1.
n. [Formation Evaluation]
The exponent,
m, in the relation of
formation factor (F) to
porosity (
phi). For a single sample, F is related to
phi using the Archie equation F = 1 /
phi^{m}, with
m being the only coefficient needed. In this case,
m has been related to many physical parameters, but above all to the tortuosity of the
pore space. In theory, it can range from 1 for a
bundle of tubes to infinity for porosity that is completely unconnected. For a simple packing of equal spheres,
m = 1.5. With a more tortuous pore space or more isolated pores,
m increases, while with fractures or conductive solids,
m decreases. As a general average for typical
reservoir rocks,
m is often taken as 2.
For a group of
rock samples, it is common practice to find a relationship between F and
phi that uses two coefficients (F =
a /
phi^{m}). In this case
m, like
a, becomes an
empirical constant of best fit between F and
phi, and may take a wide range of values. In complex formations, such as
shaly sands or carbonates with multiple pore types, a constant
m does not give good results. One solution is to vary
m, with the variability related to parameters such as porosity, shaliness, or rock texture, or else determined directly from logs in zones where the water
saturation is known or can be computed from a nonresistivity measurement such as
electromagnetic propagation.
In shaly sands, the preferred solution is to use a
saturation equation, such as Waxman-Smits, dual water, SGS or CRMM, in which
m is defined as the intrinsic m, determined from the intrinsic
formation factor at high salinities or after correction for the effect of
shale. In carbonates with multiple pore types, such as fractures, vugs, interparticle porosity and
microporosity, one solution is to use equations with different porosity exponents for each pore type. The volume of each pore type must then be determined from logs or
borehole images.