Page 48 - Geology and Geochemistry of Oil and Gas

RESERVOIR ROCKS 25
The fluid flow through the reservoir rocks is also affected by the type of clayey
cement distribution in the pore space. On assuming uniform distribution of cement,
the finer are the rock grains (and the poorer is their sorting), the greater is the effect
of the clay, i.e., the more complex is the structure of pore space, the greater is the
effect of the clay. Studies of thin sections of the reservoir rocks with different dis-
tribution of cement showed that the allothigenic minerals do not cover the clastic
grains uniformly. Thus, they form peculiar swollen coagulants on the salient parts of
rock-forming minerals and convert initially large pores into small, dead-end ones.
When the clay cement is uniformly distributed, the number of dead-end pores is very
high and the intercommunicating pores become geometrically complex. This ham-
pers the movement of oil through the reservoir. The greater the amount of a clay, the
more complex are pore outlines, and the more constricted is the fluid flow through
the reservoir.
The effective pore diameter in a reservoir with clay cement decreases also due to
sorption of some portion of hydrocarbons on the active centers of clay minerals.
High-molecular-weight hydrocarbons are especially prone to be sorbed.
Correlation between the two major reservoir parameters, porosity and permea-
bility, is a difficult task. Permeability correlates most closely with the size and shape
of pores, whereas porosity does not depend on the pore size. Numerous attempts
have been undertaken to theoretically determine the correlation between the porosity
and permeability. Sometimes, the specific surface area is used. F. I. Kotyakhov (in:
Eremenko and Chilingarian, 1991) proposed the following equation:
6 3
k ¼ 49 10 f =s p (2.3)
2
3
2
where s p is the specific pore surface area (cm /cm ), k the permeability (cm ), and f
the porosity (fractional).
Levorsen (1967), in turn, proposed the following equation:
7
2
3
k ¼ 2 10 f =ð1 f Þs 2 (2.4)
p
Buryakovsky (1985) provided quantitative relationships between permeability and
porosity based on laboratory analyses of cores recovered from the Pliocene Pro-
ductive Series of the onshore and offshore Azerbaijan.
A fuzzy correlation is illustrated by experiments conducted by Kerans et al. (1994)
on outcrop samples of Permian carbonates with leaching pores (Fig. 2.3). A log–log
graph shows some correlation between the porosity and permeability at porosity
below 20%.
Presence of a fracture in the rock drastically increases its permeability and only
slightly affects the porosity (Bagrintseva, 1977; Chilingarian et al., 1992, 1996). The
liquid flow velocity through a fracture is determined by the Boussinesq equation:

w 2
V ¼ Dp (2.5)
2m
where w ¼ the fracture opening, m ¼ the viscosity, and Dp ¼ the pressure drop.
For a laminar gas flow, taking gas compressibility into account, Eq. 2.5 can be
presented in the following form: