 values to come up with porosity values.
Multiple sensors. (Source: aps-tech.com)
We make certain assumptions when we derive the log properties. Be aware of these assumptions and their limitations.
#5: You can measure permeability directly from your log.
Permeability is a dynamic data which relates to fluid flow.
We can infer permeability from various correlations, equations, observations and derivations, but we could not directly measure permeability from well log. Validate our calculated permeability from well log with core lab data and well test results.
Take into account the scales of permeability measurements as well as the values are different.
Logging tools, tool physics and well logs are not perfect. Seek first to understand the measurement physics tools, then you’ll be able to handle the well log data better.
If we don’t have these understandings, it’s worth to to back up and start over.