Want to See What You Can Do By Yourself? Here's Some Tips on How to Get the Basics Right.

Although our business is petrophysical evaluation, training and volume assessments, we enjoy problem solving the most. Hence, we're happy to pass on some advice on log evaluation. Below are outlined the steps you should follow to get started. Most of the big service companies use their own in-house models to do this kind of work, but rarely do these models work as well as these steps - there are too many assumptions made.


Decide which software yiou are going to use. If you have specialised Petrophysical software, then by all means use it. Otherwise, you will either need to acquire it, or use something that you do have. If you have Geological Modelling software, then you should be able to do the calculations there too. It is also possible to use a spreadsheet to do the calculations and format the graphs to look like log displays. This latter option presents some difficulties with scale if you wish to actually print your log evaluations, but will otherwise be fine.


Assemble all the available wireline log data. Have copies of log headers available for information such as mud filtrate resistivities and borehole temperatures.

Note that the neutron log should be reported on a Limestone scale, even in Sandstone reservoirs. It is assumed in the industry that neutrons are reported in Limestone units, so if they are not, it is guaranteed that someone will use the data mistakenly at some time.


Plot the logs all together in your favoured display. I like to use GR/CAL/SP in left hand track, then RHOB/NPHI/DT, followed by RT/RXO and then along hole & true vertical depth subsea. Evaluated curves then are placed on the right of the depth tracks.

Shift the density & neutron logs to line up with the GR/RT logs, if required. Modern logs (from) about 1990 onwards should have been depth-matched properly by the logging contractor, but it's still worth checking.

If you know what environmental corrections have been applied to the logs, you may be able to apply anything extra needed. If you don't know, or are unsure, then don't carry out any environmental corrections since you may make things worse by "doubling up".


Use total porosities for your log evaluations - this step is the single simplest one to make to ensure reliable log interpretation. Effective porosities can be useful for a variety of reasons, but since there is no consistent definition, they are best avoided for initial log evaluation.

The most reliable porosity tool is the density log. The (total) porosities from this tool are those most closely matching core porosities. NMR (Nuclear Magnetic Resonance) tools also give comparable porosities in oil or water-bearing formations. Do NOT use density-neutron porosities through anything other than clean (non-shaley) reservoirs, otherwise your porosities WILL be too high.

The formula for density porosity is:

    phiD = (GD - RHOB)/(GD - RHOF)

where GD is the grain density, RHOB is the density measurement and RHOF is the density of the fluid in the zone of investigation of the density tool. In the absence of core, it's pretty safe to assume Miocene and younger sands have average grain densities around 2.69 g/cc. Older sands are most likely around 2.65 g/cc. If it's limestone, assume 2.71 g/cc, although if it's undergone some diagensis the grain density may be higher - possibly up to 2.85 g/cc.

Somewhat harder to address is the RHOF. If you've drilled your well with oil-based mud, then assume RHOF is 0.86 g/cc as a first pass, if you don't know any better. For water-based muds, then you can use the RXO(MSFL or MLL) measurements to estimate invaded zone water saturations (SWXO) and calculate RHOF:


where RHOW is the mud filtrate density at in-situ conditions and RHOHC is the in-situ hydrocarbon density. In order to solve this equation, you will also need to know the invaded zone water saturations (SWXO). The first pass estimate of density porosity can be used for this purpose i.e. phiD = (GD - RHOB)/(GD - RHOMF).

In the absence of density logs, or where they are poor, use the following ranking to determine porosities:


Remember NMR porosities also suffer from a gas effect, so may underestimate total porosities in gas-bearing reservoir.

Porosities from the sonic log are at their most reliable when calibrated to the density porosities over the good hole sections. The formula required to estimate the sonic porosity is:

    phiS = c.(DT - DTma)/DT - d.VSH

where DT is the compressional sonic transit time, DTma is the matrix transit time (54 us/ft for sandstone, 48 us/ft for limestone, 44 us/ft for dolomite), VSH is the shale fraction (next section) and c and d are fitting constants. If no density data is available for calibration, then assume c=0.67 and d = 0.0 initially. the factor d is for shale correction, so increase this factor until the total porosities in the shales approach the expected levels (from density logs in nearby wells).


Following the porosity evaluation, the next stage of petrophysical interpretation is to define the shale fraction. Strictly, it is not necessary to define a shale fraction when using total porosities, however the shale fraction can be useful for net reservoir identification, for permeability modelling and for comparisons with work from Operators using effective porosity systems.

