Page 82 - Standard Handbook Petroleum Natural Gas Engineering VOLUME2

70 Reservoir Engineering

water. As shown in the figure, a threshold pressure must be overcome before
any oil enters the core. The initial (or primary) drainage curve represents the
displacement of the wetting phase from 100% saturation to a condition where
further increase in capillary pressure causes little or no change in water
saturation. This condition is commonly termed the irreducible saturation, S,.
The imbibition curve reflects the displacement of the nonwetting phase (oil)
from the irreducible water saturation to the residual oil saturation. Secondary
drainage is the displacement of the wetting phase from the residual oil saturation
to the irreducible water saturation. A hysteresis is always noted between the
drainage and imbibition curves. Curves can be obtained within the hysteresis
loop by reversing the direction of pressure change at some intermediate point
along either the imbibition or secondary drainage curve. The nonuniform cross-
section of the pores is the basic cause of the hysteresis in capillary pressure
observed in porous media. Therefore, capillary pressure depends on pore
geometry, interfacial tension between the fluids, wettability of the system (which
will be discussed later in this chapter), and the saturation history in the medium.
Leverett [ 1001 introduced a reduced capillary pressure function (subsequently
termed the Leverett J function by Rose and Bruce [127]) that was suggested for
correlating capillary pressure data:

(5-76)

where J (Sw) = the correlating group consisting of the terms of Equation 5-75
k = the permeability
= porosity of the sample
The J function was originally proposed as means of converting all capillary
pressure data for clean sand to a universal curve. A series of capillary pressure
curves are shown as a function of permeability in Figure 5-47 [20]. An example
of the J function curve generated from these data is shown in Figure 5-48 [20].
While the J function sometimes correlates capillary pressure data from a specific
lithology within the same formation, significant variations can be noted for
different formations.
Common laboratory methods of measuring capillary pressure include [ 191:
mercury injection, porous diaphragm or plate (restored state), centrifuge method,
and steady-state flow in a dynamic method. .While the restored state test is
generally considered the most accurate, mercury injection is routinely used.
However, it is necessary to correct the mercury injection data for wetting
conditions before comparison to results from the restored state test.
A very valuable use of capillary pressure data is to indicate pore size distri-
bution. Since the interfacial tension and contact angle remain constant during
a test such as already described, pore sizes can be obtained from capillary
pressures. For rocks with more uniform pore sizes, capillary pressure curves will
be close to horizontal. The slope of the capillary pressure curve will generally
increase with broader poresize distribution.
If laboratory capillary pressure data are corrected to reservoir conditions, the
results can be used for determining fluid saturations. Figure 5-49 shows a close
agreement in water saturations obtained from capillary pressure and electric
logs [48].
Capillary pressure data are helpful in providing a qualitative assessment of
the transition zones in the reservoir. A transition zone is defined a8 the vertical