Environmental Engineering Reference
In-Depth Information
wetting phase (i.e., formation water) and to oil as the non-wetting phase.
Furthermore, when an electric field is applied to the porous medium,
because of the random distribution of the fluids within the pores, it is
an accepted assumption that the electric field will be identical in the two
phases (
E
w o
) (Gladkov, 2003). In the following sections, we discuss
the contribution of each of the four relative permeability coefficients to
the flow and describe the experimental and analytical approaches used to
evaluate them.
∇∇
=
5.8.4.1
Diagonal relative permeability coefficient for
water phase
[
k
er ww
The first diagonal relative permeability coefficient (
k
er w
,
) was evaluated
experimentally for four sand stone rock core specimens as a function of
their water saturation. Table 5.2 presents the properties of the rock cores
and the flooding fluids used in the experiment. The cores were all 36 mm
in diameter and 82 mm in length. Initially, each core was dried and air
vacuumed. Then, an electrolyte solution (simulating the formation water
of similar salinity) and oil were injected simultaneously at constant injec-
tion rate using a high pressure injection pump (Quizix Pump). The core
saturation was determined once a steady state flow condition was reached.
]
,
Table 5.2
Properties of the sandstone cores and fluids used for relative EO per-
meability coefficients
Material
Properties
Sandstone core A
Porosity:14.5%, permeability: 3.6 mD , bulk wet
density: 2.49 g/cm
3
Sandstone core B
Porosity:14.4%, permeability: 8.3 mD, bulk wet density:
2.43 g/cm
3
Sandstone core C
Porosity:12.8% , permeability: 2.3 mD, bulk wet
density: 2.47 g/cm
3
Sandstone core D
Porosity:11.5%, permeability: 0.5 mD bulk wet density:
2.45 g/cm
3
Crude Oil
API 25; dynamic viscosity = 0.0387 pas-sec; Specific
gravity =0.79 at 20°C
Electrolyte solution
NaCl; Salinity= 30,000 ppm; Electrical conductivity =
45,000 μS
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