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Reservoir Description 161

Figure 6.48 GR log interpretation.

environments. Reservoirs with a low or unpredictable N/G ratios often require large
numbers of wells to access reserves and are therefore more expensive to develop.

6.4.4. Porosity

Reservoir porosity can be measured directly from core samples or indirectly using
logs. However, as core coverage is rarely complete, logging is the most common
method employed, and the results are compared against measured core porosities
where core material is available.
The formation density log is the main tool for measuring porosity. It measures the
bulk density of a small volume of formation in front of the logging tool, which is a
mixture of minerals and fluids. Provided the rock matrix and fluid densities are
known, the relative proportion of rock and fluid (and hence porosity) can be
determined (Figure 6.49).
The density tool is constructed so that medium-energy GRs are directed from a
radioactive source into the formation. These GRs interact with the formation by a
process known as Compton scattering, in which GRs lose energy each time they
collide with an electron. The number of GRs reaching detectors in the tool is
inversely proportional to the number of electrons (or the electron density) in the
formation, which is related to the formation bulk density. A low GR count implies
a high electron (and bulk) density and therefore a low porosity.
The bulk density measured by the logging tool is the weighted average of the
rock matrix and fluid densities, so that
r ¼ r f þ r ð1 fÞ
ma
f
b