Page 250 - Geology and Geochemistry of Oil and Gas

MODELS OF STATIC GEOLOGIC SYSTEMS 217
The Balakhany Formation of the Productive Series of the South Caspian Basin
was used as an example to show how the anisotropy was estimated. For this for-
mation, 356 measurements of permeability were made with corrections for the for-
mation pressure and temperature, because these rocks lie at a considerable depth
(3500–4500 m). The permeability data were processed in order to determine
the anisotropy coefficients, average permeability, and variation of anisotropy
(Table 11.2).
The section of Productive Series of the South Caspian Basin is of rhythmic (cyclic)
nature: at the bottom, the rhythmic (cyclic) strata consist of thick and continuous
reservoir rocks with shale interbeds, whereas the reservoirs at the top are thin-
bedded. Formations can be grouped on the basis of similarity in the thicknesses of
individual layers. For example, one can combine formations at the base of the
rhythmic strata with thickness ranging from 3 to 20 m (average ¼ 8 m) into a single
group. The top units, which are made up of the thin layers (thickness ranges from 2
to 12 m; average ¼ 5 m), form another group. The anisotropy coefficients of thick
beds are high (l ¼ 4:4), whereas l ¼ 3:0 for thin beds. The mean anisotropy coef-
ficient for the entire Balakhany Formation is 3.9.
The value of l allows one to determine the sequence of thicknesses of beds from
thinner to thicker: the sequence can be based on anisotropy data obtained from logs
and cores. For example, Von Engelhardt (1964, in: Buryakovsky et al., 2001, p. 300)
presented laboratory results for the Dogger sandstones of Valanginian and Liassic
age (from the oil and gas fields in the Northern Germany). In all cases, the per-
meability parallel to the bedding was higher than the permeability perpendicular to
the bedding. On the average, the k k =k ? ratio was 1.9, which gives a mean anisotropy
coefficient of 1.38. Mirchink’s (1948, in: Buryakovsky et al., 2001, p. 300) data for
sandstones in various USA oil fields show that the anisotropy coefficient increases
from 1.3 to 1.86 with a mean of 1.71, as the permeability increases from 3 to 770 mD.
Generally, the median permeability of the clastic rocks varies from 10 to 100 mD,
whereas the anisotropy coefficient fluctuates around 1.5. Thus, there is a numerical
sequence in the anisotropy coefficients, which ranges from microanisotropy (from
core data) with the median value of l ¼ 1:5 to macroanisotropy (from E-log data)
with the median value of l ¼ 3 for thin-bedded formations and l ¼ 4:4 for thick-
bedded ones.

11.2.1.3. Petrophysical relationships
Experimental and field studies of reservoir-rock properties at reservoir conditions
are of great importance. Successful development of oil and gas fields depends largely
on the knowledge of such reservoir-rock properties as porosity and permeability.
The permeability is one of the most important parameters describing a porous me-
dium, but permeability measurement has some restrictions and requires a rock
sample of suitable size and certain geometric shape. The requirement for measuring
the other petrophysical properties of rocks, such as porosity, grain-size distribution,
pore-size distribution, and specific surface areas, are less restricted. Correlation
between the permeability and other easier-to-measure quantities, therefore, have
been studied extensively both experimentally and theoretically.