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I'm new around here and have a question. I have well log data (in LAS format) and need to get porosity (in %). In the file there is the following information: sonic (DT in us/ft), density (RHOB in gr/cc), neutron (NPHI in %). As far I know, porosity can be calculated from each of these parameters, being generally: 1) porosity-derived density -> too high, 2) porosity-derived neutron -> too low, 3) porosity-derived sonic -> not too affected by gas. So my question is if someone has a formula to calculate porosity from these three parameters. The porosity I'm looking is like the one determined by IODP (or ODP) (eg. http://www-odp.tamu.edu). I now it's needed probably a lot of assumptions, no problem about using assumptions, the well is composed mainly by shale, shaley sand and sandstone, and there were "normal" amount of biogenic gas (no overpressure).

For instance, Steckler and Watts (1978) show a figure (figure 4) about this using only sonic and density logs, here is the paper: http://www.earth.ox.ac.uk/~tony/watts/d ... atts78.pdf, so I'm looking for something like this.

Any help is much appreciated, thanks.

My personal preference is to use the desnity log and neutron porosity log in combination to get an apparent porosity corrected for the presence of gas, if any. I would not use the sonic porosity, especially in clastics (shaly sand reservoirs) as the formation may not be well compacted and the presence of shales will also affect the sonic porosity.
Here is the way to get an apparent porosity using the density and neutron porosity log:

Porosity from density log DPHISS = (Rhog - Rhob)/(Rhog - Rhof)
Where, Rhog = 2.65 gm/cc for quartz
Rhob = density log data in gm/cc
Rhof = 1.0 gm/cc assuming the invaded zone is fully flushed with filtrate from water base mud
This porosity from density log will be in decimal fraction. Therefore, you need to multiply it by 100 to get the density porosity in %.

Neutron porosity in sandstone units NPHISS = Neutrom porosity from log + 4%

This is an approximate conversion of the neutron porosity log (which is usually recorded in limestone units). If you want an exact conversion to sandstone units, you can use an appropriate log interpretation chartbook from the respective well logging contractor (i.e. Schlumberger, Baker Hughes or Halliburton).

APHI (apparent porosity) = (2 x DPHISS + NPHISS)/3

This approximate porosity works very well even in gas bearing reservoirs, since it is a weighted average of density porosity and neutron porosity, which are affected by gas in opposite ways. In a gas bearing interval, the density porosity will be too high and the neutron porosity will be too low. Therefore, by taking a weighted average, the gas effect is minimized.

There are also other methods of taking weighted average of the density and neutron porosities.

APHI = SQROOT((DPHISS^2 + NPHISS^2)/2)
This is the Root Mean Square value of the two porosity logs

thanks a lot kokokyi, I'll try your suggestions and will post the result, especially how different is the result from the porosity (%) calculated in near ODP boreholes. About the explanation, is there a very common and known bibliographic reference among petrophysicists to read about it? some book perhaps? thanks again for the support

There are many petrophysics textbooks out there. Two good ones that you can refer to are:

1) Crain's Petrophysical Handbook by Ross Crain
2) Log Interpretation Principles/Applications by Schlumberger

cool, thanks again

Dear friends,

If you determine porosity for the entire log section, without creating zones, what formula we shall use to adjust the density and neutron porosities in front of shale strata?

Shale Porosity = Apparent Porosity * ( 1 - Vshale), with Apparent Porosity calculated as you mentioned above.

This formula will be available also available as "Effective Porosity" in front of sandstone layers?

And last question, do you know any free software at least for basic log analysis?

Best Regards.

The equation for the Apparent Porosity that I mentioned computes "Total Porosity" of the whole interpreted interval. Normally, shales will have 10% to 15% Total Porosity depending on depth (compaction).
In order to derive an Effective Porosity, you need to remove the portion of the shale porosity from the Total Porosity computed, depending on the shale volume present in the sands.
The equation that you mentioned is one method to obtain Effective Porosity from Total Porosity.