The literature abounds with different models to define shale fraction, mostly from the GR log. In our experience, most problems associated with these models can be avoided by using the density-neutron porosity difference to define the shale fraction. The recommended formula is:

    VshND = (phiN - phiD)/(2.0.phiD)

where phiN is the lithology corrected neutron porosity (approximate by adding 0.04 to limestone porosities is actually sand/shale), phiD is the density porosity (RHOB-RXO if possible) and VshND is the neutron-density based shale fraction. Note that this formula may underestimate the shale fraction in gas-bearing formation and overestimate the shale fraction in poorly compacted formations. In the latter case, the formula below is more useful:

    VshND = (phiN - phiD)/0.33

Where no neutron log is available, there's gas influencing the neutron or for other reasons such as shale correction of neutron porosities, a GR based shale fraction may be required. The most useful form is the simplest:

    VshGR= (GR - GRmin)/( GRmax - GRmin)

where GRmin is the average GR value seen through the "cleanest" reservoir interval and GRmax is the average GR value seen through the "shaliest" non-reservoir interval. Care should be taken to exclude erroneous spikes from this average value. Note that for all shale fraction models, limit the derived values to lie between 0 and 1, since it is nonsensical to have values outside these bounds.


To estimate water saturations, a formation water resistivity is required. These are best determined using the salinity of a water sample and estimated borehole temperatures. If this data is not available, an alternative and quicker way to estimate formation water salinity is to first calculate a formation water resistivity (RW) curve by assuming a salinity and using the equation below:

    RW = (0.0123+3647.5/(SAL^0.955)).(23.8 + 21.5)/(TMPC + 21.5)

where SAL is the formation water salinity expressed as ppm NaCl equivalent and TMPC is the borehole temperature in degrees Celcius.

Next compare RW and the apparent formation water resistivity (RWA) in a depth plot. The salinity can used to estimate RW can then be manually adjusted until the RW and RWA logs are in agreement through the likely water-bearing intervals. Note that hydrocarbon bearing intervals will always show up as having higher RWA values than water-bearing intervals. If there are no clearly water-bearing intervals, then the poorer quality reservoirs which will have the lowest hydrocarbon saturations can be used for the same purpose.


Visually, hydrocarbon-bearing intervals are often readily identified on logs by looking for features such as:

- Increasing porosity (decreasing density, increasing sonic transit time) occurs at the same time as increasing resistivity.

- Similar porosity through interval, but resistivity decreases either gradually or over a shaper transition when moving down the log.

- If neutron porosity is significantly less than the density porosity through a good hole section, then a "gas effect" must be present i.e. the fluid seen by the neutron tool includes significant gas.

- Note that if porosity increases and resistivity decreases, then the interval is clearly water-bearing.

The industry uses a number of equations to quantify the volumes of hydrocarbons present in the porosity around boreholes. The two recommended equations are the Archie Equation for clean reservoirs and the Waxman-Smits equation for shaley reservoirs. Note that the so-called Dual Water Model has been shown (elsewhere) to be mathematically equivalent to the Waxman-Smits equation, but the latter (W-S) is recommended since it is easier to use. The often used Indonesia or Simandoux equations are not recommended under any circumstances. These equations are highly non-linear and may give unreliable results.

The most commonly used water saturation equation is that created by Gus Archie in 1944. This equation is best used in clean (non-shaley) reservoirs. The so-called "Archie" equation is most readily expressed in the form below:

    SWA = (a.RW.phi^(-m)/RT)^(1/n)

where a is the so-called Archie constant (assume to have a value of 1.0), RW is the formation water resistivity expressed in ohm.m, phi is the total porosity expressed as a fraction of bulk volume, RT is the true formation resistivity in ohm.m, m is the cementation exponent, n is the saturation exponent and SWA is the estimated water saturation expressed as a fraction of pore volume. Typical values for the saturation exponent (n) are around 1.9 for sands and 2.0-2.2 for limestones.

Note that wherever possible, the invaded zone saturations should also be estimated since this data can provide significant insight into what is happening in the reservoir e.g. whether or not hydrocarbons are mobile? To make these calculations, just change RXO for RT and RMF (mud filtrate resistivity) for RW.


Unfortunately, the oil and gas industry have no universal definition of net reservoir. The Industry defaults are permeability cutoffs at 0.1 mD for gas and 1 mD for oil. But these cutoffs are not recommended as they stand, since the definition should be appropriate for the reservoir fluid and recovery mechanism in each Field. For example, gas under depletion will have a contribution from all gas present, even that in low permeabilities, while oil in a water drive system will leave bypassed oil behind in the low permeability reservoir.

As a first pass, try assuming everything with a shale fraction (VSH) greater than 0.7 is non-reservoir.

Note that "pay" has no universal definition either. It is recommended to assume that "pay" refers to intervals that would flow hydrocarbons if tested. To that end, assume VSH<0.7 and SWA<0.6. gas and 1 mD for oil. But these cutoffs are not recommended as they stand, since the definition should be appropriate for the reservoir fluid and recovery mechanism in each Field. For example, gas under depletion will have a contribution from all gas present, even that in low permeabilities, while oil in a water drive system will leave bypassed oil behind in the low permeability reservoir.


Most people want to see average reservoir properties (net, porosity and water saturation at least) over the intervals of interest. So use the softwarte that you have, or a spreadsheet to generate this summary data.