Page 538 - Petrophysics

PETROPHYSICAL PROPERTIES 505

is equal to unity. In this case the formation resistivity factor can be
expressed as:

(8.8a)

Laboratory tests indicate that the tortuosity factor, T, and the fracture
porosity exponent, mf, are approximately unity in systems with
open and well connected fractures. In Type-2 and Type-3 naturally
fractured reservoirs, the formation resistivity factor can be more generally
expressed as:

(8.8b)

Where mm is the matrix porosity. If only matrix porosity is present, i.e.
$f = 0, Equation 8.8b simplifies to Equation 4.40 where m = mm and
a = T. On the other hand, if only fracture porosity is present such as
in Type-1, Equation 8.8b simplifies to Equation 8.8a. If only the total
porosity is known, then F can be estimated from:

(8.8~)

The fractures should be considered as being well connected if the
interporosity coefficient, h, which is determined from a pressure
transient test is high, i.e. lo-* or lop5. If the interporosity factor is
low, i.e. h is approximately lows or loT9, the fractures are poorly
interconnected and/or partially mineral-filled. In this case mf and T
maybe as high as 1.75 and 1.5, respectively. For 3 h 2 lo-',
1.75 > mf > 1 and 1.5 3 T 3 1.

EXAMPLE

The following characteristics of a Type-2 naturally fractured formation
were obtained from core analysis:

$f = 0.037 $m = 0.15 mf = 1.5 mm = 2
R, = 1.77 ohm-m Rw = 0.035 ohm-m

Estimate the tortuosity factor for this formation.