Page 542 - Petrophysics

PETROPHYSICAL PROPERTIES 509

formations. The presence of fractures near the wellbore and their density
are factors that must be taken into account when estimating S,,,.
Combining Equations 8.10a and 8.11 and solving explicitly for the
porosity partitioning coefficient, v, yields:

(8.13)

If the total porosity $, is known from logs or cores, the matrix porosity
and fracture porosity may be estimated from:

Om = cpt (1 - v) (8.14)

Of = Ot - Om (8.15)
The porosity partitioning coefficient v, commonly used by the
petrophysicist, is physically equivalent to the storage capacity ratio, o,
which is more commonly used in well test analysis. But, because of the
difference in scale, it is unlikely that the two values would ever be equal
for the same formation. Note that even equations 8.13 and 8.9 will yield
slightly different values of v, because one is obtained from well logs
(Equation 8.9) while the other is measured in cores.
Logs seem to yield slightly lower values of v, because the measurements
are done under in-situ conditions.

EXAMPLE

A newly drilled well in a naturally fractured reservoir was logged.
The average total porosity of the system was estimated from cores as
13%. Other known characteristics are:

A = 3,00Oacres, h = 52ft, s, = 0.21,
Bo = 1.25 bbl/STB R, = 0.19 ohm-m, Rt = 95ohm-m,
Rd = 0.17 ohm-m, m = 1.40.

(1) Estimate the porosity partitioning coefficient.
(2) Estimate the matrix porosity and fracture porosity.
(3) Calculate the total oil in place, STB.

SOLUTION

(1) In order to calculate the porosity partitioning coefficient v from
Equation 8.13, we need to determine first the resistivity in the