Page 539 - Petrophysics

506 PETROPHYSICS: RESERVOIR ROCK PROPERTIES

SOLUTION

Using Equation 4.5 the formation resistivity factor is:

Ro 1.77
F=-=-- - 50.57
Rw 0.035

The tortuosity is calculated from Eq. 8.8b:
z = F ((1 - @?>$:"' + @?)

= (50.57) ((1 - 0.0371.5)(0.152) + 0.0371.5) = 1.5

POROSITY PARTITIONING COEFFICIENT

Reservoirs with a fracture-matrix porosity system-such as found in
many carbonate rocks due to the existence of vugs, fractures, fissures,
and joints-differ considerably from reservoirs having only one porosity
type. The secondary porosity strongly influences the movement of fluids,
whereas the primary pores of the matrix, where most of the reservoir
fluid is commonly stored (more than 96% in Type-3 naturally fractured
reservoirs), are poorly interconnected. The Spraberry field of West Texas
is an example of a naturally fractured sandstone oil reservoir, which
is composed of alternate layers of sands, shales, and limestones. The
Altamont trend oilfield in Utah is another naturally fractured sandstone
reservoir with a porosity of 3% to 7% and an average matrix permeability
less than 0.01 mD [13].
Laboratory-measured values of permeability for naturally fractured
cores can be significantly different from the in-situ values determined
by well pressure analysis. The difference is attributed to the presence of
fractures, fissures, joints and vugs, which are not adequately sampled in
the core analysis. One of the earliest methods used to analyze full-sized
naturally fractured cores was developed by Locke and Bliss [30]. The
method consists of injecting water into a core sample and measuring
the pressure values as a function of the cumulative injected volume of
water (Figure 8.11). The secondary pore space, Vf, because of its high
permeability, will be the first to fill up with water. A sharp increase in
pressure is recorded later, indicating that the matrix porous space, V,,
has to fill up. The total pore volume, Vt = Vf + @fVm, is considered to
be fdled up when a pressure of 1,000 psi is reached in the test. If the
fraction of total pore volume in the secondary porosity is v, then:

vc